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Chapter 46
Thermal Recovery Chieh Chu, Getty Oil Co.*
Introduction Thermal recovery generally refers to processes for recovering oil from underground formations by use of heat. The heat may be supplied externally by injecting a hot fluid such as steam or hot water into the formations, or it may be generated internally by combustion. In combustion, the fuel is supplied by the oil in place and the oxidant is injected into the formations in the form of air or other oxygen-containing fluids. The most commonly used thermal recovery processes are steam injection processes and in-situ combustion.
Two Forms of Steam Injection Processes In principle, any hot fluid can be injected into the formations to supply the heat. The fluids used most extensively are steam or hot water because of the general availability and abundance of water. Hot water injection has been found to be less efficient than steam injection and will not be discussed here. A schematic view of the steam injection process is shown in Fig. 46.1, together with an approximate temperature distribution inside the formation. ’ There are two variations of steam injection processessteam stimulation and steam displacement. Steam Stimulation This method has been known as the huff ‘n’ puff method, since steam is injected intermittently and the reservoir is allowed to produce after each injection. In this process the main driving force for oil displacement is provided by reservoir pressure, gravitational force, rock and fluid expansion, and, possibly, formation compaction. In the steam stimulation process only the part of the reservoir adjacent to the wellbore is affected. After a number of cycles of injection and production, the near-wellbore region in reservoirs having little or no dip becomes so depleted of oil that further injection of steam is futile. In this case, wells must be drilled at very close spacing to obtain a high oil recovery. ‘NowWlihTexacoinc
Steam Displacement This process, usually referred to as steamflood or steamdrive, has a much higher oil recovery than steam stimulation alone. Whereas steam stimulation is a one-well operation, steamflood requires at least two wells, one serving as the injector and the other serving as the producer. The majority of steamflood projects use pattern floods. In many cases, steam stimulation is required at the producers when the oil is too viscous to flow before the heat from the injector arrives. Because of the high oil recovery achievable through steamflooding, many reservoirs that were produced by steam stimulation previously now are being steamflooded.
Three Forms of In-Situ Combustion In-situ combustion usually is referred to as fireflood. There are three forms of in-situ combustion processesdry forward combustion, reverse combustion, and wet combustion. Dry Forward Combustion In the earlier days, this was the most commonly used form of the combustion processes. It is dry because no water is injected along with air. It is forward because combustion starts at the injector and the combustion front moves in the direction of the air flow. Fig. 46.2 gives a schematic view of the dry forward combustion process. ’ The upper part of the figure shows a typical temperature distribution along a cross section leading from the injector at the left to the producer at the right. Two things need to be pointed out. First, the region near the producer is cold, at the original temperature of the reservoir. If the unheated oil is highly viscous, it cannot be pushed forward by the heated oil at its back that has been made mobile by the high temperature of the combustion zone. This phenomenon is called “liquid blocking.” Second, the temperature of the region in the back of the combustion zone is high, indicating a great amount of heat being stored in the region, not used efficiently.
46-2
PETROLEUM
Y
I
ENGINEERING
HANDBOOK
The lower part of Fig. 46.2 shows the fluid saturation distributions inside the formation under the combustion process. One should note the clean sand in the burnedout region. Being able to burn the undesirable fraction of the oil (the heavier portion) is one advantage of the forward combustion process over the reverse combustion process. Reverse Combustion
Fig. 46.1-Steam
injection
CROSS-SECTION
Fig. 46.2-Dry
processes.
OF FORMATION
forward
combustion
Strictly speaking, it should be called dry reverse combustion, because normally only air is injected, no water. A simple example will help to explain how reverse combustion works. In ordinary cigarette smoking, one ignites the tip of the cigarette and inhales. The burning front will travel from the tip of the cigarette toward one’s mouth, along with the air. This is forward combustion. The cigarette also can be burned if one exhales. This way, the burning front still moves from the tip of the cigarette toward one’s mouth, but the air flow is in the opposite direction. This is, then, reverse combustion. Fig. 46.3 shows the various zones inside the formation, with the cold zone near the injector at the left and the hot zone near the producer.3 Since the region around the producer is hot, the problem of liquid blocking mentioned earlier in connection with the dry forward process has been eliminated. In principle, there is no upper limit for oil viscosity for the application of the reverse combustion process. However, this process is not as efficient as the dry forward combustion because a desirable fraction of the oil (the lighter portion) is burned and an undesirable fraction of the oil (the heavier portion) remains in the region behind the combustion front. Besides, spontaneous ignition could occur at the injector.4 If this happens, the oxygen will be used up near the injector and will not support combustion near the producer. The process then reverts to forward combustion. No reverse combustion project has ever reached commercial status. Nevertheless, this process should not be written off because, in spite of the difficulties facing this process, it could offer some hope of recovering extremely viscous oil or tar. Wet Combustion
couwslIoN ZONE lnAValNa lHlS DIRECTION
Fig. 46.3-Reverse
combustion.
The term “wet combustion” actually refers to wet forward combustion. This process was developed to use the heat contained behind the combustion zone. In this process, water is injected either alternately or simultaneously with air. Because of its high heat capacity and latent heat of vaporization, water is capable of moving the heat behind the combustion front forward, and helping to displace the oil in front of the combustion zone. Fig. 46.4 shows the temperature distributions of the wet combustion process as the water/air ratio (WAR) increases.5 The curve for WAR=0 refers to dry combustion. With an increase in WAR, the high-temperature zone behind the combustion zone shortens (WAR=moderate). With a further increase in WAR, the combustion will be partially quenched as shown by the curve for WAR=large. The wet combustion process also is known as the COFCAW process, which is an acronym for “combination of forward combustion and waterflood.” This process also can be construed as steamflood with in-situ steam
THERMAL
46-3
RECOVERY
generation. It should be noted that this method cannot prevent liquid blocking and its application is limited by oil viscosity, as is the dry forward combustion.
WAR = LARGE
Historical Development The following lists chronologically some of the major events that occurred in the development of the thermal recovery methods. 1931 1949
A steamflood was conducted in Woodson, TX.6 A dry forward combustion pro’ect was started in Delaware-Childers field, OK. J 1952 A dry forward combustion project was conducted in southern Oklahoma. 8 1955 A reverse combustion project was initiated in Bellamy, M0.9 1958 The steam stimulation process was accidentally discovered in Mene Grande Tar Sands, Venezuela. ‘O 1960 Steam stimulation was started in Yorba Linda, CA. ” 1962 Wet combustion phase of a fireflood project was started in Schoonebeek, The Netherlands. I2
Current Status U.S. Oil Production by Enhanced Recovery Methods The significance of the thermal recovery processes can be seen from the April 1982 survey of the Oil and Gas J. I3 As shown in Table 46.1, of the daily U.S. oil production with EOR processes, 76.9% comes from steam injection and 2.7% comes from in-situ combustion, totalling 79.6% obtained by thermal recovery processes. The combustion process, although dwarfed by the steam injection processes, accounts for more than double the production of all the chemical floods combined, which amounts to 1.2 % . Geographical Distribution of Thermal Recovery Projects Table 46.2, based largely on the 1982 survey, I3 shows the geographical distribution of the steam injection projects in the world. Of the daily oil production from steam injection processes, 71.7% comes from the U.S., 15.4%
TABLE
46.1-U.S.
EOR PRODUCTION
(1982)
BID Steam Combustion Total thermal Micellarlpolymer Polymer Caustic Other chemicals Total chemicals CO, miscible Other gases Total Grand
Total
-
288,396 10,228 298,624
DISTANCE
Fig. 46.4-Wet
---)
combustion.
from Indonesia, 7.0% from Venezuela, and 3.0% from Canada. In the U.S., California accounts for nearly all the production, with small percentages coming from Louisiana, Arkansas, Texas, Oklahoma, and Wyoming. The daily oil production by in-situ combustion is shown in Table 46.3. Here, the U.S. accounts for 40.0% of the total production, followed by Romania (26.0%), Canada (22.1%), and Venezuela (10.8%). Of the U.S. production, nearly one-half comes from California, one-third from Louisiana, with the rest from Mississippi, Texas, and Illinois. Major Thermal Recovery Projects The major thermal recovery projects, again based largely on the 1982 survey, t3 are listed in Table 46.4. Reservoirs Amenable to Thermal Recovery Table 46.5 shows the ranges of reservoir properties in which the technical feasibility of steamflood and tireflood has been proven. I4 Potential for Incremental Recovery According to Johnson et al., l5 vast energy resources exist in the tar sands in Venezuela and Colombia (1,000 to 1,800 billion bbl), Canada (900 billion bbl) , and the U. S . (30 billion bbl). These tar sands should be a major target
TABLE
46.2-011.
PRODUCTION PROCESSES
BY STEAM (1982)
INJECTION
%
~
76.9 2.7 79.6
902 2,587 580 340
0.2 0.7 0.2 0.1
4,409
1.2
21,953 49,962
5.9 13.3
71,915
19.2
374,948
100.0
B/D U.S. Arkansas California Louisiana Oklahoma Texas Wyoming Canada (Alberta) Brazil Trinidad Venezuela Congo France Germany Indonesia Total
%
288,396
71.7
284,093 1,600 617 711 575 12,180 1,920 3,450 28,030 2,500 360 3,264 621000
3.0 0.5 0.9 7.0 0.6 0.1 0.8 15.4
402,100
100.0
PETROLEUM
46-4
TABLE
46.3-PRODUCTION
BY IN-SITU BID
-
Total
46.4-MAJOR
40.0
22.1
~
RECOVERY
1.1 10.8 26.0
PROJECTS Enhanced Oil Production
Field, Steamflood
Steam
Fireflood
Thermal
stimulation
Location
(Operator)
VW 83,000 40,000 22,800 22,500
Kern River, CA (Getty) Duri, Indonesia (Caltex) Mount Poso. CA (Shell) San Ardo. CA (Texaco) Tia Juana Este, Venezuela (Maraven)
15,000
Lagunillas, Venezuela (Maraven) Duri, Indonesia (Caltex) Cold Lake, Alberta (Esso) Suplacu de Barcau, Romania (IFPIIPCCG) Battrum No. 1, Saskatchewan (Mobil) Bellevue, LA (Getty)
40,850 22,000 10,000
6.552 2,900 2,723
Jobo. Venezuela (Lagoven)
HANDBOOK
for development of thermal recovery methods, since the results will be most rewarding if a percentage of these resources can be tapped economically. Based on an assumed oil price of $22.OiVbbl, Lewin and Assocs. Inc. I6 estimated that the ultimate recovery in the U.S. by thermal recovery methods will amount to 5.6 to 7.9 billion bbl. This includes 4.0 to 6.0 billion bbl by steamfloods and 1.6 to 1.9 billion bbl by firefloods. Production Mechanisms
100.0
25,760
THERMAL
(1962)
%
-
10,228 4,873 179 2 2,940 1,300 934 5,690 150 5,540 284 2,799 - 6,699
U.S. California Illinois Kansas Louisiana Mississippi Texas Canada Alberta Saskatchewan Brazil Venezuela Romania
TABLE
COMBUSTION
ENGINEERING
13,000
The production mechanisms in steam in’ection processes have been identified by Willman et al. 14 as (1) hot waterflood, including viscosity reduction and swelling, (2) gas drive, (3) steam distillation, and (4) solvent extraction effect. The relative importance of these mechanisms on light and heavy oil, represented by 37.0 and 12.2 “API, respectively, is given in Table 46.6. In &floods, the above mechanisms are also important. In addition, the breaking up of heavy oil fractions into light oil fractions through cracking should have at least two effects: increase in volume and more drastic reduction in viscosity. The gas drive effect also should be increased because of the large amount of air injected and combustion gas produced.
Theoretical Considerations Surface Line and Wellbore Heat Losses In current field practice, downbole steam generators are still in the developmental stage. Surface steam generators are being used in almost all of the steam injection projects. Steam from a generator normally is sent to the injector wellhead through a surface line. Some heat will be lost to the surrounding atmosphere by convection and radiation. As steam travels from the wellhead through the wellbore to the sandface at the pay zone, heat will be lost to the overburden, mainly by conduction. The method of calculating surface line and wellbore heat losses is discussed below.
Surface Line Heat Losses TABLE
46.5-RESERVOIRS AMENABLE AND FIREFLOOD
TO STEAMFLOOD
The steam lines in most of the steam injection projects are insulated. The heat loss from such a line, Btuihr, is: Qr,=2ari,U,;(T,
Steamflood Depth, ft Nei pay, ft Dip, degrees Porositv. % Permeability, md 011 oravitv, OAPI 011 iiscosity at initial temperature, cp Oil saturation at start, % OOIP at start, bbl/acre-ft
-T,,)AL,
(1)
Fireflood
160 to 5,000 10to1,050 0 to 70 12to39 70 to 10,000 -21044
180 to 11,500 4 to 150 0 to 45 16to39 40 to 10,000 9.5 to 40
4 to 106 15to85 370 to 2,230
0.8 to lo6 30 to 94 430 to 2,550
where = outside radius of the insulation surface, ft, r, = steam temperature, “F, 7’,, = atmospheric temperature, “F, and ti = pipe length, ft. ‘in
In the above, CT,.is the overall heat transfer coefficient (based on inside radius of the pipe or tubing), Btu/hr-ft“F, and can be calculated as follows. -1 Uti =
1 +- h+l
) ....
.......
I where rro is the outside radius of pipe, ft, and khin is the thermal conductivity of insulation material, Bm/hr-sq R-OF.
THERMAL
RECOVERY
46-5
The convection heat transfer coefficient, h, Btuihr-sq ft-“F, can be calculated thus ‘* : h=0.75v,o~6/ril10~4,
. .
. . . , . . . . .
(3)
. .
where v,+ is the wind velocity, miihr. The radiation heat transfer coefficient, I, normally can be neglected. If the pipe is bare, that is, uninsulated, then J-,~=rin and
where 7” is the temperature of the formation. Suppose one starts with the temperature of the steam at a depth D r , and desires to calculate the temperature at depth Dl with the length of the depth interval AD= 02 -D 1. Since the formation temperature at D is g GD , + T,Y,, Ramey ‘s equation for the gas case I9 becomes T(D2,r)=gcDz+T,,-gcA-AB
+[T(D,,t)-gcD, U,i=h.
.....
.
..... .... . .
-T,,+gGA+AB]e-hDJA.
(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8)
If the steam is superheated, T, will vary along the line as heat is being lost to the atmosphere. When the pipe is long, it needs to be broken up into segments and the heat loss calculated segment by segment. In each segment,
A is defined as
A= w~C~[khf+rtiUdit)l 2sr,i Urikhf
Ts* =T,$, -Qr,lwsc,s,
.. ...
..
..
........
. . . . (9)
. (5) and
where
1 B=- 778c,,
steam temperatures at the beginning and the end of the segment, “F, QrI = heat loss along the segment, Btulhr, w,~ = mass rate of steam, lbm/hr, and C,, = heat capacity of steam, Btu/lbm-“F.
T.vl ,Ts2
=
If the steam is saturated, the heat loss will cause reduction in steam quality. I,2 =f;, -Qr,lwsLs,
.......
. . . . . .(6)
where f,i and fs2 equal the steam quality at the beginning and the end of the pipe segment, fraction, and L, is the latent heat of steam, Btu/lbm. Wellbore Heat Losses In most of the steam injection projects, saturated steam at a certain quality is injected into the formation. Here, we assume a more general case in which the steam first enters the wellbore as superheated steam, becomes saturated with a gradually diminishing quality, and is further cooled after its complete condensation into hot water. Superheated Steam. Assume that when the depth D is 0, the temperature of the steam is T, and varies with time. Also assume that a linear geothermal gradient exists so that Tf=gGD+
T,,,,,
.
. .
TABLE
...
46.6--MECHANISMS
(7)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .(lO)
where khf = thermal conductivity of the formation, Btu/D-ft-“F, inside radius of the tubing, ft, rtr = ur, = overall heat transfer coefficient for the annular space between inside of the tubing and outside of the casing based on rti, Btu/D-ft-“F, f(r) = transient heat conduction time function for earth, dimensionless, shown in Fig. 46.5, c, = heat capacity of steam, Btu/lbm-“F, gc = geothermal gradient, “F/ft, and T.m = surface temperature, OF. For t>7 days, f(t)=lnp
2Jat r co
-0.29,
...
...
...
..
where 1yis the thermal diffusivity, sq ft/D, and rcO is the outside radius of casing, ft. Saturated Steam. When the steam is saturated, the wellbore heat loss will cause changes in the steam quality whereas the steam temperature, T, , is kept constant. If
CONTRIBUTING
TO STEAM
RECOVERY Recovery (% Initial 011 In Place)
Torpedo
Sandstone Core 37OAPI Crude
Steam
injectron
pressure,
psig
Hot waterflood recovery (Includes viscosity reduction and swelling) Recovery from gas drive Extra recovery from steam distillation Recovery improvements from solventlextractton effects Total recovery by steam
Torpedo
Sandstone Core 12 2OAPI Crude
800 (52OOF)
84 (327OF)
800 (52OOF)
84 (327°F)
71.0 3.0 18.9 4.7 97.6
68.7 3.0 15.6 4.6 91 .9
68.7 3.0 9.3 3.0 84.0
66.0 3.0 4.9 3.7 77.6
46-6
PETROLEUM
TUBING
ENGINEERING
HANDBOOK
CASING
I
T,,
CONSTANT
I
r.r,,
TLYC2RAlUIIL
CYLINonICAL
AT
SOURCE
BOUNOARY
CONOlTlON
I
I
I
TC c
Vi
Fig. 46.5-Transient
‘to
heat conduction
in an infinite radial system.
the steam quality at D isf, =f,(D t J), the steam quality at 02 can be calculated by Satter’s equation*O: A’B’+aD, fsP2J)=fs(D1
A+
Fig. 46.6-Temperature
distribution
in an annular
completion.
where Tfi =temperature of fluid, OF. 4. Calculate Tci at casing inside surface.
+b-T, AD
A’
* 2A’ . . . . . . . . . . . . . . . . . . . . . . . . (12) +-a@@ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (17)
In Eq. 12, A’=
wJs[khf+‘riUhfIf)l 2=rli Utrkhf
.
.........
. . . .(13)
and B’=-.
1 778L,
........ .......... ..... ...
Hot Water. For cooling of the hot water, Ramey’s equation for the liquid phase I9 applies. To advance from depth D, to D2,
Wz,t)=g&
.. .
5. Estimate I for radiation and h for natural convection. 6. Calculate U,,.
.,-(&+ rr;;ez)-l. .... ... . ..(18)
+T.,, -gcA+[W,,t)-gcD,
+T,y,+g~A]e-a’A.
where r-d = radius to cement/formation interface, ft, rc( = inside radius of casing, ft, h-e = thermal conductivity of the cement, Btu/hrft-“F, and khca = thermal conductivity of the casing material, Btu/hr-ft-“F.
. . (15)
Overall Heat Transfer Coeffkient. The temperature distribution in an annular completion is shown in Fig. 46.6. 2’ To evaluate the overall heat transfer coefficient, U,,, based on the outside tubing surface, the following procedure developed by Willhite*’ can be used. I. Select U,, based on outside tubing surface. 2. Calculate AI), as defined previously. 3. Calculate Tc. at cement/formation interface.
With commercial
um =
insulation of thickness Ar,
rlo In? rto + khin
rto
rlo ln’cf
+
r,(h’+l’) . . . . . ..1.....................
-’
rco khce
7 I (19)
where h’ and I’ are based on insulation outside surface. khf
Tcf=
Tfi’) + -Tf rlo ulo At)+-
khf rfO(Ito
. . . . . . . . . . . . . . . . . (16)
Calculations Including Pressure Changes. A more sophisticated calculation procedure proposed by Earlougher** includes the effect of pressure changes inside the wellbore. The wellbore is divided into a sequence
THERMAL
RECOVERY
46-7
of depth intervals. The conditions at the bottom of each interval are calculated, on the basis of the conditions at the top of that interval. The procedure is as follows. 1. Calculate the pressure at the bottom of the interval, ~2.
c.
2
p2=pI+1.687x10-‘2(v,,
-------
‘; 1
-v,2); rti
+6.944x10-3%Q7,. . “II
........ , ;
where “1 = specific volume of the total fluid, cu ft/lbm (condition 1 is top of interval and 2 is bottom), m = length of depth interval, ft, and Ap = frictional pressure drop over interval, psi. The Beggs and Brill correlation23 for two-phase flow can be used to calculate the Ap in the above equation. 2. Calculate the heat loss over the interval.
-0.5(Tf,
.......
+Tp)],
\
“6m.L Ol,rUCT .Io” IwccTIo* WCLL Fig. 46.7-Temperature
distribution
in
Marx-Langenheimmodel.
mations. The heat-carrying fluid is supposed to advance with a sharp front perpendicular to the boundaries of the formation (Fig. 46.7). The heat balance gives: heat injected into the pay zone equals heat loss to the overburden and underlying stratum plus heat contained in the pay zone. The heated area at any time t can be calculated
. . . . . . (21)
A= QriMhao where U, is the overall heat transfer coefficient based on outside casing surface, Btulhr-sq ft-“F. 3. Calculate the steam quality at the bottom of the interval .
where H,.] and H,,.2 are the enthalpy of liquid water at top and bottom of the interval, Btu/lbm, and L,,, and L,,* are the latent heat of vaporization at top and bottom of the interval, Btu/lbm.
4k,,, 2AT
(c’oerfc\l;;;
+2Js-
A
1) ,
(23)
where A = heated area at time t, sq ft,
t = time since injection, hr, Q,; = heat injection rate, Btu/hr, M = volumetric heat capacity of the solid matrix containing oil and water, Btu/cu ft-“F
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (24) More Recent Developments. A new model has been dethat treats wellbore heat losses veloped by Farouq Ali rigorously by using a grid system to represent the surrounding formation. In addition, the pressure calculation accounts for slip and the prevailing flow regime, based on well-accepted correlations.
Analytical Models for Steam Injection For predicting reservoir performance under steam injection processes, the usual practice is to use threedimensional (3D), three-phase numerical simulators. Where the simulators are unavailable or a quick estimate of the performance is needed, one can resort to simple analytical methods. Usually these methods take into account the thermal aspects of the process only, without regard to the fluid flow aspects. Front Displacement
Models
Marx-Langenheim Method. 25 Consider that heat is injected into a pay zone bounded by two neighboring for-
4 = porosity, fraction, Pr&otPw = density of rock grain, oil, water, lbm/cu ft, C,,C,,C, = heat capacity of rock, oil, water, Btu/lbm-“F, S,i,Swi = initial saturation of oil, water, fraction, h = pay thickness, ft, a0 = overburden thermal diffusivity, sq ft/hr, kho = overburden thermal conductivity, Btulhr-ft-“F, AT = Tid-Tf, “F, Ti”j = injection temperature, “F, Tr; = initial formation temperature, “F, TV = dimensionless time
=(;;;l,,) 1. .
(25)
46-8
PETROLEUM
and
ENGINEERING
HANDBOOK
It can easily be shown that
&y=(~)tB? ......... .......
..
e’Derfc&+2
Eh =i
. . (35)
tD
The complementary
error function is:
erfcx=l-erfx=l-1S~e-B2d13, a0
.....
. . . (27)
where /3 is a dummy variable. To evaluate e’Derfc ,&, one can use the following approximation. 26 1 Let y= 1+o.3275911JtD,
Ramey’s Generalization of the Marx-Langenheim Method.” The Marx-Langenheim method can be extended to the case where a series of constant injection rates is maintained over various time periods. If the heat injection rate is (Qri)i over the period O
A=
.........
. . . . . cw i=rl-
I
+ C [(Q,i),-(Q,i);+IlF(rD;) i= I
etDerfc&=0.254829592y--0.284496736y2
3
. . (36)
+1.42143741+1.453152027y4+1.061405429y5. ... ..................
. . . . . . (29)
Assume that all the movable oil is displaced in the heated area. If we assume that all the displaced oil is produced, we can calcuate the cumulative steam/oil ratio (SOR): i,vt
F .A0*=
4.275Ahr$(S,,
-Sic,)
’
(30)
‘. .
where
F(tDi)=e’nferfCJtDi+2
J
% T
. .
.
(37)
and F(~D,)=F(CD~) with i=n. The oil displacement rate at f; depends on the heat injection rate at that time, independent of the previous heat injection rates.
where 1, = steam injection rate, B/D, cold water equivalent, initial oil saturation, and so, = s;, = irreducible oil saturation.
Mandl-Volek’s Refinement of the Marx-Langenheim Method.28 Mandl and Volek observed that the heated area measured in laboratory experiments tends to be lower than that predicted by the Marx-Langenheim method after a certain critical time, t,. For t? t,.,
Differentiation of the expression for A with t gives the rate of expansion of the heated area. The oil displacement rate, q(,d, in B/D, is
A= QriMhao
qod =4.275
Qrrwoi -So,) I
MAT
eroerfcJt,.
.. . .........
. . (31)
..... ....
. . (32)
qod
The thermal (heat) efficiency,
1 1+-
SOR
1 -dE a
tD -tcD
X
From this one can calculate the instantaneous Flo=15.
e’DerfcG+2*-
4kho2AT
Lsfs
+
-3
ezDerfc J- tD
3
C,AT
-
tD -tcD 3J?rtD
>I
. . . .. . . . . . . . . . . . . . .
(38)
Eh, is defined as t, is determined by this equation:
e’cDerfc& where Qh- = heat remaining in the heated zone, Btu, Q;, = total heat injection, Btu, and AhMA T Eh = ~ Q,iT .
..
. . ..
= ,+
1 Lag
. ...
.....
(39)
C,AT
The relationship between t, and t& is again
(34)
. (40)
THERMAL
46-9
RECOVERY
Myhill and Stegemeier” used a slightly different version of the Mandl-Volek model and calculated oil/steam ratio (OSR) for 11 field projects. They found that the actual OSR’s range from 70 to 100% of the calculated ratios.
TABLE
46.7-COMPARISON BETWEEN MARX-LANGENHEIM AND VOGEL METHODS Thermal
0.01
0.1 1 .o 10.0 100.0
Steam Chest Models In contrast to the front displacement models discussed previously, Neuman30 visualized that steam rises to the top and grows both horizontally outward and vertically downward. Doscher and Ghassemi3’ took a view even more drastic than Neuman’s. They theorized that steam rises to the top instantly and the only direction of the steam zone movement is vertically downward. Vogel12 followed the same reasoning and developed the following simple equation for thermal efficiency:
4oc
.
Table 46.7 compares the thermal efficiencies calculatmethod and the Vogel method. This table shows that the Vogel method predicts a thermal efficiency that lies between 80 and 100% of that calculated by the Marx-Langenheim method.
Steam Stimulation Steam stimulation usually is carried out in a number of cycles. Each cycle consists of three stages: steam injection, soaking, and production. The basic concept of this process follows. Without stimulation, the oil production rate is
O.O0708kk,h .
(p, -p ,),
. ...
0.900
0.967
0.804 0.556 0.274 0.103
0.737 0.470 0.219 0.081
0.917 0.845 0.799 0.787
.
...
. (44)
lnT’
rrt,I
rh
lnr,
lnr,
rw
rw
(41)
ed by the Marx-Langenheim
4 oc =
0.930
ln’h
pm
.. .
Ratio Vogel/ML
1
‘?oh
-=
1 . ...
Vogel
where rh equals the radius of the heated region, ft. The ratio between qoh and qoc is
poh
E,, =
Efficiency
Marx-Langenhelm
t,
As the reservoir fluids are produced, energy associated with the fluids are removed from the reservoir. This causes a reduction in rh and a reduction in temperature, which increases PO),. Several methods have been developed for calculating reservoir performance under steam stimulation. One of the methods, which has en’oyed wide acceptance, is the Boberg and Lantz method. d3 This method assumes a constant rh, with a changing T inside the heated zone. The method consists of the following steps. 1. Calculate the size of the heated region using the Marx-Langenheim method. 2. Calculate the average temperature in this region. 3. Calculate the oil production rate, taking into account the reduced oil viscosity in this region. 4. Repeat Steps 1 through 3 for succeeding cycles, by including the residual heat left from preceding cycles. The average temperature of the heated region is calculated by
. . . . (42)
--
T=TR+(Ts-TR)[V,Vz(l-6)-h],
. . . . .(45)
where where 4oc = cold oil production rate, B/D, k= absolute permeability. md, k t-0 = relative permeability to oil, fraction, PO< - cold oil viscosity, cp, PC - static formation pressure at external radius r,, psia, and P\,’ = bottomhole pressure, psia.
After steam injection, the oil inside the heated region, r, < r< rh, will have a lower viscosity, p&. The hot oil production, qoh, is:
TX average temperature of the heated region, r,
O.O0708kk,h (P, -P,),
qoh =
poh lnrh+poc rw
Ink rh
..
(43)
ao(f-ti) tD
=
rh
2
) . . . . . . . . . . . . . . . . . . . . . . .(46)
‘These symbols have no physical connolat~on. They are amply mathemailcal symbols
PETROLEUM
46-10
Ij1~11[ ~lllll ! aott-I,)..S;:t, = v,:t,
1 %(t-4) =- 7
I’
HANDBOOK
the enthalpy of water carried by oil based on a STB of oil, Btu/STB oil. Also, L, is hfK in the steam tables. If P Mz >P s and F,, < Fwclt
F,, =0.0001356 o.j#~v;#~
ENGINEERING
.-!A-
(
PW-PS
>
R,,
.......
. (53)
/
0.1
0.01
to,
1.0
10
DIMENSIONLESS
Fig. 46.8--Solutions
1ac
TIME
bbl liquid water at 60”F/STB oil. If F,, (calculated) > F,, , F,, =F,,,.
for V, and V,, single
sand.
where a,
= overburden thermal diffusivity, sq ft/D, t= time since start of injection for the current cycle, D, ti = time of injection for the current cycle, D, and
.......... . . ..........
(54)
In the above, R, = total produced GOR, scf/STB, F wet = total produced WOR, STBISTB, F,, = steam/oil ratio, STB/STB, PW = producing bottomhole pressure, psia, and ps = saturated vapor pressure of water at ?, psia. The rate of hot oil production can be calculated thus:
f-h = radius of region originally heated, ft. qoh=FJJcAp,
For vz, tD=
ao(t--ti) -
HI
where FJ is the ratio of stimulated productivity indexes, dimensionless, 2
,
. . . . . . . . . . . . . . . . . . . . . . .
. . .
1
FJ= EC1 m~it(.fsLsfHw3s Wh
2WVs
-Hw~)
- TR)N,
= total mass of steam injected, lbm, N, = number of sands, H,vsJ’,v~ = enthalpy, Btu/lbm, of water at steam and reservoir temperatures, “F, and A4 = volumetric heat capacity, Btu/cu ft-“F.
The energy removed with produced fluids, 6, can be calculated thus:
J, =
tc2
0.ooo708kk,h
ln? c, = - rw
. . . . . . . . . . . . . . . . . . . . . (57)
........... .........
. . . . . (58)
lnT’ rw
ink c*= -. rh
._ .... ..... .. .. ...
(50) (51)
and = 5.6146p,[F,,(hf-H~,R)tRtL,],
index,
and
where h, = total thickness of all sands, ft, Q, = heat removal rate at time t, BtulD,
H,
(cold) productivity
pot lnT’ rw If Pe is constant,
(49)
= (5.6146M, +R,C,)@-TR),
. . . . . . . . . . . . . . . . . . . . . (56)
and J, is the unstimulated STBIDlpsi,
m,it
Ho,
,
Poe
) . . . . . . . . . . . . . . (48)
and
Qr, = qoh(Hog+H,),
to unstimulated
(47)
where
H, =
. . . . . . . . . . . . . . . . . . . . . . . . ...(M)
..
lnr, rw Thus Eq. 55 is identical with Eq. 43 in this case. Ifp, is declining,
(52)
where hf is the enthalpy of liquid water at T above 32°F (see steam tables), BtuAbm, H, is the enthalpy of oil and gas based on a STB of oil, BtulSTB oil, and H,. is
. . . . . . . . . . . . . . . . . . . . . . . . . (59)
c, =
lnTk---
4
rw
2re2
&A rw
2
,.....................
(60)
THERMAL
RECOVERY
46-11
@a
CP
Fig. 46.9-Correlation of steam stimulation results. and rh
,nr,-I+-
c2 =
rh
,&1 r,
2
2
2re2
. ... ..........
. . (61) . ,
2
This method of calculating oil production rate is probably the weakest part of the Boberg-Lantz method. 1. It assumes a monotone decline betweenp, andp,. Actually, because the injected steam is at a high pressure, there could be a high pressure ps near rh and the pressure declines toward both p ,+ and pe . 2. Only the change in p0 is accounted for in changing from cold oil productivity to hot oil productivity. Left unaccounted for is the change in k, , which should change with changing S,. Based on the Boberg-Lantz method, a correlation was developed by Boberg and West34 that allows one to estimate incremental OSR with known reservoir properties (Fig. 46.9).
Numerical Simulation The analytical models for thermal recovery processes usually are concerned with the thermal aspects of the processes only. The fluid flow aspects are neglected. To account adequately for the fluid flow inside porous media under a thermal recovery process, numerical simulators will be needed. In these simulators, the reservoir is divided into a number of blocks arranged in one, two, or three dimensions. A detailed study is made of the reservoir by applying fundamental equations for flow in porous media to each one of the blocks. Numerical reservoir simulators are no substitute for field pilots. They have several advantages, however, over field pilots. Field conditions are irreversible. It took millions of years for the field to develop to the present state. Once disturbed, it cannot revert to the original conditions and start over again’. Furthermore, it takes a long time, in terms of months or even years, before the pilot results
can be evaluated. The cost for pilots is, of course, enormous. In comparison, a simulated reservoir can be produced many times, each time starting at the existing state. This can be done within a short period of time, in terms of seconds, once the reservoir model is properly set up. The cost for reservoir simulation is much less than that of a pilot. However, simulated reservoirs may never duplicate field performance. Modem practice is to use reservoir simulation to help design a pilot before launching a large-scale field development. Numerical models and physical models are complementary to each other. As will be detailed later, physical models can be classified into two types: elemental models and partially scaled models. In an elemental model, experiments are conducted with actual reservoir rock and fluids. The results can help explain various fluid flow and heat transfer mechanisms as well as chemical reaction kinetics. In a partially scaled model, reservoir dimensions, fluid properties, and rock properties are scaled for the laboratory model so that the ratios of various forces in the reservoir and the physical model are nearly the same. One can only build partially scaled models because fully scaled models are difficult or impossible to construct. One of the advantages of a numerical model over a physical model is that there is no scaling problem in numerical simulation. However, in many cases, a numerical model needs physical models to validate the formulation or to provide necessary input data for the simulation. Steam Injection Model Numerical simulation models for steam injection processes have been developed by Coats et a1.35 and Coats. 36.37 A steam injection model consists of a number of conservation equations. 1. Mass balance of Hz 0. Both water and steam are included. 2. Mass balances of hydrocarbons. Only one equation will be necessary for nonvolatile oil. For volatile oil, two or more pseudocomponents will be needed to describe the vaporization/condensation phenomenon of the oil and two or more equations will be needed.
PETROLEUM
46-12
3. Energy balance. The energy balance accounts for heat conduction, convection, vaporization/condensation phenomenon, and heat loss from the pay zone to its adjacent formations. The need to include an energy balance in the model sets the thermal recovery processes apart from isothermal processes for oil recovery. In addition to the conservation equations, the model needs to include the following auxiliary equations. 1. If both water and steam coexist, temperature is the saturated steam temperature for a given pressure. An equation is needed to describe this relationship between temperature and pressure. 2. The sum of saturations for the oil, water, and gas phases equals unity. 3. The mol fractions of hydrocarbon components in the liquid and gas phases are related through equilibrium vaporization constants (K-values). 4. The sum of gas-phase mol fractions equals unity. This includes steam and any volatile components of hydrocarbons. 5. The sum of liquid-phase mol fractions for hydrocarbons equals unity.
In-Situ Combustion Model Numerical simulation models have been developed by Crookston et al., 3g Youngren, 39 Coats,40 and Grabowski et a1.4’ The in-situ combustion model is more complicated than the model for steam injection. The conservation equations are as follows. 1. Mass balance of H20. This equation includes the water produced from combustion. 2. Mass balances of hydrocarbons. This includes consumption of certain hydrocarbons through cracking and combustion. It also may include the production of certain other components through cracking. 3. Mass balance of oxygen. This accounts for the consumption of oxygen by combustion. 4. Mass balance of inert gas. If air is used, the conservation of nitrogen should be accounted for. CO2 produced from combustion may be included in the equation for the inert gas or be treated separately. 5. Mass balance of coke. This includes the formation and burning of coke. 6. Energy balance. This equation now includes the heat of reaction for the reactions involved in the in-situ combustion process. These reactions may include lowtemperature oxidation of hydrocarbons, high-temperature oxidation or burning of hydrocarbons, thermal cracking (which produces coke and other products), and combustion of coke. This model also needs a number of auxiliary equations, which include (1) steam/water equilibrium, (2) vaporization equilibrium of hydrocarbons, (3) phase saturation constraints, (4) mol fraction constraints, and (5) chemical stoichiometry. An example is: Oil+a
02 -+b CO2 +c Hz0
This says that one mol of oil reacts with a mols of oxygen to form b mols of CO1 and c mols of HzO. This model also requires a chemical reaction kinetics equation. For each reaction involved in the process, an equation can be written to denote that the reaction rate varies as a function of temperature and concentrations of
ENGINEERING
HANDBOOK
the various reactants. One possible form of the reaction rate equation is the following Arrhenius equation:
w=k’(C,)m(CO,)n
exp
This equation says that the reaction rate, w, is proportional to the concentration of oil, C, , raised to the mth power times the concentration of oxygen, Co, , raised to the nth power. The temperature dependence ofthe reaction rate is in the given exponential form, where E is the activation energy, the energy barrier the reactants need to overcome before being converted to the products, R is the gas constant, and T is the absolute temperature. The proportionality constant, k’, usually is called the preexponential factor. The models developed so far are believed to be adequate as far as the formulation of the process mechanisms is concerned. However, problems abound. 1. Artificial breakdown of the crude oil into two components may not be sufficient to describe faithfully the vaporization/condensation phenomena and the chemical reactions involved in the combustion process. More components mean more equations to be solved and hence higher computer costs. 2. The grid size problem could be severe. A grid size large enough for economic computation could greatly distort the temperature distributions in the simulated reservoir. This would lead to erroneous predictions of the chemical reaction rates and thus of reservoir performance under combustion.
Laboratory Experimentation The thermal numerical models have been used widely for screening thermal prospects, designing field projects, and formulating production strategies. Still, we cannot completely dispense with laboratory experiments for several reasons. First, the numerical models need data that can be measured only experimentally. These data include relative permeabilities, chemical kinetics, adsorption of chemicals on rocks, etc. Second, the numerical models are valid only when all the pertinent mechanisms are accounted for. The currently available models cannot handle adequately situations such as injection of chemicals along with steam, swelling of clays, which reduces the permeability, etc. As previously mentioned, physical models for thermal recovery processes may be classified into two types, namely, elemental models and partially scaled models. The elemental models are used to study the physicochemical changes inside a rock-fluid system under certain sets of operating conditions and are normally zerodimensional (OD) or one-dimensional (1D). The partially scaled models are used to simulate the performance of a reservoir under thermal recovery operations and are normally 3D. Although the intent is to scale every physicochemical change that takes place in the processes, the models usually are partially scaled because of the extreme difficulty in achieving full scaling. Elemental Models Elemental models used for steamfloodin can be exemplified by those used by Willman er al. lg7 In their classic work, they used glass bead packs and natural cores
THERMAL
RECOVERY
of different lengths to study the recovery of oil under hot waterflood and steamflood at different temperatures. The oils used included crudes of different gravities and oil fractions. Fireflood pots and combustion tubes are also elemental models. In another classic work, Alexander et ~1.~~ used fireflood pots (OD) to study fuel laydown and air requirement, as affected by crude oil characteristics, porous medium type, oil saturation, air flux, and timetemperature relationships. The combustion tube (1D) used by Showalter enabled him to delineate the temperature profiles at various times, thus giving the combustion front velocity. More recently, combustion tubes were used to study the use of water along with airMA and the use of oxygen-enriched air in combustion. 47
46-13
TABLE
46.8-COMPARISON VACUUM MODELS
Field Length, ft Permeabtlity, darcies Time Steam rate Pressure 1, psia Steam quality Oil viscosity, cp Temperature, OF Pressure 2. psia Steam quality Oil viscosity, cp Temperature, OF
OF HIGH-PRESSURE FOR STEAMFLOODS
AND
High-Pressure Model
Vacuum Model
458 50 min 144.7 cm3/min 400 0.80 3.0 445 100 0.80 6.3 328
1,527 120 min 263.1 cm3/min 2.70 0.082 23.6 137.5 1.24 0.108 38.2 108.9
229 2 5 yrs 300 BID 400 0.80 3.0 445 100 0.80 6.3 328
Partially ScaledModels Partially scaled models have been used to simulate steamfloods in 5/8of a five-spot pattern, !4 of a five-spot pattern, etc.48-53 Similar attempts have also been made for tirefloods. However, it is certainly much more difficult to include chemical kinetics along with the fluid flow and heat transfer aspects of the combustion process. Partially scaled models for steamfloods fall into two types, namely, high-pressure models and vacuum or lowpressure models. High-Pressure Models. All experimental studies on steamflooding had used high-pressure models until vacuum models came along and offered an alternative approach. The scaling laws of Pujol and Boberg normally were followed in the design. If the dimensions are scaled down by a factor of F in the model, the steam injection rate will be scaled down by the same factor and so will the pressure drop between the injector and the producer. The permeability will be scaled up by a factor of F, and the model time will be scaled down by a factor of F*. Because of the necessity of increasing the permeability in the model to a great extent, reservoir rock material cannot be used. Nevertheless, the experiments will be conducted with the actual crude. Also, the steam pressure and steam quality to be employed in the field will be used in the model Vacuum Models. In a small-scale physical model, the thickness is reduced greatly as compared with that in the field. To obtain the same gravitational effects as in the field, the pressure drop from the injector to the producer also must be reduced greatly. The vaporizationicondensation phenomenon of water and hydrocarbons is governed by the Clausius-Clapeyron equation, which involves d In p, or Q/p. Thus, a decrease in the pressure drop (dp) necessitates a corresponding decrease in the pressure (p) itself. This is the rationale behind the vacuum-model approach developed by the Shell group as reported by Stegemeier et al. ” To see the differences between a high-pressure model and the vacuum model, Table 46.8 has been prepared for using both models to simulate a hypothetical field element with a hypothetical oil. The entries for the high-pressure models were based on the scaling laws of Pujol and Bobergs and the entries for the vacuum model were based on the work of Stegemeier et ~1.~~
The following observations can be made on the highpressure and vacuum models. 1. Neither the high-pressure model nor the vacuum model can accurately simulate the capillary forces and the relative permeability curves of the actual rock/fluid system because, to obtain a very high permeability, actual rock material is not being used. 2. The high-pressure model does not observe the Clausius-Clapeyron equation, whereas the vacuum model follows it to a large extent but not exactly. 3. To use the vacuum model, an oil has to be reconstituted to obtain the required oil viscosity/temperature relationship. This is completely different from the actual crude in many physicochemical aspects, including its vaporization/condensation behavior and chemical kinetics. In contrast, a high-pressure model normally uses actual crudes.
Field Projects Screening Guides In dealing with oil prospects, the first step is to find out whether the field in question can be produced by certain recovery methods. Screening guides are useful for this purpose. Screening guides for steamflood and fireflood processes have been proposed by various authors including Farouq Ali, 57 Geffen, 58 Lewin et al., 59 Iyoho, 6oChu, 61-63and Poettmann. @ These screening guides are listed in Table 46.9. A perusal of the various screening guides listed in Table 46.9 shows that some of the earlier screening guides were quite restrictive in selecting oil prospects. Such a guide tends to minimize the error of the second kind, that is, the riskof excluding some undesirable prospects. In so doing, it tends to increase the error of the first kind, that is, the risk of missing some desirable prospects. Recent changes in the price structure of the crude oil and improved technology helped to widen the range of applicability for the steamflood and fireflood processes. This is reflected in the less restrictive screening guides developed in more recent years. However, in minimizing the error of the first kind (erroneous rejection), the newer guides may possibly increase the error of the second kind (erroneous acceptance). This should be borne in mind when applying these guides to oil prospects.
PETROLEUM
46-l 4
TABLE
46.9--SCREENING
GUIDES
D
4
h
830
< 3,000
0.30
- 1,000
>20
<4,000
Year -__
h
1973 1973
1976 >20 <5000 1979 30 to 400 2.500 to 5.000 >lO 1993 >400
FOR STEAMFLOOD
12 to 15 >lO > 0.50 >I0 >0.50 10 to 20
>o 30 > 1,000 >020
> 0.40
AND
FIREFLOOD
200 to 1,000
ENGINEERING
HANDBOOK
PROJECTS
>20
0.15 to 0.22 20.10
>I00 >50
> 0.065 > 0.065 >0.06
~36
Firefloods Poettmann @ Geffen58 Lewn and Assocs. ”
1964 1973
Chu”
1976 1977
lyohoM
1977 1976
>020 >lO
> 500
>lO
> 500
>250
>20
10 to 45 524
< 1,000
>O.lO >005
for COFCAW only
>0.05 >0.13
confidence llmlts approach > 0 27 regression analysts approach
5 to 50
1976 1962
200 to 4,500
>lO
>500
>3W
>050
<1,ooo
z 0.20
2 0.25 >0.16
<45 <40
no upper limit
>lOO
Performance Indicators Common to Both Steamfloods and Firefloods. Sweep Efficiency. The area1 and vertical sweep of the steam front or burning front has pronounced influence on the economics of the steamflood or fireflood projects. Some reported sweep efficiencies of the steamflood and fireflood projects are given in Table 46.10. 65-81Whereas the volumetric sweep of steamfloods varies from 24 to 99 % , that of firefloods appears to be lower, ranging from 14 to 60%.
46.10-SWEEP EFFICIENCY OF STEAMFLOOD AND FIREFLOOD PROJECTS Field, Locatlon (Operator)
>20
10 to40
20.20
Reservoir Performance
TABLE
>I00
<45 >0.50 r0.50
2022
1976 10 to 120 Ch””
>lW
Areal
Vertical
60.0
50.0
30.0
-
-
80.0
> 0.077 (>600 BIAF)
for dry combustion (well spacings40 acres) for reverse combustion for wet combustion
> 0.064 >lO
>O.iO
Oil Recovery. Table 46.11 lists some of the reported oil recoveries of steamflood and fireflood projects. 82-‘21 For the estimation of the oil recovery obtainable in a steam injection project, the analytical methods discussed previously can be used. As steam injection continues, the thermal efficiency will gradually diminish and the instantaneous SOR will increase gradually. When this ratio reaches a certain limit, further injection of steam will become uneconomical and needs to be stopped. The cumulative oil production at that time divided by the original oil in place (OOIP) will give the oil recovery. The oil recovery from a fireflood project can be calculated with the recognition that oil production comes from both the burned and unburned regions (Nelson and McNeil 122), Let Evb equal the volumetric sweep effciency of the burning front and ERu equal the recovery efficiency in the unburned region. The overall oil recovery is:
Volumetric
Steamfloods Inglewood, CA65 (Chevron-Socal) Kern River CA66,67 (Chevro;) Kern River, CA68-70
- 100.0
GeW) Midway Sunset, CA” (Tenneco) El Dorado, KA73 (Cities) Deerfield, MO 74 (Esso-Humble) Schoonebeek,The Netherlands75 (Nederlandse)
”
62.8 to 98.8
-
-
60.0 to 70.0
-
-
<50.0
85.0
40.0
34.0
-
-
24.3 to 41.9
>E,b+(l-Evb)ERu,
where C,,, is the fuel content, Ibm/cu ft. In this equation, the fuel consumed is taken to be a IO”AP1 oil with a density of 62.4 lbm/cu ft. The equation developed by Satman et al. ‘23 can be used to calculate the oil recovery from a dry combustion project.
( >1 0.25
Y=47.0
0.427S, -O.O0135h-2.196
-!-
X,
PO
..__,.....,..........
Firefloods South Belridge, CA76 (General Petroleum) Within Pattern Area (2.75 acres) Within Total Burned Area (7.90 acres) Sloss, NE”-” (Amoco) South Oklahoma” (Magnolia) Shannon Pool, WY” (Pan AmericanlCasper)
. . . . . (63)
,.......
(64)
where 100
59.6
59.6
100
50.4
50.4
Y=
rnP+vfbx100
..
..
. .
N 50
28
14
85
-
26
43
100
43
i&o2 x= [N,,(~S,)l(l -d) .
... ...
.
THERMAL
TABLE
RECOVERY
46-15
46.11 -OIL RECOVERY OF STEAMFLOOD AND FIREFLOOD PROJECTS
Field,
Location
(Operator)
Thermal Oil Recovery (Q/o OOIP)
Steamfloods Smackover, AR (Phillips)e2~83 Kern River, CA (Chevronia4 Kern River, CA (Getty)68 ’ Midway Sunset, CA (CWOD)85 Mount Poso. CA (Shell)*“~87 San Ardo, CA (Texaco)” Slocum, TX (She11)89~30 Winkleman Dome, WY (Amoco)g’ ” Tta Juana Estes, Venezuela (Maraven)g3-g5
25.7’ 69.9* 46.6 to 72.6 63.0* 34.6’ 47.5, 51.2 55.8* 28.1 * 26.3’
Firefloods Brea-Olinda, CA (Union)Q6,97 Midway Sunset, CA (Mobil)gB Midway Sunset, CA (CWOD)99 South Belridge, CA (General Petroleum)76 South Belridge, CA (Mobil)‘00 Robinson, IL (Marathon)‘0’~‘06 Bellevue. LA (Cities) lo7 lo8 Bellevue, LA (Getty)‘09~“* May Libby, LA (Sun)“3 Heidelberg, MS (G$~14~“5 Sloss, NE (Amoco) Glen Hummel, TX \Sun)“6,“7 Gloriana, TX (Sun) l6 “’ North Tisdale. WY (Continental)“g Suplacu de Barcau, Romania (IFPIICPPG)‘zo Miga, Venezuela (Gulf)“’
25.1. 20.0 52.8 56.7 14.5 31.9 41.5’ 44.6* 68.0 22.4’ 14.3 31 .o 29.7 23.0 47.5 11.6
In the above equation, ANp = cumulative incremental oil production, bbl, Ve = fuel burned, bbl, N = OOIP, bbl, lar = cumulative air injection, lo3 scf, EQ2 = oxygen utilization efficiency, fraction, and NV = oil in place at start of project, bbl. Gates and Ramey 124 developed a correlation between oil recovery and PV burned at various initial gas saturation, on the basis of field data taken from the South Belridge tireflood project 76 and laboratory combustion-tube data. This correlation, shown in Fig. 46.10, should be useful in predicting current oil recovery as the fireflood proceeds. Changes in Oil Property. At the temperatures and pressures prevailing in steamfloods, no changes in the oil property are expected to occur because of any chemical reactions. However, the properties of the recovered oil could have been changed as a result of steam distillation. In firefloods, of course, oil properties change considerably because of thermal cracking and combustion, as well as steam distillation. Changes in oil property in some of the reported steamfloods and firefloods are shown in Table 46.12. 125~‘30 Performance Indicator Pertaining to Steamfloods Only. Steam Oil Ratio (SOR). The SOR, F,, , is the most important factor characterizing the success or failure of a steamflood project. Its reciprocal, the OSR, F,,v, also is used commonly. In projects where oil is used as fuel
VOLUME Fig. 46.10-Estimated
8URNED
oil recovery
%
vs. volume
burned.
for steam generation, 1 bbl of oil normally can generate 13 to 14 bbl (cold-water equivalent) of steam. Thus, the highest SOR that is tolerable without burning more oil than that produced is 13 to 14. For steamflood operation, there are other costs than fuel alone. Because of this, steam injection is normally terminated when the instantaneous SOR reaches the level of eight or so. Ideally the overall SOR should be around four. This corresponds to 3 to 4 bbl of oil produced per barrel of oil burned. 13’This ideal case is, unfortunately, not normally achievable. The SOR of the majority of the steamflood field projects falls into the range of 5 to 7. The following set of regression equations developed by Chu62 can be used to estimate the SOR with known reservoir and crude properties. (F,, <0.20), 1. For F,>5.0 F,,=l/(-0.011253+0.000027790+0.0001579h
+0.5 12O$S,). 2. For F,, ~5.0
..
.... ..... ...
. ..
(67)
(F,, 20.20),
F,,=18.744+0.0014530-O.O5088h-0.0008844k -0.0005915~, where D = h = 8 = CL0= k = S, =
- 14.79S, -O.O002938khl/~~,
. (68)
depth, ft, reservoir thickness, ft, dip angle, degrees, oil viscosity, cp, permeability, md, and oil saturation at start, fraction.
Another method of estimating F,v, has been given by Myhill and Stegemeier, 29 based on the Mandl-Volek model.
PETROLEUM
46-l 6
TABLE
ENGINEERING
HANDBOOK
46.12-CHANGES IN OIL PROPERTY IN STEAMFLOOD AND FIREFLOOD PROJECTS Viscositv “API
Field, Location (Operator)
Before
After
23.5
25.9
South Belridge, CA76 (General Petroleum)
12.9
14.2
West Newport, GAlz6 “’ (General Crude)
15.2
20.0
9.5 then 10.5
12.2
Kyrock, KY “’ (Gulf)
10.4
South Oklahomaso (Magnolia)
Asphalt Ridge, UT13’ (U.S. DOE)* *
Temperature PF)
(cp) Before
’ After
Steamflood Brea, CA ‘Z (Shell)* Fireflood
East Venezuela”’ (Mene Grande)
‘Changes I” 0’0 C ~ -C ,* before-21 “Changes in other properf,es
Pour point. OF Residue bolllng above 1 ,OOOOF,wf%
Before
After
140 62
25 35
07 120
2,700 540
800 200
160 60 100
120 4,585 777
54 269 71
210
32
IO
14.5
60 210
90,000 120
2,000 27
15.4
20.4
66
14.2
20.3
after-28
Performance Indicators Pertaining to Firefloods Only. Fuel Content. Fuel content (lbm/cu ft of burned volume) is the amount of coke available for combustion that is deposited on the rock as a result of distillation and thermal cracking. It is the most important factor influencing the success of a fireflood project. If the fuel content is too low, combustion cannot be self-sustained. A high fuel content, however, means high air requirement and power cost. Besides, oil production also may suffer. Fuel content can be determined by laboratory tube runs. Gates and Ramey ‘24 presented a comparison of the estimated fuel content by use of various methods including laboratory experiments and field project data from the South Belridge project. 76 Their comparison shows that fuel content determined from the tube runs can provide reasonably good estimation of the fuel content obtainable in the field. In the absence of experimental data, the correlation of Showalter relating the fuel content to API gravity can be used. Fig. 46.11 shows a comparison of the Showalter data and field project data. 63 In addition, the following regression equation developed by Chu6* based on data from 17 field projects can be used to calculate the fuel content: C, = -0.12+0.00262h+0.0001 +0.000242kh/p,
5,000 800 after a month 5,000
14k+2.23S0
where C, is the fuel content, lbm/cu ft. Both laboratory experiments and field projects indicate that, for a specific reservoir, fuel content decreases as WAR increases. However, no statistically significant correlation was found to exist between fuel content and WAR in the presence of widely varying reservoir properties . 63 Air Requirement. As pointed out by Benham and Poettmann, 132air requirement, a, in lo6 scf/acre-ft of burned volume, can be calculated on the basis of stoichiometric considerations: 2Fcc+l
a=
( FCC+1
+FHC -
2
0.001109(12+F~~)~~~
>
ctn
x0.04356,
. .(70)
where F, is the CO2/CO ratio in produced gas and FHC is the atomic H/C ratio. In the absence of necessary data for Eq. 70, the Showalter correlation43 relating air requirement to API gravity can be used. A comparison of the Showalter data and field project data is given in Fig. 46.12. 63 It can be seen that all the field points fall on the upper side of the Showalter curve. Air requirement in the fields can exceed laboratory values because of air channeling and migration. In addition, the following regression equation developed by Chu63 can be used:
-0.0001890-0.0000652,u0,
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (69)
a=4.72+0.03656h+9.996S3,+0.000691k.
.
(71)
THERMAL
RECOVERY
46-17
.
LABORATORY TEST DATA BY SHOWALTER
l FIELD PROJECT
DATA
25
I
/
I
.
LABORATORY TEST DATA BY SHOWALTER
.
FIELD PROJECT DATA
I
O-
. . . MC
oI
20
10
Fig. 46.11-Effect
40
30
of oil gravity
on fuel content.
Fig. 46.12-Effect
Air-Oil Ratio (AOR). This important ratio relates air injection to oil production and usually is expressed in terms of lo3 scf/bbl. Oil recovery comes from both the burned and unburned regions. The AOR can be calculated thus I** :
Fm = a
. . . . . . . . . . . . . . . . . . . . . . . . (72) In the absence of Evb and ER,, , the following regression equation developed by Chu6* based on 17 field projects can be used. F,, =21.45+0.0222h+0.001065k
+0.002645~,
-76.76gbS,.
... . .
(73)
Besides, the correlation between oil recovery and PV burned developed by Gates and Ramey 124 can be used for estimating the current AOR as the fireflood proceeds. Both laboratory experiments and field projects indicate that, for a specific reservoir, AOR decreases as WAR increases. No statistically significant correlation, however, has been found between AOR and WAR in the presence of widely varying reservoir properties. 63
Project Design Design Features Common to Both Steamfloods and Firefloods Pattern Selection. For any oil recovery process with fluid injection, a cardinal rule of pattern selection is that, to achieve a balance between fluid injection and production,
of oil gravity
on
air requirement.
the ratio of the number of producers to the number of injectors should be equal to the ratio of well injectivity to well productivity (Caudle et al. 133). Because of the high mobility of air or steam compared to that of the oil, the injectivitylproductivity ratio is high, favoring a high producer/injector ratio. This rule generally has been followed by the various reported steamflood and fireflood projects. The use of inverted 13-spot, 9-spot, 7-spot, and 6-spot patterns, unconfined five-spot patterns, down-thecenter line of injectors, and single well injection has been reported. Aside from the injectivity/productivity ratios, other factors also should enter into consideration in pattern selection. These factors include: heat loss considerations, utilization of existing wells, reservoir dip, difficulty in producing hot wells, etc. Based on these and other considerations, repeated five-spot patterns, updip and crest injections and line drive also were used. The choice of pattern or nonpattern floods in the various steamflood and fireflood projects is shown in Table 46.13. ‘34-138 Completion Intervals. In most of the steamflood and fireflood projects, the producers usually are completed for the entire sand interval to maximize production. The injectors usually are completed at the lower third or lower half of the interval, to minimize the override of the steam or air. In wet combustion projects, it is advisable to complete the lower part for air injection and upper part for water injection. This is to minimize the underflow of water as well. Producer Bottomhole Pressure (BHP). In their study for a steamflood, Gomaa et al. 139 found that decreasing the producer BHP lowers the average reservoir pressure, increases steam volume, and increases predicted oil recovery. It is, therefore, important to keep the producers pumped off all the time. Without any reason to believe otherwise, keeping the producers pumped off should benefit a fireflood as well as a steamflood.
46-19
PETROLEUM
TABLE
46.13-PATTERN
Pattern
TYPES
Types
OF STEAMFLOODS
HANDBOOK
AND FIREFLOODS
Steamfloods
Firefloods
Inverted
13-spot
Slocum, TX8g,93 (Shell)
Inverted
g-spot
San Ardo, CA8* (Texaco) Yorba Linda, CA” (Shell)
Sellevue, LA’07.‘08 (Cities Service) Sellevue, LA’0g~“2
Inverted
7-spot
Kern River, CAM (Chevron) Slocum, TXm.”
Silverdale, (General
Ti!?i!ra, (Shell)
ENGINEERING
Wty) Alta. ‘34 Crude)
Venezuela’35
Unconfined inverted 5-spot
West Newport, CA’26.‘27 (General Crude)
Down-the-center-line of injectors
Trix-Liz,
TX”6~‘36
Gt!sf?~)ummel,
TX”6,“7
(Sun) Single
well injection
Repeated
5-spot
Miga, Venezuela’*’ (Gulf) East Coalinga.
CA’37
Sloss, NE77-79 (Amoco)
Ke?%er. CAa4 (Chevron) Kern River. CA”870
(GeW Winkleman Dome, (Pan American) Updip or crest injection
Downdip
injection
Updip and downdip injection
Brea, CAiz5 (Shell) Midway Sunset, (Tenneco) South Selridge, (Mobil)
WY “.”
CA7’.72
Midway Sunset, CA” (Mobil) Heidelberg, MS”4,1’5 (Gulf)
CAi3’
Mount Poso. CA8”.87 (Shell)
Line drive
Design Features Pertaining to Steamfloods Only Steam Injection Rate. According to Chu and Trimble, I40 the optimal choice of a constant steam injection rate is relatively independent of sand thickness. As sand thickness decreases, the total oil content in the reservoir decreases. This calls for a lower steam rate. At the same time, a higher steam rate is needed to compensate for the increased percentage heat loss with a decrease in thickness. These two counteracting factors result in only a small variation in the optimal steam rate as thickness is changed from 90 to 30 ft. The same study with five-spot patterns shows that the optimal choice of a constant steam rate is proportional to the pattern size. Furthermore, varying steam rates appear to be preferable to constant steam rates. An optimal steam rate schedule calls for a high steam rate in the initial stage and a decrease in the steam rate with time.
Suplacu de Sarcau, Romania (IPF/ICPPG)‘20
Steam Quality. Steam quality refers to the mass fraction of water existing in vapor form. Gomaa et al. ‘39 reported that increasing steam quality increases oil recovery vs. time but had little effect on recovery vs. Btu’s injected. This indicates that heat injection is the important parameter in determining steamflood performance. Just as with steam injection rates, the optimal choice of steam quality should be studied. High-quality steam could cause excessive steam override. This may be remedied by using lower-quality steam at one stage of a steamflood. Design Features Pertaining to Fireflood Only Dry vs. Wet Combustion. The choice between dry combustion and wet combustion is an important decision to be made in conducting a field project. Laboratory experiments indicated that the use of water either simultaneously
THERMAL
RECOVERY
46-19
or alternately with air does reduce the AOR, although the oil recovery may not be improved significantly. As was mentioned previously, a correlation between AOR and WAR, based on data from 21 field projects, was found to be statistically insignificant in the presence of widely varying reservoir properties. 63 Cities Service conducted a field comparison test of dry and wet combustion in the Bellevue field, LA, 14’ in which possible interference by variations in reservoir properties was essentially circumvented by using two contiguous patterns, one with dry combustion and another with wet combustion. This test found that, with wet combustion, the volumetric sweep was improved to a great extent. This indirectly implies an increase in oil recovery. Furthermore, the air requirement for a specific volume of reservoir was reduced. This reduced the operating cost and improved the economics. Because of these encouraging results, the possible advantages of using wet combustion should be explored.
ment, with high-temperature cement placed opposite and about 100 ft above the pay zone. The high-temperature cement recommended for the injectors is calcium aluminate cement (with or without silica flour), pozzolan cement, or API Class G cement (with 30% silica flour). If spontaneous ignition occurs, the use of cemented and perforated liners is required to prevent well damage resulting from burnback into the borehole. The producers should be completed to withstand relatively high temperatures and severe corrosion and abrasion. These authors recommended the use of gravel-flow pack, and stainless steel 316 for both liner and tubing opposite the pay zone. The well completion methods for injectors and producers in the various steamflood and fireflood projects, detailed by Chu6’,63 previously, are given in Table 46.14.
Air Injection Rate. According to Nelson and McNeil, ‘22 the air injection rate depends on the desired rate of advance of the burning front. A satisfactory burning rate was stated to be 0.125 to 0.5 ft/D. In the design method proposed by these authors, a maximum air rate is first determined, based on the minimum burning rate of 0.125 ft/D. They recommended a time schedule such that the air rate would be increased gradually to the maximum rate, held at this rate for a definite period, and then reduced gradually to zero. The Midway Sunset, CA, project of Chanslor-Western99 used a burning rate of 1 in./D (0.08 ft/D). Gates and Ramey ‘24 found that the air rate should provide a minimum rate of burning front advance of 0.15 ft/D or an air flux of at least 2.15 scfihr-sq ft at the burning front.
Steam Generation and Injection. Most of the steam injection projects use surface steam generators. The major difference between oilfield steam generators and industrial multitube boilers is the ability to produce steam from saline feedwater with minimum treatment. Other features include unattended operation, portability, weatherproof construction, and ready accessibility for repairs. The ability to use a wide variety of fuels including lease crude is also an important requirement. The capacity of steam generators used in steamflood projects usually ranges from 12 to 50 X lo6 Btuihr, with 50 x lo6 Btuihr becoming the industry standard in California. With surface steam generators, the steam goes from the generators to the injection wells through surface lines. Most surface steam lines are insulated with a standard insulation with aluminum housings. The steam is split into individual injectors through a header system using chokes to reach critical flow. This procedure requires that the steam achieve sonic velocity, which, under one field condition, 68 calls for a pressure drop of about 55 % across the choke. The chokes are sized to each other to give the desired flow rate into each injector. As long as the pressure drop is greater than 55 X , the flow rate will be independent of the actual wellhead injection pressure. A recent development is the use of downhole steam generators to eliminate wellbore heat losses in deep wells. There are two basic designs, which differ on the method of transferring heat from the hot combustion gases to produce steam. ‘43 In one design, the combustion gas mixes directly with feed water and the resulting gas/steam mixture is injected into the reservoir. Because of this, the combustion process takes place at the injection pressure. In another design, there is no direct contact between the combustion gas and water, just as in the surface generators. The combustion gas returns to the surface to be released after giving up much of the heat to generate steam. A lower pressure than injection pressure can be used in this case. Still another new development is cogeneration of steam and electricity. I44 The effluent gas from a combustor is used in a gas turbine, which drives an electrical generator. The exhaust gas from the turbine is then used in steam generators to produce steam for thermal recovery purposes.
Field Facilities Steamflood Facilities
WAR. The reported WAR in various field projects ranged from 0 (for dry combustion) to 2.8 bbl/103 scf. The choice of WAR depends on water availability, quality of the water available, well injectivity, and economic considerations. Combustion tube experiments, properly designed and executed, should be helpful.
Well Completion Special well completions are needed for injectors and producers to withstand the high temperatures in steamfloods, and to withstand the corrosive environment as well in firefloods. According to Gates and Holmes, 14* wells used in steam operations should be completed with due consideration of heat loss with thermal stresses. In deep wells, tubular goods with high qualities, such as the normalized and tempered P-105 tubing and P-110 casing, should be used if the tubing and casing are not free to expand. Thermal stress can be minimized by the proper use of expansion joints. Thermal packers should be used on steam injection wells and deep wells undergoing cyclic steaming. The cement should include a thermal strength stabilizing agent, an insulating additive and a bounding additive. For firefloods, Gates and Holmes’42 felt that steel casing and tubing such as J-55 is suitable for injectors. These wells can be completed with normal Portland ce-
PETROLEUM
46-20
TABLE
46.14-WELL
COMPLETION
FOR STEAMFLOODS
Casing
Openhole or perforated completions
HANDBOOK
AND FIREFLOODS Firefloods
Steamfloods
Injectors
ENGINEERING
Grades: J-55, K-55, and N-80 Sizes: 4%, 5%, 65/8, 7, and 9% in. Tensile prestressing of casing in deep wells
Grades: J-55 and K-55 Sizes: 41/z, 5%. 7, and 8% in. across pay zone
Both openhole completions with slotted lmers and solid-string completion with jet perforations have been reported. Liner sizes: 4X, 5’/2, or 7 in. Perforations: l/4 or % In., one or two per foot, or one-half per foot Some with stamless steel wire-wrapped screens.
Perforated completion openhole completion
Class A, G, and H cement 60% of dry cement).
Use of high-temperature
with silica flour (30 to
Liner sizes: Perforations:
the
more prevalent than with or without liners.
3% or 5% in. l/4 or l/2 in. (two or four per foot)
cement
prevalent
Use not prevalent
Use not prevalent.
Tubing insulations used in deep wells: asbestos with calcium silicate, plus alummum radiation sheld; or jacketed tubing with calcium silicate.
Tubing used for air injection or as a thermowell. In wet combustion, various ways have been used for injection of air and water.
Casing
Grade: K-55 Sizes: 4%, 5%, Ss/,, 7, and 85/8 in. Tensile prestressing of casing in deep wells
Grades: H-40, J-55, and K-55 Sizes: 51/z, 7. 85/8, and 95/a in.
Openhole or perforated completions
Both openhole completion with slotted liners and solid-string completion with jet perforations have been reported. Liner sizes: 4’/2, 4X, or 65/a in. Slot sizes: 40, 60, or 601180 mesh Perforations: % in., four per foot Some with stamless steel wire-wrapped screens.
Openhole completion with or without slotted and perforated completion are equally prevalent. Liner sizes: 4%, 5’12, or 65/8 in. Slot sizes: 60-mesh. 0.05, 0.07, or 0.08 in. Perforations: V2 In. (two or four per foot)
Cement
Class G and H cement 60% of dry cement).
Use of high-temperature
Gravel packing
Use more prevalent than in injectors Gravel size: 6/9 mesh flow-packed.
Use more prevalent Gravel sizes: 20/40 pressure-packed.
Tubing
Tubing
Tubing for rod pump, to serve for cooling water injection.
Gravel
packmg
Tubing
Producers
with silica flour (30 to
for rod pump.
Water Treatment. The feedwater treatment for steam generation consists mainly of softening, usually through zeolite ion exchange. Some feedwaters may require filtration and deaeration to remove iron. Still others may need to use KC1 for control of clay swelling and chlorine to combat bacteria. Facilities for oil removal also will be needed if the produced water is to be reused as feedwater for steam generation. Fireflood Facilities Ignition Devices. In many fields, the reservoir temperature is so high that spontaneous ignition would occur only a few days after starting air injection. In some projects, steam, reactive crude, or other fuels will be added to help ignition. Many other fields need artificial ignition devices, which include electrical heaters, gas burners, and catalytic ignition systems. The various ignition methods, including equipment and operational data, have been discussed by Strange. 145 Air Compressors. The air compressors can be gas engine or electrical motor driven. Depending on the total
cement
liners
was reported
than in Injectors. or 619 mesh, flow- or
as a thermowell.
or
injection rate the compressor needs to supply and the output pressure needed, the capacity of the compressors can range from 1.0 to 20.0~ lo6 scf/D, and the power rating can range from 300 to 3,500 hp.
Monitoring and Coring Programs Monitoring Programs A thermal recovery project could be a complete failure economically and still be considered a success if it could provide useful information on the reservoir performance under steamflood or fireflood. A properly designed monitoring program carried out during the project and coring programs during and after the project are important in providing the information necessary for evaluating steamflood or fireflood performance. The Sample, Control, and Alarm Network (SCAN) automation system installed by Getty in the Kern River field ‘46 illustrates how a large steam injection operation can be monitored. This system consists of a devoted central computer that monitors 96 field sites. At these sites, the production rates of more than 2,600 producers and the operating rates of 129 steam generators are gathered. The SCAN oerforms several functions.
THERMAL
46-21
RECOVERY
1. It automatically schedules and controls well production tests at each site. 2. It monitors results of well production tests, steam generator operating rates, flow status, and injection status of producers, valve positions during well tests, and various status contact checks. 3. It sounds the alarm upon any malfunctioning at a field site or a steam generator. 4. It reports necessary operating information routinely on a daily, weekly, or monthly basis, and other special reports on demand from the operator. The Silverdale, Alta., fireflood project of Genera1 Crude ‘34 also uses an automatic data collection system. Differential pressure transducers, thermocouple-amplifier transducers, pressure transducers, and motor load transducers are used to measure and record data at each well. These data are transmitted to a central system, which can be interrogated and can indicate any alarm situation when pressures, temperatures, or flow rates fall outside certain specified ranges. Not all thermal projects call for elaborate automatic monitoring programs. The following program used in the Bodcau, LA, fireflood project of Cities Service-DOE I47 typifies one needed for a small-scale pilot. 1. Gas production rates, useful for mass balance calculations, were measured monthly. Monthly analysis of the produced gas gave data for the calculation of the oxygen utilization efficiency. 2. Oil and water production rates were measured at least twice each month. 3. Flow line temperatures were measured daily. These temperatures, in conjunction with the gas production rates, were useful in determining the amount of quench water needed at the producers, 4. Downhole temperature profiles were taken monthly at the observation wells. These profiles helped to delineate the development of the burned volume.
Photographs and Visual Examination. Whereas blackand-white photographs were found to be rather useless, ultraviolet photographs gave an excellent picture as to where the oil was removed by the burning process. The absence of oil also could be seen by visual examination. In some intervals, the reddish color of the core indicated that the core had been subjected to a temperature high enough for iron oxidation. Mineral Analyses of the Cores. Various minerals, including glauconite, illite, chlorite, and kaolinite, underwent permanent changes with the temperature increase. The maximum temperature to which the core samples had been exposed could be determined from the form and color of these minerals. Microscopic Studies. The scanning electron microscope was used to study anhydrite formation and clay alteration in the core samples, which had been subjected to high temperatures. Tracers The use of tracers helped to monitor fluid movement and interpret areal coverage in individual steamflood patterns. According to Wagner, I48 preferred aqueous-phase or gaseous-phase tracers include radioisotopes, salts with detectable cations and anions, fluorescent dyes, and watersoluble alcohols. Radioactive tracers include tritium, tritiated water, and krypton-85. Other tracers include ammonia, air, sodium nitrite, sodium bromide, and sodium chloride.
Operational Problems and Remedies Operational problems plaguing steamflood and fireflood projects and their remedies, previously detailed by Chu . 6’,63 are summarized next.
Coring Program
Problems Common to Steamfloods and Firefloods
Drilling core holes could be very expensive, depending on the depths of the pay zones. However, a judiciously designed and properly executed coring program, either during a thermal project or afterward, could provide valuable information on the project performance. Such a program can give the following information: (1) residual oil saturation (ROS) after steamflood or fireflood, (2) vertical sweep of the injected steam or burned volume, (3) areal sweep of the steam front or burning front, (4) maximum temperature distribution, both areally and vertically, and (5) effective permeability of the rock, and whether any deposits formed during the process could have reduced the flow capacity. A typical coring program, used for postmortem evaluation in the Sloss, NE, fireflood project,79 is summarized next.
WeII Productivity. Production of the highly viscous crude may be extremely low before the arrival of the steam front or burning front. The production rate can be improved by injecting light oil as a diluent, hot oil treatment, cyclic steam injection, or burning at the producers. When producer temperature exceeds 250”F, pump efficiency decreases to a great extent because of hot produced fluids flashing to steam or direct breakthrough of the injected steam or flue gas. The best remedy is to plug off the hot zone and redirect the steam or flue gas to the oil section before entering the wellbore.
Core Analyses. Porosity, permeability, and oil saturations were measured on each foot of the recovered cores. Oil saturations were determined by the routine Dean-Stark extraction and weight loss method, and the infrared absorption method.
Sanding. Sanding can be severe even in steamflood projects. The remedies include the Hyperclean’” technique, foamed-in tight-hole slotted liners, a sodium aluminate sand consolidation technique, and the use of phenolic-resin gravel packing. In firefloods, sanding is particularly severe if the sand is extremely unconsolidated. The erosion can be aggravated further by coke particles and high gas rates. Sandblasting could require frequent pulling of wells and replacement of pumps.
Log Analyses. Compensated formation density and dualinduction laterolog logs were run in the core holes to determine porosity and oil saturation.
Emulsions. In steamfloods, emulsions sometimes can be broken easily by chemical treatment. The problem could
PETROLEUM
46-22
ENGINEERING
HANDBOOK
Problems Plaguing Firefloods Only Poor Injectivity. Various substances can cause losses in injectivity for the air injectors. If identifiable, these problems can be remedied by appropriate means. Injector plugging by iron oxide can be reduced by injecting air into the casing and bleeding it through the tubing. Asphaltene buildup can be reduced by squeeze washing with asphaltene solvent. Emulsion formed in situ can be reduced by emulsion breakers. Scale formation caused by barium and strontium sulfate can be reduced by an organic phosphate. The injection of NuTriT” (trichloromethylene) and acidizing are useful in improving the injectivity.
t
Corrosion. Corrosion can be mild or serious and is caused by simultaneous injection of air and water, production of acids, sulfur, oxygen, and CO2 . Corrosion inhibitors are needed regularly.
I--
Exploration Hazards. To minimize explosion hazards in the air injection system, an explosion-proof lubricant should be used. Flushing of the interstage piping with a nitrox solution is necessary.
Case Histories Fig. 46.13-Production history of cyclic steam stimulation, sand, Huntington Beach offshore field, CA.
TM
become severe if the emulsion is complicated with the solids produced and with the continuously changing nature of the produced fluids. Emulsions found in fireflood projects are formed of heavy oil, cracked light ends, quench and formation water, solids, and possibly, corrosion products. They can become a continual and major problem in some projects, and require expensive emulsion breakers. Problems Plaguing Steamfloods Only Steam Placement. The lack of control of steam placement during steam stimulation is a major problem in producers with liner completions. The use of solid string completions will help reduce the problem. Steam Splitting. The uneven splitting of steam in a twophase regime can cause significant differences in steam quality into different injectors. This can be corrected by modifying the layout of the steam line branching system.
TABLE 46.15--RESERVOIR ROCK AND FLUID PROPERTY DATA, TM SAND, HUNTINGTON BEACH OFFSHORE FIELD, CA Depth, fl Thickness, ft Gross Net Porosity, % Permeability, md Oil gravity, OAPI Reservoir temperature, OF Reservoir pressure at start, Oil viscosity at 12?F, cp Oil saturation al start, %
2,000
wig
to 2,300
115 40 to 58 35 400 to 800 12 to 15 125 600 to 800 682 75
Many thermal recovery projects have been reported in the literature. The following describes a number of selected projects and gives the reasons for their selection.
Steam Stimulation Operations Huntington Beach, CA (Signal) 149-TypicaI Operation. The steam stimulation project was conducted in the TM sand, in the Huntington Beach offshore field, Orange County, CA, This project typifies the behavior of a heavyoil reservoir under cyclic steam stimulation. The reservoir properties are given in Table 46.15. Steam injection was started in nine producers in Sept. 1964, resulting in a large increase in oil production. This early success prompted the expansion of the project by drilling wells on 5-acre spacing. The number of wells increased from 9 in 1964 to 35 in 1969. The performance of the steam stimulation project during the 1964-70 period is shown in Fig. 46.13. With steam stimulation and with the almost quadrupling of the number of wells, the oil rate increased more than lo-fold, from 125 B/D oil in 1964 to about 1,500 B/D oil in 1970. The performance of steam stimulation normally deteriorates as the number of cycles increases. As shown in Table 46.16, the OSR changed from the range of 3 to 3.8 bbl/bbl for the first two cycles to the range of 2.4 to 2.5 bbl/bbl for the third and fourth cycles. Fig. 46.14 shows how oil production in one well decreases during a cycle and how it varies from one cycle to another. Paris Valley, CA (Husky) ‘50-Co-Iqjection of Gas and Steam. A wet combustion project was initiated at Paris Valley, which is located in Monterey County, CA. Before the arrival of the heat front, the producers were stimulated with steam. A special feature that made this project interesting was the co-injection of air and steam in three of the stimulation cycles. The reservoir properties are given in Table 46.17.
THERMAL
46-23
RECOVERY
TABLE THROUGH OCTOBER
46.16-SUMMARY OF PERFORMANCE FOUR “HUFF ‘N’ PUFF” CYCLES AS OF 1,197O; TM SAND, HUNTINGTON BEACH OFFSHORE FIELD, CA Cycle
Number of wells Average cycle length, months Average oil recovery per well, STB Average quality of steam injected, % Average volume of steam injected, bbl Ratio of oil recovered to steam injected, STBlbbl
1
Cycle
2
Cycle
Cycle 4
3
24
18
11
4
14
18
15.3
14.5
28,900
30,900
24,650
29,225
71.4
69.3
75.1
78.5
9,590
8,130
10,190
11,760
3
3.8
2.4
2.5
? ABLE 46.17-RESERVOIR ROCK AND FLUID PROPERTY DATA, ANSBERRY RESERVOIR, PARIS VALLEY FIELD, CA
Fig. 46.14-011
production offshore field.
rate, Well J-128,
Huntington
Beach
In Table 46.18, Cycles 3 and 5 of Well 20 and Cycle 7 of Well 3 used air-steam injection. For Well 20, oil production in Cycle 3 was 4,701 bbl while that in Cycle 2 was 2,449 bbl. Thus, with air-steam injection, oil production increased by 92 % . A similar increase was noticeable for Cycle 5 of Well 20 and Cycle 7 of Well 3 when compared with their respective preceding cycles, which used steam only.
Depth, R Net thickness, ft Dip, degrees Porosity, % Permeability, md Oil gravity, OAPI Reservoir temperature, Initial pressure, psig Saturation at start, % Oil Water Oil viscosity, cp
OF
64 36 Upper
87°F lOOoF 200°F
800 50 15 32 3,750 10.5 a7 220
Lower
Lobe
227,000 94,000 340
Lobe
23,000 11,000 120
Steamflood Projects Kern River, CA (Getty) 68m70-Largest Steamflood. The Kern River field is located northeast of Bakersfield, CA, in the southeastern part of the San Joaquin Valley. Getty Oil Co.‘s steam displacement operation in this field is the largest in the world, based on a 1982 survey. l3 According to this survey, the thermal oil production rate was 83,000 B/D in an area of 5,070 acres. The Kern River formation consists of a sequence of alternating sand and shale members. The reservoir properties are given in Table 46.19. The Kern River field was discovered in the late 1890’s. In the mid-1950’s, bottomhole heaters were used to improve the oil productivity. In Aug. 1962, a 2.5-acre normal five-spot hot waterflood was started. Results showed that this process was technically feasible but economically unattractive. In June 1964, the hot waterflood pilot was converted to a steam displacement test and the number of injectors was increased from the original 4 wells to 47 wells. Continued expansion through the years has increased the number of injectors to 1,788 wells, with 2,556 producers by 1982. The original Kern project and some later expansions are shown in Fig. 46.15. The steam displacement operation was in general conducted in 2.5-acre five-spot patterns. Getty Oil Co.‘s steam displacement operation includes many projects. For illustration purposes, the Kern project is presented here with a map showing the well patterns (Fig. 46.16) and a figure showing the injection and
TABLE
46.1 &-RESPONSE
TO CYCLIC
AIR/STEAM
Well 20
Steam volume, lo3 bbl Air volume, lo6 scf Air/steam ratio, scflbbl Comparable producing days Oil produced, bbl Steam/oil ratio, bbl/bbl Oil/steam ratio, bbllbbl Peak oil production test, BID
Well 3
Cycle 2
Cycle 3
Cycle 4
Cycle 5
Cycle 6
Cycle 7
13.2 0
16.2 1.5
15.7 0
10.4 3.7
8.2 cl
9.2 3.6
0
91
0
355
0
394
161 2,449
161 4,701
90 270
90 503
97 2,375
97 4,203
5.4
3.4
50
21
3.5
2.2
0.19
0.29
0.02
0.05
0.29
0.45
51
81
24
38
60
141
46-24
TABLE
PETROLEUM
46.19--RESERVOIR ROCK AND FLUID DATA, KERN RIVER FIELD, CA
Depth, ft Thickness, ft Dip, degrees Porosity, % Permeability, md Oil gravity, OAPI Reservoir temperature, OF Reservoir pressure at start, Oil viscosity, cp 9OoF 250°F Oil saturation at start, %
ENGINEERING
HANDBOOK
PROPERTY
500 to 1,300 30 to 90 4 28 to 33 1,000 to 5,000 12.0 to 16.5 90 100
psig
4,000 15 35 to 52
production history of the four-pattern pilot (Fig. 46.17). In this project, the cumulative SOR was 3.8 bbl/bbl and the production rate reached 100 B/D of oil per pattern. Core hole data before and after the steamflood showed an oil recovery of 72 % and also a very high area1 sweep efficiency. Brea, CA (Shell) ‘25-Steam Distillation Drive, Deep Reservoir, Steeply Dipping. A steam distillation drive was initiated in 1964 in the Brea field, which is located about 25 miles east of Los Angeles. This project is interesting because the oil is relatively light with low viscosity, and the reservoir is steeply dipping at a great depth. The reservoir properties are summarized in Table 46.20. The dipping reservoir is seen clearly in Fig. 46.18. The injectors are located updip, as shown in Fig. 46.19. Because of the depth, insulated tubing was used for the injectors. This figure also shows the area of temperature response and production response. The injection and production rates are given in Table 46.20. As of Dec. 1971, the steam rate was 1,010 B/D water and the oil rate was 230 B/D, giving an estimated SOR of 4.4 bbl/bbl.
Fig. 46.15-Kern
River field,
CA.
I . 312
I . .
l
.
Smackover, AR (Phillips) 82T83-Reservoir With Gas Cap. The Smackover field is located in Ouachita County, AR. The steamflood pilot, conducted in the Nacatoch sand, is worth mentioning because the reservoir has a gas cap thicker than the oil sand itself. This gas cap can be seen readily in the log and coregraph of Sidum Well W-35 (Fig. 46.2 1). The reservoir properties are given in Table 46.21.
. .
.
. . .-
I
Fig. 46.16-Kern
steam displacement
project,
Kern River field.
Iam I,mnn
TABLE
46.20-RESERVOIR ROCK AND FLUID DATA, BREA FIELD, CA
Depth, ft Gross stratigraphic thickness, ft Ratio of net to gross sand, % Dip, degrees Porosity, O/O Permeabilitv. md Oil gravity, ‘“‘API Reservoir temperature, OF Reservoir pressure at start, psi Oil viscosity at 17YF, cp Saturahon at start, % Oil Gas
PROPERTY
’ soan
4,600 to 5,000 300 to 800 63 66 22 77
‘mm =
6 49 18
Fig. 46.17-Injection and production history, Kern hot water and steam displacement project (four patterns) Kern River field.
m m 0
THERMAL
46-25
RECOVERY
F-12
F-13 F-18
WATER SATURATION, X
M-15
$7nnn’
Fig. 46.18-Cross field.
section
through
the lower “B”
sands,
I-I -
Brea Fig. 46.21-Log and coregraph, field, AR.
Sidum Well W-35, Smackover
PAODUCTION RESPONSE ~
OYC
---------
TOP
f-14 SPNO ---_
--“T-
Fig. 46.22 is a map of the lo-acre five-spot pilot, which was later expanded to a 22-acre nine-spot pattern by adding four more producers. As shown in Fig. 46.23, steam injection started in Nov. 1964 and stopped in Oct. 1965. The oil production continued long after steam injection stopped. As of Aug. 1970, the additional oil produced by steamflood was 207,000 bbl. With total steam injection of 860,000 bbl, the cumulative SOR was 4.14 bbl/bbl. The temperature log in Fig. 46.24 shows that steam goes to the gas cap. It can be concluded that the increase in oil production was not caused by frontal displacement. Rather, the oil zone temperature increased because of conduction and convection from the gas cap, thus reducing the oil viscosity and increasing the oil production.
---
LEGEND 'I'
lNJECT,ON PROOUCTION
'
OBSERVATION
YELLS YELLS WELLS
Fig. 46.19-Well locations and area of temperature, tritium, production responses, Brea field, CA.
and
TABLE
EST
lo
63
64
65
66
67
PRIVAAY
WODUCTION
68
69
70
71
YEAR Fig. 46.20-Injection lation
and production pilot.
history,
Brea steam distil-
46.21--RESERVOIR ROCK AND FLUID DATA, SMACKOVER FIELD, AR
Depth, ft Thickness, ft Gross Net Dip, degrees Porosity, % md Permeability, Oil gravity, OAPI Reservoir temperature, ‘-‘F Reservoir pressure at start, Oilviscosity, cp 6OOF llO°F Saturation at start, % Oil Water
PROPERTY
1,920
psia
130 25 0 to 5 35 2,000 20 110 5 180 75 50 50
46-26
PETROLEUM
SE14
SECTION
ENGINEERING
HANDBOOK
TEMPERATURE SCALE ) OF DFEEpErT” ~ 150 175 200 225 250 275 125
32-ISS-15W
3 .2
.’
,SA3
.‘6
20
.‘4 WELL
SYMBOLS:
SCALE
.2
PRODUCING
00-1
WATER DISPOSAL
0%43
WATER SUPPLY
Fig. 46.22-Sidum
steam
injection
pilot,
Smackover
.‘9 I- = 400’
field. Fig. 46.24-Temperature field.
h 300-
log, Sidum
Well
W-42,
Smackover
Slocum, TX (SheU)89~90-Reservoir With Water Sand. The Slocum field is located in southern Anderson County in northeast Texas. The steamflood project interests us since it is conducted in an oil reservoir underlain by a water sand, as shown in the type log (Fig. 46.25). The reservoir properties are given in Table 46.22. The fieldwas discovered in 1955. Only about 1% of OOIP was produced by primary operation. A small steamflood pilot using a N-acre normal five-spot pattern showed encouraging results. A full-scale seven-pattern project was initiated in 1966-67, with 5.65acre, 13-s@ patterns (Fig.
n
46.26).
/ 0' 0 L p7---
-
1964
1965
-TOTAL ;E loots E a. d d
PRIMARY-
/
I
1966
1967
1970
1971
PILOT
)WELL
1&VA 4 ’ PRMAAY -’ 01 1966
Fig. 46.23-injection jection
Both injectors and producers were completed a few feet into the water sand. Steam moves horizontally through the water layer, rises vertically into the oil layer, and displaces oil that had been heated and mobilized. The oil then falls down and subsequently is swept toward the producers. The injection and production history is shown in Fig. 46.27.
PILOT
1969
and production pilot, Smackover
history, field.
Sidum
steam
in-
Street Ranch, TX (Conoco) I51-Extremely Viscous Tar, Fracture-Assisted Steamflood. The Street Ranch pilot was conducted in the San Miguel-4 tar sand reservoir located in Maverick County, TX. This pilot proved the technical feasibility of the fracture-assisted steamflood technology (FAST) in recovering extremely viscous heavy oils and tars. The reservoir properties are given in Table 46.23. The pilot used a 5-acre inverted five-spot pattern. The four producers were fractured horizontally with cold water, steam stimulated, perforated, and resteamed. The injector then was fractured horizontally to establish communication with the producers. The pilot consisted of three
THERMAL
RECOVERY
GAMMA
46-27
RAY
TABLE
RESlSTlVlTY
46.22--RESERVOIR ROCK AND FLUID DATA, SLOCUM FIELD, TX
Depth, ft Thickness, ft Gross Net Dip, degrees Porosity, O/o Permeability, md Oil gravity, OAPl Reservoir temperature, “F Initial reservoir pressure, psig Oil viscosity, cp 60°F 400°F Oil saturation at start, %
Fig. 46.25-Type
log, Slocum
field,
PROPERTY
520 34 32 0 to 5 34 > 2,000 18 to 19 80 110
1,000 to 3,000 3 to 7 68
phases: (1) fracture preheat, (2) matrix steam injection, and (3) heat scavenging with water injection. The tar production and steam/tar ratio during the 3 1-month history are shown in Figs. 46.28 and 46.29, respectively. The average tar production rate was 185 B/D and the cumulative steam/tar ratio was 10.9 bblibbl. Postpilot core holes showed residual tar saturations as low as 8% and an average recovery efficiency of 66 % .
TX
Lacq Suphieur, France (Elf Aquitaine) Is2 -Carbonate Reservoir. The Lacq Sup&ieur field is on the north side of the Pyrenees Mts. in southwest France. The steamflood pilot is unique because it was conducted in a carbonated, dolomitized, and highly fractured reservoir. The reservoir properties are given in Table 46.24. The pilot was located in the central part of the fractured limestone zone, near the top of an anticline. The pattern area is 35 acres, defined by six old producers, as shown in Fig. 46.30. The injector was the only one drilled for the pilot. Steam injection started in Oct. 1977. Oil production started to increase, only 3 months after steam injection began. The production history is shown in Fig. PLTTERN EXPLHIlGN 119.511 m ElGtlT PATTERN EXPINSlG” IIP,PI 46.3 1. By June 1980, incremental oil production amount. INJECTION WELL ed to 176,000 bbl with a cumulative steam injection of . THERYIL PRODUCTIGN WELL 926,000 bbl. The cumulative SOR is 5.26 bblibbl. This Fig. 46.26-Slocum
thermal
recovery
Project.
TABLE
Fig. 46.27-Injection recovery
and production project.
history,
Slocum
thermal
4’j.23--RESERVOIR DATA, STREET
ROCK AND FLUID PROPERTY RANCH PILOT, TX
Depth, ft Thickness, ft Gross Net Dip, degrees Porosity, % Permeability, md Tar gravity, “API Reservoir temperature, OF Tar viscosity at 95OF. cp (est.) Tar kinematic viscosity, cSt 175OF 200°F 250°F 300°F Pour pomt. “F Total sulfur, wt% Initial boiling pomt, OF Tar saturation at start, %
1,500 52 40.5 2 26.5 and 27.5 250 to 1,000 -2.0 95 20,000,000 520,000 61,000 2,900 870 170 to 180 9.5 to 11.0 500 54.7 and 38.9
PETROLEUM
46-28
TABLE
ENGINEERING
46.24--RESERVOIR ROCK AND FLUID PROPERTY DATA, LACQ SUPERIEUR FIELD, FRANCE
Depth, ft Thickness, ft Oil gravity, OAPI Reservoir temperature, OF Reservoir pressure, psi Oil viscosity at 1 40°F, cp
1,970 to 2,300 400 21.5 140 670 17.5 Matrix
Porosity, % Permeability, md Water saturation at start.
Fig. 46.28-Tar
production
history,
Street
Ranch
HANDBOOK
%
Blocks 12 1 60
Fissure
Network
0.5 5,000 to 10,000 100
pilot, TX.
pilot showed that a strongly fissured reservoir can be exploited efficiently by the steamflood process, as if it were a homogeneous reservoir. The dissociation of the carbonate rocks by steam apparently produced no unfavorable effects. Rather, the CO2 evolved might have some positive effect on the process efficiency.
Fireflood Projects
Fig. 46.29-Steam/tar
ratios,
Street
Ranch
\ \ O-
loo0
0
Fig. 46.30-Pilot
/I
\
2som ft.
area,
pilot.
/ v
La4
Lacq Sup&ieur
field,
France
Suplacu de Barcau, Romania (IFP-ICPP) “‘-Largest Fireflood. The Suplacu de Barcau field lies in northwestern Romania. This is reportedly the largest fireflood project in the world, producing nearly 6.563 B/D of 15.9”API oil. The reservoir properties are given in Table 46.25. The project started with a pilot in 1964 using a 1.24-acre inverted five-spot pattern that was later expanded into a 4.94-acre inverted nine-spot pattern. This was followed by a semicommercial operation in the period 1967-71 with eight 9.88-acre inverted nine-spot patterns. This operation further expanded into full commercial operation, first retaining the nine-spot patterns with the same spacing, and later changing to linedrive operation. The original pilot and later expansions are shown in Fig. 46.32. Injection wells numbered 38 in 1979 with 20 using alternate air and water injection and the balance using straight air. The production history is given in Fig. 46.33. The WAR was 0.089 to 0.178 bb1/103 scf. As of 1979, the air injection rate was 63,600~ lo3 scf/D. With an oil rate of 6,563 B/D. the AOR was estimated to be 9.7 X 10’ scf/bbl. West Heidelberg, MS (G~lf)“~*“~-Deepest Fireflood. The West Heidelberg field is located in Jasper County in eastern Mississippi. With a depth exceeding 2 miles, it is the deepest fireflood project, or the deepest thermal project, for that matter. The Cotton Valley formation has eight sands. The fireflood was conducted in Sand No. 5. The reservoir properties are given in Table 46.26. As shown in the structure map of Sand No. 5 (Fig. 46.34), only one injector was used, near the top of the structure, with seven producers located downdip. The injection and production history is given in Fig. 46.35. It can be estimated from this figure that, during the period 1973-76, the average air injection rate was about 900 x lo3 scf/D whereas the average oil production rate was about 400 B/D. This gives an AOR of only 2.25 x lo3 scfibbl.
THERMAL
RECOVERY
46-29
Fig. 46.31-Production
history,
Lacq Superieur
field.
TABLE 46.25--RESERVOIR ROCK AND FLUID PROPERTY DATA, SUPLACU DE BARCAU FIELD, ROMANIA Depth, ft Net thickness, ft Porosity, % Permeability, md Oil gravity, OAPI Reservoir temperature, OF Oil viscosity at 64OF, cp Oil saturation at start, %
Fig. 46.32-Suplacu
de Barcau
field,
Romania.
TABLE
46.26-RESERVOIR ROCK AND FLUID DATA, WEST HEIDELBERG FIELD, MS
Depth, ft Thickness, ft Gross Net Dip, degrees Porosity, % Permeability, md Oil gravity, OAPI Reservoir temperature, Oil viscosity at 221°F, Oil saturation at start.
Fig. 46.33-Injection field.
and production
history, Suplacu
de Barcau
164 to 656 32.8 32 1,722 15.9 64 2,000 85
PROPERTY
11,500 20 to 40 30 5to 15 16.4
OF cp %
;: 221 4.5 77.8
Gloriana, TX (Sun)“6~118-Thinnest Reservoir Produced by a Fireflood. The Gloriana field is in Wilson County, TX. The fireflood took place in the Poth “A” Sand. It is possibly the thinnest reservoir that has ever been produced by a fireflood. The reservoir properties are given in Table 46.27. The field originally was developed on 40-acre spacing. A new well, Well 2-8, was ignited in May 1969. Well 2-5, a producer, burned out and was converted to air injection in May 1971. These wells, along with other wells,
46-30
PETROLEUM
TABLE
Productionlimit l-1 1,093 Cl
Fig. 46.34--Structure MS.
46.27--RESERVOIR ROCK AND FLUID DATA, GLORIANA FIELD, TX
Depth, ft Thickness, lt Gross Net Dip, degrees Porosity, O/O Permeability, md Oil gravity, OAPI Reservoir temperature, Oil viscosity, cp 112°F 8OOF Oil saturation at start,
line
ENGINEERING
HANDBOOK
PROPERTY
1,600 10 4
0 to 5 35 1,000
OF
20.8 112 70 to 150 250 to 500 58.5
%
-j--y$>.)1
map of Sand No. 5, West Heidelberg
field,
are shown in the isopachous map in Fig. 46.36. The injection and production histories are given in Figs. 46.37 and 46.38, respectively. Air injection stopped in Dec. 1974 when the oil production rate declined to the economic limit. Sloss, NE (Amoco) 77-79-Wet Combustion, Tertiary Recovery. The Sloss field is located in Kimball County, NE. The pilot used a wet combustion process in a previously waterflooded reservoir. Here, the pay is thin and deep, the oil is light, the viscosity is low, and the oil satu-
Fig. 46.35-Injection
and production
ration at the start of the flood was low. The reservoir properties are given in Table 46.28. The fireflood started in 1%7 with six 8O-acre five-spots. Additional wells were included so that it covered 960 acres in its final stage. The pilot area is shown in Fig. 46.39. The injection and production data in the 4YGyear period of its operation are given in Figs. 46.40 and 46.4 1, respectively. Between Feb. 1967 and July 1971, total air injected was 13,754X lo6 scf and water injected was 10,818 x lo3 bbl, giving a WAR of 0.79 bbl/103 scf. The total oil production was 646,776 bbl. This gives an AOR of 21.3~ lo3 scfibbl. The area1 sweep by the greaterthan-350°F zone was 50%. Combining with a vertical sweep of 28%, the volumetric sweep was only 14%. Asphalt Ridge, UT (DOE) 130-Extremely Viscous Tar, Combination Reverse/Forward Combustion. The Northwest Asphalt Ridge deposit is located in northeast Utah, near the city of Vernal. The fireflood conducted
history,
West Heide,oerg
field,
THERMAL
46-31
RECOVERY
Fig. 46.36-lsopachous
map, net oil, Poth “A”
in this deposit is interesting because it attempted to use a combination of reverse and forward combustion for the recovery of oil from tar sands. The reservoir properties are given in Table 46.29. The U.S. DOE conducted two fireflood tests in the Asphalt Ridge area. The first, conducted in 1975, demonstrated the feasibility of using reverse combustion to recover oil in the tar sand. The second tested a combination of reverse combustion and forward combustion during the period from Aug. 1977 to Feb. 1978. The location of the test sites and well arrangements are shown in Fig. 46.42. In both tests, the line drive was on a small area of 120~40 ft, covering only 0.11 acres. In the second test, several echoings of reverse and forward combustion phases were noticed in the northwest area, as seen from the temperature variations at observation Well 203 (Fig. 46.43). The reverse combustion phase had an areal sweep of 95 % and vertical sweep of 9 1% , giving a volumetric sweep of 86%. The echoing forward combustion phase had an area1 sweep of 75 % and vertical sweep of 44 % , giving a volumetric sweep of only 33%. The produced oil was of better quality than the original bitumen, with the pour point reduced from 140 to 25°F and the amount of residue lowered from 62 to 35 wt% . Forest Hill, TX (Air Products-Greenwich) Is3 Oxygen-Enriched Air. The Forest Hill field is located in Wood County, TX. The significance of the field test lies in the use of oxygen-enriched air for the fireflood. The reservoir properties are given in Table 46.30. The field was on primary production in 1964. Air injection started in 1976. One of the air injectors was switched to oxygen-enriched air in 1980. The test site is shown in Fig. 46.44. As seen in Fig. 46.45, during a 2-year period, the oxygen concentration in the injected gas ranged from 2 1 to 90%. The test showed that essentially pure oxygen can be handled and injected safely in a typical oilfield environment. Short of any definitive comparison, the test only hinted that using enriched air might produce oil faster than using air only.
sand, Gloriana
field, TX.
Thermal Properties Only some selected thermal properties of the rock/fluid systems encountered in the thermal recovery projects will be presented briefly. A more complete compilation of tables and figures has been included in Appendix B of Ref. 154. Oil Viscosities The viscosity-temperature relationships for representative heavy-oil deposits are shown in Fig.46.46. Oil viscosities should be measured experimentally. In the absence of experimental data, the viscosities can be estimated by charts (Fig. 46.47 to 46.49)‘55-‘57 and equations. Is8 Beggs and Robinson Is8 suggested the following equations for estimating viscosities of live oils. Dead-oil viscosity is first calculated: &,~=lo*-l,
.
.... . ..
. . . . .(74)
where pLodequals the viscosity of dead oil (gas-free oil) at T, cp. py~-I.163
Y=lO’,
,
. . . . . . . . . . .
. . . . . . . . . . . . . . .
(75)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..(76)
and Z=3.0324-0.02023
yo. . . . .
..
....
.(77)
where y0 equals the oil gravity, “API, and Tis the temperature, “F. Live-oil viscosity is calculated next. p=&,,dB,
..
........
... ...
..
(78)
46-32
PETROLEUM
OlORlANA 001
Fig. 46.37-GOR
‘
AIR
POIW
‘A’
UN11
INUCllON
and air injection
VS
history,
OLORIANA 011
POlH
PROOUCIION
IlYE
Gloriana
‘4
UNIT
VI
1lMt
field.
0 :
Fig. 46.38-011
production
history,
Gloriana
field.
ENGINEERING
HANDBOOK
THERMAL
RECOVERY
46-33
AlRlWATER RATIO SCFlBBL
AIR INJ.PRESS. PSI
@T rno-nrl""
I
i
-- '
WATER INJ.RAlE EBI,/DAY
4cm mo n ”
., 4b f 0’
AIR
1967
1%8
INJ .RATE
1969
Fig. 46.40-Injection
history,
MMCFlDAY
1970
1971
Sloss field COFCAW
1972 pilot
PHAS,. \
WATER PROO.RATE
EBlr /DAY I I-L
-
PROD.RATE MCFlDAY
0 PRODUCING
WELL
A
INJECTION WELL +
Fig. 46.39-Sloss
TABLE
unit,
NE.
46.26--RESERVOIR ROCK AND FLUID DATA, SLOSS FIELD, NE
46.29-RESERVOIR DATA, ASPHALT
Depth, ft Net thickness, fl Porosity, 910 Permeability, md Saturated Extracted Oil gravity, OAPI Reservoir temperature, "F Oil viscosity at 60°F, Cp Pour point, OF Saturations at start, % Oil Water
1967 Fig. 46.41-Production
1968
lW9 history,
1970
1971
Sloss field COFCAW
pilot
PROPERTY
6,200 14.3 19.3 191 38.0 200 2,274
Depth, ft Net thickness, ft Porosity, % Permeability, md Oil gravity, OAPI Reservoir temperature, 'F Reservoir pressure, psig Oil viscosity at 200°F, cp Oil saturation al start, O/o
TABLE
DRY HOLE
0.8 2oto
ROCK AND FLUID RIDGE FIELD, UT
40
PROPERTY
350 13.1 31.1
a5 675 14 52
> 1 ,ooo,ooo 140 65 2.4
Fig. 46.42-LETC
field site, Asphalt
Ridge
deposit,
UT.
PETROLEUM
46-34
TABLE
46.30-RESERVOIR DATA, FOREST
ENGINEERING
HANDBOOK
ROCK AND FLUID HILL FIELD, TX
PROPERTY
Depth, ft Net thickness, ft Porosity, O/o Permeability, md Oil gravity, OAPI Reservoir temperature, OF Oil viscosity at 185OF, cp Saturations at start, % Oil Water
Fig. 46.43-Maximum temperature Ridge deposit.
4,800 15 27.7 626 10 185 1,002 64 36
vs. time, Welt 203, Asphalt
,--
PEACE RIVER
LLOYDMINSTER ’ .IIESEn”Ol”
1
IEMI’Cl,*TI,IIE
Fig. 46.46-Viscosity/temperature relationships live heavy oil deposits.
for representa-
where A= 10.715@, + 100) -OS’~, Fig. 46.44-Forest
. . . . . . . . . . . . . . . (79)
Hill field, TX.
B=5.44(R,+150)-0.338,
.. ..
.
.
. . (80)
and R, :s the solution gas/oil ratio, scf/STB. Relative Permeability
Curves
Relative permeability data should be determined experimentally. In the absence of experimental data, the following equations may be used for rough estimation. According to Brooks and Corey, 159 k, =(S,,,*)5,
.. .. ......... .. ..
k,=(1-S,*)2(1-Sw*2),
s Fig. 46.45-Injection
history,
Well 32, Forest
Hill field.
w
*=
SW
...
.
(81)
,. .....
.(82)
-Siw )
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1 -ISi,
where Si, is the irreducible
water saturation,
.
.
.
(83)
percent.
THE RMAL
RECC IVERY
46-35
AT 100.
r.
h ATYOSCWLnIC PRLSSURL
tom
1000 600 y n
600 ,oo 400
g
100
;
200
::
J
100
FORYULA:
60 60
---
ABSOLUTE
vIscosITY
AT
l00.F
------27, 29,420
(Cpl*
EXTQAPOLATED
ho-ll)
I
.01 IO
! 1
I
I3
60 CR”DE2001L
CR2~“ITY.
&.
I.
*T”KPF
Fig. 46.47-Dead
‘I\ONO
ATzw”ER)PC
PR&“RE
oil viscosity.
lo4
10
Fig. 46.48-Universal
temperature/viscosity
chart.
66
PETROLEUM
46-36
. 6 7
6 9
FIN0 A CR”OE
OIL
CU FT I BBL AT THE
AN0
SAME
PROCEOURE: 1
SCALE GAS/OIL
1
REAO
THE GAS-SATUR4TED
“AvING
VISCOSITY
GAS/OIL
DEAO OIL VISCOS1TY
LOCATE
RATIO
1.50 CP ON
1 AN0 LINE.
ANSWER.
OIL VISCOSITY
SOLUTION
RATIO
OF OF 600
OF I.50 CP.
ALL
TEMPERATURE.
(A8SCISSA THE
A
SCALE
WE
DEAO OIL VISCOSITY
GO UP VERTICALLY
THEN 0.56
GO LEFT CP. ON
I OROINATE
THE
TO THE
600
MORIZONTALLY GAS-SATURATED
I
Fig. 46.49-Live
oil viscosity.
TO
ENGINEERING
HANDBOOK
rHERMAL
RECOVERY
46-37
According to Somerton, 160 for unconsolidated Sj,=0.211+2.0x10-4T+1.1x10-6T2,
sand,
_._.. (84)
where T is the temperature, “F. The effect of temperature on irreducible water saturation and relative permeability of unconsolidated sands has been studied by Poston et al. 16’Some of their results are given in Figs. 46.50 through 46.52. The effect of temperature on relative and absolute permeabilities of consolidated sandstones has been studied by Weinbrandt et al. ‘62 Some of their results are given in Figs. 46.53 through 46.56. PV Compressibility The compressibility of unconsolidated, Arkosic sands was measured by Sawabini et al. ‘63 Fig. 46.57 shows that the effective PV compressibility lies in the range between 10e4 and 10m3 psi-l, about 2 to 3 orders of magnitude higher than the normally accepted figure of IO -6 psi -I for consolidated sandstones. In Fig. 46.57, pro is the total overburden pressure, psi, and pP is the pore pressure, psi.
oj #)
loo
Is0
200
300
TEYWIAIURE,°F Fig.
of temperature on irreducible water sand, and natural sand.
46.50-Effect
satura-
tion, Houston 40
Thermal Conductivity 30
Thermal behavior of unconsolidated oil sands was studied by Somerton et al. K+J Fig. 46.58 shows how thermal conductivity of Kern River oil sands varies with brine saturation. Vaporization
Equilibrium
Vaporization equilibrium of an oil fraction is described by the equilibrium vaporization constant, K, which is defined as
20 s : CA0IO
I
I
I
I
100
IS0
200
26c
0
K=x,
50
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .@5) X
where y is the mol fraction in vapor phase and x is the mol fraction in liquid phase. Poettmann and Mayland I65 in 1949 published a series of charts on equilibrium constants of various oil fractions with normal boiling points of 300”F, 4OO”F, etc., up to 1,OOO”F. To illustrate how K values vary with temperature and pressure, the figure for normal boiling point=5OO”F is shown in Fig. 46.59. More recently, L.ee ef al. 166presented equilibrium constants of oil fractions with 100°F boiling ranges. For example, Fraction 1 has the boiling range up to 3OO”F, Fraction 2 boiling between 300 and 400”F, and Fraction 6 boiling above 700°F. Figs. 46.60 and 46.61 show the effects of pressure and temperature, respectively. on the K values for these oil fractions as well as N 2, CH4, and co*.
300
TEIJ~PEPATURE,~F Fig. 46.51-Effect
of temperature
on ROS, natural
sand.
WATER
Chemical Kinetics Chemical reactions taking place in an in-situ combustion process are considered to fall into three types: (1) lowtemperature oxidation, (2) fuel deposition or coke formation, and (3) combustion. The kinetic data of these three types of reactions reported by various authors have been summarized in the paper by Fassihi et al. 16’and will not be reproduced here.
-I 0
20
40 WATER
Fig.
46.52-Water tures,
80
60 SATURATION,
100
‘L
and oil relative permeability Houston sand, 80-cp 011.
at four tempera-
PETROLEUM
46-38
I
ENGINEERING
HANDBOOK
4.
I
zsoo48
5. z
2000
k
s c ;
5. bW.6
;
29 ISOO-
iTi H
l 4i
2 01 60
TEMPERATURE.
Fig. 46.53-Effect tion,
1 180
140
loo
‘F
of temperature on irreducible sandstone cores.
water
satura-
1000
5’ i I
l2
A1
5oL---l 60
TEMPERATURE.
Fig. 46.56-Effect of temperature sandstone cores.
0: 60
TEMPERATURE.
Fig. 46.54-Effect
of temperature
lF
on absolute
permeability,
180
140
100
180
140
100
‘F
on ROS, sandstone
cores.
to*
%
EFFECTIVE
PiiESSURE,
Fig. 46.57-Effective PV compressibility, oil sand.
oo- -20 WATER
Fig. 46.55-Water tures,
--~
40 60 SATURATION,
and oil relative permeability Core 4, Boise sandstone.
6 %
100
at two tempera-
PSI
unconsolidated
Arkosic
THERMAL
RECOVERY
hsv
.0.?35-r.30~*sw
+
POROSITY RANGES: a 0.28-0.30 ---0 0.31 -0.33 -A 0.34 -0.37
BRINE SATURATION, Fig. 46.56-Thermal
1000 1
conductivity
2000
1500 I
SW
of Kern River oil sands.
2500
3000
Fig. 46.59-Equilibrium point-500°F.
P(rksld
400 IO
500
‘c
vaporization
constant,
600
700 r
I
I
normal
boiling
T(OF)
&& 0
co2
-
I-
y
PREDICTED
.,
EXPERIMENTAL
FRACTION A-AI 5ow
A
., 0,
0.1
-
0.01
-
. *,
0
6 &-/ IL ISCCO
loo00
zoo00
p(hPol
0 cm k Fig. 46.60-Effect of pressure A at 260%.
on equilibrium
K values for Crude
n/ x0
1
,
1
I
250
3al
350
400
T(‘C)
Fig. 46.61-Effect of temperature on equilibrium Crude 8 at 1,514.7 psia.
K values
of
46-40
PETROLEUMENGINEERING
HANDBOOK
TABLE46.31-SATURATEDSTEAMTABLE Specific Absolute
Pressure,
0.08865 14.696 50.0 100.0 150.0 200.0 250.0 300.0 400.0 500.0 600.0 700.0 800.0 900.0 l,ooo.o 1.200.0 1,400.o 1,600.O 1,800.O 2,000.0 2,200.o 2,400.O 2,600.O 2,800.O 3,000.0 X208.2'
Temperature
32018 212.00 281.02 327.82 358.43 381.80 400.97 417.35 444.60 467.01 486.20 503.08 518.21 531.95 544.58 567.19 587.07 604.67 621.02 635.80 649.45 662.11 673.91 684.96 695.33 705.47
Volume,
Saturated Liquid, "L
Evaporate,
0.016022 0.016719 0.017274 0.017740 0.01809 0.01839 0.01865 0.01889 0.01934 0.01975 0.02013 0.02050 0.02087 0.02123 0.02159 0.02232 0.02307 0.02387 0.02472 0.02565 0.02669 0.02790 0.02938 0.03134 0.03428 0.05078
3,302.4 26.782 8.4967 4.4133 2.9958 2.2689 1.82452 1.52384 1.14162 0.90787 0.74962 0.63505 0.54809 0.47968 0.42436 0.34013 0.27871 0.23159 0.19390 0.16266 0.13603 0.11287 0.09172 0.07171 0.05073 0.00000
v tg
Steam Properties An abbreviated steam table’68 is given in Table 46.31.
Nomenclature a = air requirement, 106, scf/acre-ft A = heated area at time t, sq ft, or quantities defined by Eqs. 9 and 79 A’ = quantity defined by Eq. 13 B = quantities defined by Eqs. 10 and 80 B’ = quantity defined by Eq. 14 C, = fuel content, lbmicu ft C,, = heat capacity of oil, Btu/lbm-“F, or concentration of oil, lbm molicu ft C, = heat capacity of rock, Btuilbm-“F C,, = heat capacity of steam, Btuilbm-“F C,,. = heat capacity of water, Btuilbm-“F Co2 = concentration of oxygen, Ibm molicu ft C, = quantity defined by Eqs. 58 and 60 C2 = quantity defined by Eqs. 59 and 61 D = depth, ft E = activation energy, Btuilbm mol Eh = thermal (heat) efficiency, fraction Eo2 = oxygen utilization efficiency, fraction E, = overall oil recovery ERU = recovery efficiency in the unburned region, fraction vh = volumetric sweep efficiency of the burning front, fraction f‘,, = steam quality at the beginning of the pipe segment, fraction
E
cu ftllbm Saturated Vapor,
Enthalpy.
Btullbm
Vg
Saturated Liquid, H,
Evaporate, L.
Saturated Vapor, H,
3,302.4 26.799 8.5140 4.4310 3.0139 2.2873 1,84317 1.54274 1.16095 0.92762 0.76975 0.65556 0.56896 0.50091 0.44596 0.36245 0.30178 0.25545 0.21861 0.18831 0.16272 0.14076 0.12110 0.10305 0.08500 0.05078
0.0003 180.17 250.2 298.5 330.6 355.5 376.1 394.0 424.2 449.5 471.7 491.6 509.8 526.7 542.6 571.9 598.8 624.2 648.5 672.1 695.5 719.0 744.5 770.7 801.8 906.0
1,075.5 970.3 923.9 888.6 863.4 842.8 825.0 808.9 780.4 755.1 732.0 710.2 689.6 669.7 650.4 613.0 576.5 540.3 503.8 466.2 426.7 384.8 337.6 285.1 218.4 0.0
1,075.5 t,150.5 1,174.l 1,187.2 1,194.i 1,198.3 1,201.l 1,202.g 1,204.6 1,204.7 1,203.7 1,201.8 1,199.4 1,196.4 1,192.g 1,184.8 1,175.3 1,164.5 1,152.3 1,138.3 1,122.2 1.103.7 1,082.O 1.055.8 1,020.3 906.0
f.Yfs2 = steam quality at the end of the pipe segment, fraction f(t) = transient heat conduction time function for earth, dimensionless F a0 = AOR F,., = COZ/CO ratio in produced gas F HC = atomic H/C ratio F, = ratio of stimulated to unstimulated productivity indices, dimensionless F,?, = steam/oil ratio, STBiSTB F MAO, = total produced WOR. STBiSTB h = pay thickness, ft, or convection heat transfer coefficient, Btu/hr-sq ft-“F h’ = convection heat transfer coefficient based on insulation outside surface, Btulhr-sq ft-“F hf = cnthalpy of liquid water at T above 32”F, Btuilbm h, = total thickness of all sands, ft HO, = enthalpy of oil and gas Btuilbm H,, = enthalpy of water carried by oil based on a STB of oil, Btu/STB oil H WR = enthalpy of water at reservoir temperature, Btu/lbm H,,, = enthalpy of water at steam temperature, Btu/lbm IUI -~ cumulative air injection, 10’ scf i, = steam injection rate, B/D I = radiation heat transfer coefficient, Btulhr-sq ft-“F
THERMAL
RECOVERY
I’ = radiation heat transfer coefficient based on insulation outside surface. Btuihrsq ft-“F J, = unstimulated (cold) productivity Index, STBiD-psi k = absolute permeability, md k’ = pre-exponential factor k,,,., = thermal conductivity of the casing material, Btu/hr-sq ft-“F k,IC.P= thermal conductivity of the cement. Btu/hr-ft-“F k,,f = thermal conductivity of the formation, Btu/D-ft-“F k,,;,, = thermal conductivity of insulation material, Btuihr-ft-“F k ho = overburden thermal conducitivity, Btu/hr-ft-“F k,,, = relative permeability to oil, fraction k,,,. = relative permeability to water, fraction K = equilibrium vaporization constant L = pipe length, ft L,, = latent heat of steam, Btuilbm L,l = latent heat of vaporization at top of interval, Btuilbm L,.? = latent heat of vaporization at bottom of interval, Btuilbm m.\,, = total mass of steam injected, Ibm M = volumetric heat capacity. Btuicu ft-“F N = OOIP, bbl N, = number of sands N.,, = oil in place at start of project, bbl AN.,, = cumulative incremental oil production, bbl PO = static formation pressure at external radius, psia = pore pressure, psi PI, P,~ = saturated vapor pressure of water at T, psia P ,o = total overburden pressure, psi p,,, = bottomhole pressure, psia p / = pressure at top of interval, psia p2 = pressure at bottom of interval, psia Ap = frictional pressure drop over interval, psia 40 = oil displacement rate, B/D qoC. = cold oil production rate, B/D qnlr= hot oil production rate, B/D Qi,, = heat remaining in heated zone, Btu Q;, = total heat injection, Btu Qri = heat injection rate, Btuihr Q,., = heat loss along the segment, Btuihr Q, = heat removal rate at time t. BtuiD rd = radius to cement/formation interface, ft r<.; = inside radius of casing. ft rccr = outside radius of casing. ft rc, = external radius, ft rf, = radius of region originally heated. ft r in = outside radius of insulation surface, ft rrr = inside radius of tubing, ft
46-41
r/,1 = outside radius of pipe. tt r,,.
R R,, R, S,s Sir, S;,,. S,, S,; S,,,; S,,.* t
tc fg t;
= = = = = = = = = = = = = = =
T =
T,, = Td = T,.; = Tj; = I$ = T;,,j = TR = T, = T,s, =
u c0 =
U,i =
ur,
=
v t= v,,. = F’R = V,., V, = v,, VT =
well radius, ft gas constant solution GOR. scf/STB total produced GOR. scf/STB gas saturation, fraction irreducible oil saturation, fraction irreducible water saturation. percent oil saturation at start, fraction initial oil saturation, fraction initial water saturation, fraction normalized water saturation, fraction time since injection, hours critical time, hours dimensionless time time of injection for the current cycle, days average temperature of the heated region, rr,. < r< rh , at any time t, “F atmospheric temperature, “F temperature at cement/formation interface, “F temperature at casing inside surface, “F initial formation temperature, “F temperature of fluid, “F injection temperature, “F original reservoir temperature, “F steam temperature, “F formation temperature at ground surface, “F overall heat transfer coefficient based on outside casing surface, Btuihr-sq fi-“F overall heat transfer coefficient based on inside radius of pipe or tubing, Btuihr-sq ft-“F overall heat transfer coefficient based on outside tubing surface, Btu/D-sq ft-“F specific volume of total fluid, cu ft/lbm wind velocity, mile/hr fuel burned, bbl unit solution for component conduction problems in the r and z directions* average values of V, and V; for O
w = M’s = x = X = v = i = (Y = QY,>=
Arrhenius reaction rate mass rate of steam, Ibm/hr mole fraction in liquid phase quantity defined by Eq. 66 mole fraction in vapor phase quantity defined by Eq. 65 thermal diffusivity, sq ft/D overburnden thermal diffusivity, ft/D
sq
‘These symbols have no physical connotation They are simply mathemallcal symbols
PETROLEUM
46-42
0 = dummy variable in Eq. 27 6 = energy removed with the produced fluids. dimensionless 8 = dip angle, degrees P 0 = oil viscosity, cp kLoC= cold oil viscosity, cp p,,d = viscosity of dead oil (gas-free oil) at T, cP poh = hot Oil ViSCOSity, cp = density of oil, rock grain, and water, lbmicu ft 4 = porosity, fraction
Po.Pr.P,,.
ENGINEERING
HANDBOOK
F,, (in m3im3)=18.744+0.004767D-0.16693h -0.89814k-0.5915~L,,
-0.0009767kh. PO
- 14.79S,
.
C,n (in kg/m 3, = - I .9222 + 0.137695h + 1.85029k
+35.723,, +0.012887kh /*0 -0.0099302Fcc + 1 +
Key Equations in SI Units
FCC + 1
lx=
1.0444pL.. . . . (69)
FHC cm 2 >
.
.
0.01776(12+FHc)E,~ h=7.165v,.0~6/rin0.4.
.
.
..
. .
a (in std m3/m3)=
-v,,)%
108.356+2.75367/~+229.4773,, +16.073k.
.
+9.806~lO-~E-Ap. &‘II
F,,,, *=
Q,d
Ahd(S,; -sju)
.
. . . . (20) F,,, =
..
.
.
(30)
-1:;oj EL’ b-E,,h)ERu 1 [(4s,a+@,(I
(in std m3/m3)=3820.4+12.97h+192.20k
. . . . . . . . . . . . . . . . . . . . . . . . . . . . (73)
pLoc.lnL r 111
where a is A is C, is D is F,, is F,, is F Jo* is h is h is I,~ is k is N, is p’s are qoc is Q, is .
0.4273, -0.004429h
[
in std m3/m3, in m2, in kg/m3, in m, in std m3 /m3, in m3/m3, in m3/m3, in kJ/m2 .h*K (Eqs. 2 through 4), in m, in std m3, in pm2, in m3, in kPa, in m’/d, in m3/h, IS m m, IS m m, is in h. is in m‘3 /kg, is in kg/h, is in kglh, is in Pa.s, and is in Pa.s.
> 1x, .... (64) 0.25
where
x=
i&o2 W,444J1(1-~) ’
F,,
(in m3/m3)=
li
. (71)
(p,-p,,,)............(42)
4oc =
Y=O.2639
..
. . . . . . . . . . . . . . . . . . . . . . . . . . . . (72) F,,
O.O005427kk,,h
. . . . . (70)
(3)
2
p2=pI +7.816x10~r2(v,,
(68)
-0.011253+0.000091170
+0.0005180h-0.077758
+0.00003467~
t-0.5120@, P0
rjn rli
/)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (67)
t v, v, ws p. pot
THERMAL
References I
2 3
4 5
9
IO II
I2 13. 14.
15.
16
17. 18 19 20. 21. 22. 23. 24.
25. 26.
27. 28. 29. 30. 31.
32.
46-43
RECOVERY
Farouq Ah. SM.: “Steam Injection,” Sewn&lv uncl Terrrar) Oil Rrrw~en Processes. Interstate Oil Compact Commission, Oklahoma City (Sept. 1974) Chap. 4. McNeil. J.S. and Moss. J.T.: “Oil Recovery by In-Situ Combustion.” Per. Ejtx. (July 19.58) B-29-B-42. Berry. V.J. Jr. and Parrish. D.R.: “A Theoretical Analysis of Heat Flow in Reverse Combustion,” Twns., AIME (1960) 219. 124-31. Dietz, D.N. and Weijdema. J.: “Reverse Combustion Seldom Feasible.” Producer.s Monrhi~ (May 1968) IO. Smith. F.W. and Perkins, T.K.: “Experimental and Numerical Simulation Studies of the Wet Combustion Recovery Process.” J. Cdn. Pa. Tuch. (July-Sept. 1973) 44-54. Stovall. S.L.: “Recovery of Oil from Depleted Sands by Means of Dry Steam,” Oil Week/y (Aug. 13, 1934) 17-24. Grant. B.R. and Szaaz. S.E.: “Development of Underground Heat Wave for Oil Recovery.” Tram., AIME (1954) 201. 108-18. Kuhn. C.S. and Koch, R.L.. “In-Situ Combustion-Newest Method of Increasing Oil Recovery,” Oil and Grrs J. (Aug. IO, 1953) 52, 92-96, 113. 114. Trantham. J.C. and Marx. J.W.: “Bellamy Field Tests: Oil from Tar by Counterflow Underground Burning.” J. Per. Tech. (Jan. AIME. 237. 1966) 109-15: Trm~.. Giusti. L.E.: “CSV Makes Steam Soak Work in Venezuela Field,” Oil md Gas 1. (Nov. 4, 1974) 88-93. Stokes. D.D. and Doscher. T.M.: “Shell Makes a Success of Steam Flood at Yorba Ltnda.” Or/ cind Gas J. (Sept. 2. 1974) 71-76. Dietz, D.N.: “Wet Underground Combustion, State-of-the-Art,” J. Pcjr. Twh. (May 1970) 605-17: Tram., AIME. 249. “Steam Dominates Enhanced Oil Recovery.” Oil crud Gw J. (April 5. 1982) 139-59. “Experts Assess Status and Outlook for Thermal, Chemical. and CO1 Miscible Flooding Processes.” J. PPI. Tech. (July 1983) 1279-92. Johnson. L.A. Jr. rr ul.: “An Echoing In-Situ Combustion Oil Recovery Pmject in the Utah Tar Sand.” J. PH. T&I (Feb. 1980) 2955304 Enhmcw/ Oil Recoined Porenrid in rhr Uniwd Srcues, Report by Lewin and Assocs. for Office of Technology Assessment (Jan. 1978) 40-41. Wdlman. B.T. 6’1dl.: “Laboratory Studies of Oil Recovery by Steam Injectton.” Truns., AIME (1961) 222. 681-90. McAdams, W.H.: Hmt Transmission. third edttion. McGraw-Hill Book Co. Inc., New York City (1954) 261. Ramey. H.J. Jr.: “Wellbore Heat Transmtssion.” J. Pet. Tech. (April 1962) 427-35. Saiter. A.: “Heat Losses During Flow of Steam Down a Wellbore.” J. Pe/. Tech. (July IY65) 845-5 I. Willhite. G.P.: “Overall-All Heat Transfer Coefficients in Steam and Hot Water Injection Wells.” J. Per. Trch. (May 1967) 607-15. Earlougher. R.C. Jr.: “Some Practical Considerations in the Destgn of Steam Injection Wells,” J. Pet. Tech. (Jan. 1969) 79-86. Beggs. H.D. and Brill. T.P.: “A Study of Two-Phase Flow in Inclined Pipes.” J. Per. Tech. (May 1973) 607-14. Farouq Ali, S.M.: “A Comprehensive Wellbore Steam/Water Flow Model or Steam Injection and Geothermal Applications.’ .Soc~. Pet. En+ J. (Oct. 1981) 527-34. Marx. J.W. and Langenheim, R N.: “Reservoir Heating by Hot Flutd Injection.” Truns.. AIME (1959) 216. 312-15 Evans. J.G.: “Heat Loss During the Injection of Steam lnto a 5-Spot.” paper presented as term project in PNG 515. Pennsylvania State U.. University Park (June 1960). Ramey. H.J. Jr.: “Discussion of Reservoir Heating of Hot Fluid Injectton.” Trms., AIME (1959) 216. 363-65. Mandl. G. and Volek. C.W.: “Heat and Masg Transport in Steam Drive Processes.” .Soc Per. Ore. J. (March 1969) S9-79. Myhill, N.A. and Stegemeier, G:i.: “Steam Drive Correlattons and Prediction.” J. Per. Ted. (Feb. 1978) 173-82. Neurnan. C.H.: “A Gravity Override Model ofSteamdrive.” J. Per. Twh. (Jan. 1985) 163-69. Doscher. T.M. and Ghassemi. F.: “The Influence ofOil Viscowy and Thickness on the Steam Drive.” J. Pd. Twh. (Feb. 1983) 291-98. Vogel, J.V: “Stmplrtied Heat Calculations for Steamlloods,” J. Per. Tech. (July 1984) 1127-36.
33.
34. 35. 36. 37. 38.
39.
40. 41.
Boberg. T.C. and Lantz, R.B.: “Calculation ot the Production Rate ofaThermally Stimulated Weli,” J. Pet. Tech. (Dec. 1966) 1613-23. Boberg, T.C. and West, R.C.C.: “Correlation of Steam Stimulation Performance.” J. Put. Tech. (Nov. 1972) 1367-68. Coats, K.H. etrrl.: “Three-Dimensional Simulation of Steamflooding,” Sot. Pet. Enc. J. (Dec. 1974) 573-92. Coats, K.H.: “Simulationof Steamflooding with Diatillatton and Solution Gas,” Sot. Per. Enx. J. (Oct. 1976) 235-47. Coats. K.H.: “A Highly Implicit Steamflood Model.” Sot. PC!. Enn. J. (Oct. 1978) 369-83. Crookston, R.B., Culham, W.E.. and Chen, W.H.: “Numerical Simulatton Model for Thermal Recovery Processes,” Sot,. Per. Eng. J.(Feb. 1979) 37-58. Youngren, G.K.: “Development and Applications of an In-Situ Combustion Reservoir Simulator.” Sot. Pet. Eng. J. (Feb. 1980) 39-5 I Coats. K.H.: “In-Situ Combustion Model,” Sot. Per. En,e. J. (Dec. 1980) 533-54. Grabowski, J.W. era/.: “A Fully Implicit General Purpose FiniteDifference Thermal Model for In-Situ Combustion and Steam,” paper SPE 8396 presented at the 1979 SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 23-26.
42. Alexander, I.D.. Martin, W.L., and Dew. J.N.: “Factors Affecting Fuel Availability and Composition During In-Situ Combuation.” J. Per. Tech. (Oct. 1962) 1154-64 43. Showalter, W.E.: “Combustion-Drive Tests.” Sot. Pet. Eng J. (March 1963) 53-58. 44. Parrish. D.R. and Craig. F.F. Jr.: “Laboratory Study of a Combination of Forward Combustion and Waterflooding-The COFCAW Process,” J. Per. Tech. (June 1969) 753-61. 45. Burger, J.G. and Sahuquet. B.C.: “Laboratory Research on Wet Combustion.” J. Pet. Tech. (Oct. 1973) 1137-46. 46. Garon, A.M. and Wygal. R.J. Jr.: “A Laboratory Investigation of Firewater Flooding,” Sot. Pet. En,q. J. (Dec. 1974) 537-44. 47. Moss. J.T. and Cady. G.V.: “Laboratory Investigation of the Oxygen Combustion Process for Heavy 011 Recovery,” paper SPE 10706 presented at the 1982 SPE California Regional Meeting, San Francisco, March 24-26. 48. Pursley, S.A.: “Experimental Simulation of Thermal Recovery Processes,” Pmc,. , Heavy Oil Sympostum, Maracaibo, Venezuela (1974). 49. Huygen, H.H.A.: “Laboratory Steamfoods in Half of a FiveSpot.” paper SPE 6171 presented at the 1976 Annual Technical Conference and Exhibition. New Orleans, Oct. 3-6. 50. Ehrlich, R.: “Laboratory Investigation of Steam Displacement in the Wabasca Grand Rapids ‘A’ Sand,” Oil Smds of CanadaVenezueku 1977, CIM (1978) Special Vol. 51. Prats. M.: “Peace River Steam Drive Scaled Model Experiments,” Oii Sands of Cmada-Ven:uc41 1977. CIM (1978) Special Vol. 52. Doscher, T.M. and Huane. W.: “Steam-Drive Performance Judged Quickly from Use of Physical Models.” Oil and Gas J. (Oct. 22, 1979) 52-57. 53. Singhal. A.K.: “Physical Model Study of Inverted Seven-Spot Steamfloods in a Pool Containing Conventional Heavy Oil,” J. C&t. Per. Tech. (July-Sept. 1980) 123-34. 54. Binder, G.G. era/.: “Scaled-Model Tests of In-Situ Combustion in Massive Unconsolidated Sands,” Proc,. , 7th World Pet. Gong.. Mexico City (1967). 55. Pujol. L. and Boberg. T.C.. “Scaling Accuracy of Laboratory Steamflooding Models,” paper SPE 4191 presented at the 1972 SPE California Regional Meeting. Bakersfield. Nov. 8-10. 56. Stegemeier. G.L., Laumbach. D.D., and Volek, C W.: “Representing Steam Processes with Vacuum Models,” Sot. Pa. Grg, J. (June 1980) 15 l-74. 57. Farouq Ali. S.M.: “Current Status of Steam Injection as a Heavy Oil Recovery Method.” J. G/n. Per. Twh. (Jan.-March 1974) I-15. 58. Geffen. T.M.: “Oil Production to Expect from Known Technology.” Oil md Gas J. (May 7. 1973) 66-76. 59. Lewin and Assocs. Inc. : Tha Potmricrls und Eummics ofEnhowecl Oil Recowr,?, Federal Energy Administration (April 1976) Report 876122 I, 2-6. 60. lyoho. A.W.: “Selecting Enhanced Oil Recovery Processes.” Wdd Oil (Nov. 1978) 61-64 61. Chu. C.: “State-of-the-Art Review of Steamtlood Field Projects,” paper SPE 11733 presented at the 1983 SPE California Regional Meeting, Ventura, March 23-25.
PETROLEUM
46-44
62. 63. 64. 65.
66.
67. 6X. 69.
70.
71.
72.
73. 74. 7s. 76.
77.
78.
79.
80.
RI.
82. 83.
84
85.
X6
Chu. C.: “A Study of Firetlood F~cld Protect\.” J. PHI. &/I. (Feb. 1977) 171-79. Chu. C. “State-ot-the-Art Review of Firetlood Ftcld Prrqccth.” J. Pr,i. Tech. (Jan. 1982) 19-X. Poettmann. F.H.’ “In-Situ Combustion: A Current Appraisal.” W&c/ Oil. Part I (April 1964). 124-28; Pan 2 (May 1963) 95-98. Blrvina, T.R.. Ascltinc. R.J.. and Kirk, R.S.: “Analyv\ ol a Steanl Drive Protect, Inglcwood Field. California,” J. Per. 7ec,i?. (Sept. 1969) Il41-50. Blevlnb. T.R. and Billingsley. R.H.: “The Ten-Pattern Stean(Dec. 1975). flood. Kern River Fteld. California.” J. Pet. lidi. I SOS- 14; 7i-,” J. PH. Ttrh. (March 1968) 295-302. Gate\. C F. and Ratney. H.J. Jr.: “Fteld Rewlts of South Belridge Thermal Recovery Experiment.” ‘frwz\. , AIME (19.58) 213. 236-44. Parrish. D.R. rr [il.: “A Tertiary COFCAW Pilot Test m the Sloss (June 1974) 667-75: Trtr,~.,., Field, Nchra\ka.” J. /‘<,I. 7d1. AlME. 257. Pnrrihh, D.R.. Pollock. C.C.. and Craig. F.F. Jr.. “Evaluation oi‘COFCAW as a Tertiary Recovery Method. Slow Field. Nchraaka.” J. Per. T& (June 1974) 676-86: TUNIS., AIME, 257. Buxton, T.S. and Polock. C.E.: “The Sloss COFCAW PKIJeCtFurther Evaluation of Performance During dnd After Air In,@tion:’ J. PC,! TwIi. (Dec. 1974) 1439-48: Tru,~r., AIME. 257 Mo$s. J.T.. White. P D.. and McNeil. J.S.: “In-Situ Combw twn Process-Rewlts of a Five-Well Field Experiment in Southcm Oklahoma.” Trw>\. , AIME (1959) 216. 55-64 Parrish. D.R. PI cl/.: “Underground Combustion in the Shannon Pool. Wyoming.” J. Per. Tdl. (Feb. 1962) 197~205: Tr
90.
xx
89
HANDBOOK
“Slocutn Field.” ltnpm~d Oil RWO I cvy k-w/d Reporr.s. SPE ~ Richerdwn, TX (1976) 2. No I, 11%28. F.&rrlwd Oil Rccvl.~!:vFic/l Rqwrrs. SPE, Rtchardson. TX (1979) 5. No. 2. 291-97.
91. Pollock, C.B. and Buxton, T.S.: “Performance of B Forward Steamdrive Project-Nugget Reservoir, Winkleman Dome Field, Wyommg,” J. Prr. Tech. (Jan. 1969) 35+Kl. 92. “Winkleman Dome Field.” frnpwwd Oil Rec~myv Fidd Rcp~m. SPE. Richardson, TX (1975) 1, No. I, 155-62. E!&~ric(.d Oii R~c~nw~ Fir/d Rqxvrc, SPE. Richardson. TX (1980) 6, No. I. 41-44. 93. Herrerd, A.J.: “The M6 Steam Drive ProJect Design and Implementation.” J. Cdn. Per. Tee-h. (July-Sept. 1977) 62-83. Recovery Bemg Uxd on Lake 94. Herrera. A.J.: “Steam-Drike Mardcaibo Coastal Field.” Oilcirid GN(.J. (July 17. lY78) 74-80. 95
96
97
98
90
I00
IO1
102
I03
IO4
10s 106
107 IO8
IO9 I IO III I I?
Xl Richardwn. TX ( 1975) I. No. 7. 277-86: &
ENGINEERING
I I3
I I4 I I5
“Tia Juana Este Field. Marawn, S.A. ,” Glhowerl Oil Rrw~r~ Fwlcl Report.\, SPE. Richardson. TX (1978) 3, No 4. 751-62: &hw&/ 011 Rwowrv Field Rqxw/r, SPE. Richardson. TX (1982) 8. No. I? 75l-S3. Showalter. W.E. and MacLean. M.A. “Fireflood at Brea-Olinda Field, Orange County. California.” paper SPE 4763 presented at the 1974 SPE Symposium on Improved Oil Recovery, Tulsa. April 22-24. “Brea Oiinda Field,” I*nprowd 011 Rrcrn~~r~ Fdd Rqx~rt.s, SPE, Richardson. TX (1975) 1, No. I, IS- 18; Orhrrwc’d Of/ RPCOW~! Fiekl R~~pons. SPE, Richardson. TX (1981) 7, No. I, 407-08. Gates. C.F. and Sklar, I.: “Comhubtlon as a Primary Recocery Process-Midway Sunset Field,” J. Per. 7.cvh. (Aug. 1971) 9X1-86: Trur~s.. AIME. 251. Counihan, T.M.: “A Succes\l’ul In-Situ Combu\tton Pilot In the Midway Sunset Field, California,” paper SPE 6.525 prehented at the 1977 SPE Califomta Regional Meettng, Baker\fteld, Aprtl 13-1.5 Gates. C.F.. Jung, K.D.. and Surface. R A.: “In-Situ Combustion in the Tulare Formation, South Belrtdge Field. Kern County. CA,” .I Per. T&. (May 1978) 798-806: Trcw\. AIME. 265. Hewitt. C.H. and Morgan. J.T.: “The Fry In-Sttu Comhu\tion Te\t-Reservoir Characteristic\,” 1. PH. TK/I. (March lY65) 337-42: Trcrn.c., AIME, 234. Clark, G.A. e~ol.: “The Fry In-Situ Combustion Test-Field Operations.” J. F’cr. Teds. (March 196.5) 343-47: Trcrr~s., AIME. 234 Clark. G.A. ertil.: “The Fry In-Situ CombustionTest-Field Operations and Performance,” J. Prc Tc,rh. (March 1965) 348-53; Trcrm., AIME. 234. Earlougher. R.C. Jr.. Galloway, J.R . and Parsons, R.W.: “Performance of the Fry In-Situ Combustmn Project.” J. PH. T~~c~/I. (May 1970) 551-57. Bleaklcy. W.B.: “Fry Unit Fireflood Surwving Economic Pressures.“- Oil cm! Gas-J. (May 3. 1971) 92-97: Howell. J.C. and Peterson. M.E.: “The Frv In Situ Comhu\tton ProJect Performance and Economic Statu;.” paper SPE X.181 prebenled at the I979 SPE Annual Technical Confercncc and Exhibttion. Las Vegas. Sept. 23-26. Little, T.P.: “Successti~l Fixflooding of the Bellewe Flcld.“ &r Eng. /n/l. (Nov. 1975) 55-56. “Bellewe Field. Cities Service Oil Co..” li~,/~rrwe
THERMAL
RECOVERY
46.45
I4.L
135. 146.
119.
147.
(‘I 01.: .. Heavy Oil Recovery by In-Situ 120 Gadelle.‘C.P. Comhu&x-Two Field Caaca in Romania.” J. PH. Tmh. (Nov. 1981) ‘057-66. P.L. PI rrl.: “Flretlood of the P, 2 Sand Kcscrvoir 121. Terwilllger. in the Miga Field of Eastern Venezuela.” J.Pet.Tech.~.lan. 1975) Y-14 T.W. and McNeil. J.S.: “How to Engineer an In-Situ 122. N&on. Cm J. (June 5. 1961) 59. No. ‘3. Comhuwon Project.” O’I! o,rt/ X-65. 123. S&man. A.. BrIgham. W.E.. and Ramey, H.J. Jr.: “In-Situ Comhwtion Models ior the Steam Plateau and for Fleldwde 011 Recovery.” DOEiETIl2056-1 I. U S. DOE (June 1981). 124. Gates, C.F. and Ramq, H.J. Jr.: “A Method for Engmeerinp In-Situ Combustion 011 Recoverv Proiects.” J. Pc,rTd. (Feb. 1980) 285-94. C.W. and Pryor. J.A.: “Steam Distillation DTIVL’. Brea 125. V&k. Field. Calilhrnia.” J. Per.k/r. (Aug. 1972) X99-906. 126. Burke. R.E.: “Combu&n Proicct 1s Makmp a Profit.” Oi/a/zd Cm J. (Jan. 18. 1965) 44-46.127. Koch. R.L.: “Practical Use of Combustion Drive at West Newport Field.” Per. Dz,q. (Jan. 1965) 72-81. 128. Bowman. C.H: “A Two-Spot Comhustmn Recovery Project.” J Per. fdr. (Sept. 1965) 994-98. 129. Tewilliger. P.L.: “Flrctlooding Shallow Tar Sands-A Case Histow.” J. C&I. Per. Tdz. (Oct.-Dec. 1976) 41-4X. I so. J&son. L.A. ($1cri.: ” An Echomp In-Situ Comhu\tmn OilTVI11 (Feb. 1980) Recovcrv Proieci in a Utah Tar Sand.” J. fcdt. 295sioi _ .’ 131. Perry, C.W., Hertlherg. R.H.. and Stosur. J.J.: “The Status DI Enhanced Oil Recovery in the United States,“ Pmt., Tenth World Pet. Congres. Bucharest (1980) 3. 257-66. 132. Benham. A.L. and Poettmann. F.H.. “The Thermal Recovery Process-An Analyhia of Laboratory Combustion Data.” Trtr,r.\. , AIME (1958) 213, 83-85. 133. Caudle. B.H.. Hickman. B.M.. and Sllherberg. I.H.: “Performance of the Skewed Four-Sp)t Injection Pattern.” J. /‘cr. Twh. (Nov. 1968) 1315-19. “Silver134. Cady. G.V., Hoffman. S J.. and Scarborough, R.M. dale Combination Thermal Drive Project,” paper SPE 8904 presented at the 1980 SPE California Regional Meetmg. Los Angeles. April 9mII 135. de Haan. M.J. and Schenk. L.: “Pertormancc Analysis of a MaJor Steam Drive Project m the Tin Juana Field. Western Venczw la.”J. fcr. Td7. (Jan. 1969) I I l-19. 136. “Texas Fireflood Looks Like a Winner.” Oil crnd Gtry J. (Feb. 17. 1969) 52. 137. A~~Ju. B.I.: “Conversion of Steam Injection to Waterllood. East Coalinga Field.” J. Per. Twh. (Nov. 1974) 1227-32. 138. Gate\. C.F and Brewer. S.W.: “Steam Iniection into the D and E Zone, Tulare Formation, South Belridge Field. Kern County, California.” J. Put. TK~. (March 1975) 343-4X. 139. Gomaa, E.E.. Duerksen. J.H.. and Woo. P.T.: “Designing a Steamtlood Pilot in the Thick Monarch Sand of the Midwy-Sunset Field,“ J. PH. Tech.(Dec. 1977) 1559-68. 130. Chu. C. and Trimble. A.E: “Numerical Simulation ofSteam Displacement-Field Performance Applications,” J. fe/.Tkh. (June 1975) 765-74. 141. Joseph, C. and Pusch. W.H.: “A Field Comparison of Wet and Dry Combustion,” J. PC/. Tech. (Sept. 1980) 1523-28 142. Gates. C.F. and Holmes, B.C.: “Thermal Well Completion\ and Operation.” paper PDI I presented at the Seventh World Pet. Cmg.. Mexico City (1967). 143. Fox. R.L.. Donaldwn. A.B., and Mulac, A J. “Development nf Technology for Dwnhole Steam Producti[m.” paper SPE 9776 prehcnted at the 1981 SPEiDOE Joint Symposium cm Enhanced Oil Recovery, Tulsa. April S-8.
148.
149. I so.
151.
152.
I
153.
154. 155.
156. 157. isx. 159.
160.
161.
162.
163.
164.
165.
166.
167.
168.
Carrawaq. P.M Kloth. T.L and Bull. A I): “Co-Gcneratiirn. A New Energy Sy\tem to Generate Both Steam and Iilectricitq .” paper SPE 9907. presented ~11the 1081 C,~lili~rniu Regional Mcel1”;. Bahcrst’icld. March 25-26. Strange. L.K.: “Ignition: Key Phase m Comhu&on Rcwvcry.” fci.Crfi.(Nov. 1964) 105-09, (Dec. 1964) Y7~106. Shore. R.A.: “The Kern River SCAN Automation System Snrw ple. Control and Alarm Network,” paper SPE 3 I73 prcscntcd at the 1972 SPE California Regional Meeting. Baker~i‘ield. Nov n-10. “Bodcau In-Situ Combustion ProJect.” iir\t annual report. DOE Publications SAN-1 189-2. U.S. DOE (Sept. 1977). Wagner. O.R.: “The Use of Tracer5 in ‘Diagnosing lntcrwcll Reservoir Hetero~eneitics-FIleId Rcwlt\.” J. fcv.Tech (Nov. 1977) 1410-16. Yoelin. S.D.: “The TM Sand System Stimulation Pqect.” J. Per. Tdz. (Aug 1971) 987-94. Meldau. R.F., Shipley. R.G.. and Coats. K H : “Cyclic Gas/Steam Stimulation of Heavy-011 Wells.” J. Pd. Twk. (Oct. 1981) 1990-98. B&on, M.W. or (I/.: “The Street Ranch Pilot Test ot Frnctuw Assisted Steamflood Technology.” J. PC,/. Tdz. (March 19X3) 511-21. Sahuquet. B.C. and Ferrier. J.J.: “Steam-Drive Pilot in u Fracturcd Carbonate Reservoir: Lacq Superieur Field.” J. fvi.T~I. (April 19X2) X73-80. Hxjirdos. L.J.. Howard, J.V.. and Roberts. G.W.: “Enhanced Oil Recovery Through Oxygen-Enriched In-Situ Comhu\tion: Test Results from the Forest Hill Field in Texas.” J. PCI.Tdf. (June lY83) 1061-70 Prata. M,: TIwrw/ R~w\w:~. Monograph Scrlch, SPE. Richardson. TX (1983) 201-38. Beal. C.: “The Viscosity of Air. Water. Natural Gas. Crude Oil and Its Associated Gases at Oil Field Tempxzturcs and Pressures.” Twm., AIME (1946) 165. 103. Prfml~ur?! Pmdudon HrznrlhooX. T C. Frick (ed ) Vol. Il. McGraw-Hill Book Co. Inc.. New York City (1962) 19-39. Chew, J. and Connally. CA. Jr: “A Vi\co\ity Correlation lix Gas-Saturated Crude Oils.” Trcins., AIME (1959) 216, 23-25. Bcggs. H.D. and Robinson. J.R.: “Estimating the Viwosity of Crude 011 Systems.” J. Per. Tech. (Sept. 1975) 1140-41. Brooks. R.H. and Corey. A.T.: “Propertics of Porous Media Affectinfi Fluid Flow,” frw., ASCE. lrrlratmn and Drainage\ Div. (19k6) 92. No. 1R2. Somertan, W.H. and Udell, K.S.: “Thermal and High Ternperature PropertIes of Rock-Fluid Systems.” paper prerented at the 1981 OASTRA Workshop on Computer Modeling. Edmonton. Alta.. Jan. 28-30. Poston. S.W. CI cl/.: “The Effect of Tcmperaturc on lrreduclble Water Saturation and Relative Permeahdlty of Unconwhdatcd Sands.” .Soc Pet.Eq. J. (June 1970) 171-80. Weinbrandt, R.M.. Ramey, H.J. Jr., and Cabs& F.J.: “The Ett’cct of Temperature on Relative and Absolute Permeahiluy of Sandstones.” Sot. ftv.Et?& J. (Oct. 1975) 376-X4. Sawahini. C.T., Chilingar. G.V., and Allen. D.R.: “Comprcaslhility of Unconsolidated. Arkosic Oil Sand\.” Sot. Pcl. E!I,~. J. (April 1974) 132-38. Somerton, W.H., Keese, J.A., and Chu. S.L.: “Thermal Behavior of Unconsolidated Oil Sands.” Sot. /‘<,I. GI,~.I. (Oct. 1974) 513-21. Poettmann. F.H. and Mayland. B.J.: “Equilibrium Constants li)r High Boiling Hydrocarbon Fractions ot Varymg Characteri7dtlon Factors.” Prr. Refiner (July 1949) 101-12. Lee. S.T. et (il.: “Experim>ntal and Theoretical Studies on the Fluid Properties Required for Simulation of Thermal Procewx” Sot. Per:Org. J. (bet. 1981) 535-50. Fassihl. M.R., Brigham. W.E , and Ramcy. H.J. Jr.: “The Reaction Kinetics of In-Situ Combustion.” Sot,. Per.,!?I~. J. (Aug. 1984) 408- 16. “1967 ASTM Steam Tables.” ASME, New York City (1967).
General References “Blblmgraphy of Thermal Methods of Oil Rccoverg,” T&. (April-June 1975) 55-65.
J. C&I. Per.
46-46
Crawford. P.B.: “In-Situ Combustion.” Se~omltrr~ trd rertilrr~ Oii R<~ow~~ Pn~w.~.w.~. Interstate Oil Compact Cummlsaion. Oklahoma City (1974) Chap 5.
Farouq Ah. SM.: “Steam tnjecrion.” Set~orlllrr~~ lllld Termlr~ 011 Recovery Processes, Interstate Oil Compact Commission, OkIdhoma City (1974) Chap. 6.
PETROLEUM
Puts. M.: 77wnd TX (1982) 7.
Rrw~~r~,
7hermul Recowr~ Proces.ws, (1965. 1985) 7. 7her~w~l Reuwc~~ Techniques, TX (1972) 10.
ENGINEERING
Monograph
Serw
HANDBOOK
SPE. Richardson.
Reprint Ser~cs, SPE, Richardson,
Reprint Series, SPE. Richardson.
TX
Chapter 47
Chemical Flooding Larry W. Lake, U. of Texas
Introduction Chemical flooding is any isothermal EOR process whose primary goals are to recover oil by (1) reducing the mobility of the displacing agent (mobility control process), and/or (2) lowering the oil/water interfacial tension (lowIFT process). These classifications do not exclude processes where both effects are important, such as micellar/polymer (MP) flooding, nor do they imply that other effects, such as wettabiiity alteration, extraction, or oil swelling. are not present. Mobility control processes inject a low-mobility displacing agent to increase volumetric and displacement sweep efficiency. The two main techniques are (I) polymer flooding. whereby a small amount of polymer is added to thicken brine and (2) foam flooding, through which low mobilities are attained by injecting a stabilized dispersion of gas in water. Polymer or mobility buffer “drives” also are used to displace micellar and high-pH slugs. Foams have been used or proposed as driving agents for micellar. solvent, and steam slugs also. For these reasons foam tlooding could be discussed easily in the chapters on solvent and thermal EOR processes; however. foam stabilization requires surfactants. whose discussion belongs in this chapter. Low-IFT methods rely on injecting or forming in-situ a surface-active agent (surfactant) which lowers oil/water IFT and, ultimately. residual oil saturation (ROS). Processcs that inject the surfactant are called “MP” floods because of the tendency for surfactants to form micelles in aqueous solutions and the inevitable need to drive the micellar solution with polymer. High-pH or alkaline processes produce a surfactant in situ, since these processes rely on reactions with acidic components of the crude to generate the surfactant. This chapter is divided into sections corresponding to mobility control and low-IFT processes. Each section begins with a general discussion of how the particular mechanism recovers oil, followed by material on the individual
processes, and concludes with typical oil displacement results. The chapter concludes by giving comparative screening parameters for each chemical flooding process.
Mobility Control Processes Effect
of Low Mobility
on Oil Recovery
Mobility control processes are most applicable to reservoirs that have substantial movable oil [oil in place (OIP) minus ROS] since they displace oil only in excess of ROS. The mobility ratio concept illustrates how lowering the mobility improves oil recovery. The mobility ratio, M, between a displacing agent and a displaced fluid is M=hDlh,,,
._____.____................
._.(l)
where AD is the mobility of displacing agent(s) and A,, is the mobility of displaced fluid(s). Practical use of Eq. 1 requires specific definitions of the quantities in the numerator and denominator and of the conditions at which these quantities are evaluated. For two-phase waterflooding, common specializations of Eq. 1 are the endpoint mobility ratio, M”. the average mobility ratio, M, and the shock mobility ratio. M*. Each definition has been used in particular applications in the literature: M has been used to correlate areal sweep relations, M* is the most direct indicator of viscous instability, and M” is the most widely cited value in the literature for waterfloods. ‘Z For the special case of a piston-like displacement all three definitions are identical. From the general definition of Eq. I, lowering the mobility of the displacing fluid is equivalent to lowering any of the mobility ratios. This recovers oil by increasing both volumetric and displacement sweep efficiency. Volumetric sweep efficiency, EV. is the PV of a reservoir contacted by a displacing agent div,ided by the total PV. Et, is composed of two parts: areal, E/r, and invasion (vertical) sweep efficiency, El.
47-2
PETROLEUM ENGINEERING HANDBOOK
Fig. 47.1-Schematic
For more &tailed discuxsions of E,, and El XC‘Chaps. 30. 43. and 44 and Refs. 1 through 1 I. Both quantities dcpcnd on throughput and on several fluid. petrophyaical. and geometric factors. usually expressed as dimensionlcsa groups. However. E,.( and El both increase as Mdecrea~-i.e.. as the mobility of the displacing agent, A,,. decreases. When the displacement is piston-like in a homogcncous. isotropic. horizontal medium and M> I (an UI+I\YIUhlr mobility ratio). the displacement front forms small perturbations. called “viscous fingers.” which grow during propa@on. Such t’ingcrs also form when M< I. but they are damped out by the~~~\~cl&le mobility ratio. The growing viscous fingers can contribute substantially to poor oil rocovcry because of large-scale bypassing. Mobility control agents prevent viscous fingering cithcr in il conventional waterflood (polymer flooding) or ah a part of an otherwise inherently unstable EOR process. Displacement efficiency. El, (local or microscopic sweep cfticicncy). is the volume of oil recovered in a displacement divided by the oil volume just before the displacement. the displacement having maximum volumetric sweep efficiency. The classical solution by Buckley and Leverett can be used to describe the effect of mobility lowering on En. ” Because of the dependence on several factors there i+ no unique correspondence between M and El,: however. lowering M or An results in improved oil recovery through larger Eo. Lowering M. then. results in improved oil recovery by increahins areal. vertical. and displacement sweep efficicncics. Since it is the products of these factors that dctcrminc overall oil recovery. this implies that an incrcasc in any one may not r-csutt in a larfc overall incrcaso in oil rccokery. particularly if one of the other efficiencies ivcre IOU. Even with the combination of the three efficlc‘ncIc\. the incremental oil recovered with ;I mobility control process must he balanced against the additional eupensc rcquircd to in.jcct the viscous mobility control agent.
of polymer flooding
Polymer
Flooding
Polymers have been used in oil production in three modes. I. They have been used as near-well treatments to inprove the performance of waler injectors or high-watercut producers by blocking off high-conductivity Loncs. 2. Polymers also are used as agents that may be crosslinked in situ to plug high-conductivity zones at depth in the reservoir. ” These proccsscs require that polymer be in.jected with an inorganic metal cation. which will crosslink subsequently injected polymer molccutes with ones already bound to solid surfaces. 3. The other mode is use as agents to lower M or Xn. The first mode is not truly a chemical flooding process. since the actual oil-displacing agent is not the polymer. The overwhelming majority of polymer EOR projects have been in the third mode, which is the one emphasized here. Fig. 47. I is a schematic of a typical polymer flood injection sequence: a preflush, usually consisting of a lowsalinity brine: an oil bank; the polymer solution itself: a freshwater buffer to protect the polymer solution from backside dilution; and, finally. chase or drive water. Many times the freshwater buffer contains polymer in decreasing amounts (a grading or taper) to lessen the effects ot unfavorable mobility ratio between the chase water and the polymer solution. Because ofthe driving nature of the process. polymer tloods always arc performed through separate sets of in.jection and production wells. M is lowered in a polymer tlood by in.jecting water that contains a high-molecular-weight. water-soluble polymer. Since the water is usually a dilution of an oill‘icld brine. interactions with salinity are important. particularly for certain classes of polymers. Salinity in this chapter is the total dissolved solids (TDS) content of the aqueous phase. Typical values are shown in Fig. 47.2. ” Virtually all chemical flooding propertics dcpcnd on the concentrations ofspccific ions rather than salinity only. It is partcularly important to monitor the aqueous phahc‘s total divalcnt
47-3
CHEMICAL FLOODING
POLYACRYLAMIDE I
f’“T-Ji
1,000
r
I
I ““2 I I
HYDROLYZED POLYACAYLAMIDE
Fig. 47.3A-Molecular
a0 L d3 @ Oo
structure for partially hydrolyzed
poly-
acrylamide.
0
) I ,oc TOTAL
Fig. 47.2-Salinities
DISSOLVED
SOLIDS,
mg/l
from representallve oilfield brines
cation content (hardness) separately. since the latter are usually more crltical to chemical llood properties than the same TDS concentration. Fig. 47.2 also shows typical brine hardncsscs. Bccauxc of the high molecular weight ( I to 3 million is typical) only a small amount (typically about 500 ppm) of polJ,mer will bring about a substantial increase in water viscosity. Furthcrmorc. several types ofpolymcrs lower mobility by lowcring water relative pcrmcability (pcrmeability reduction effect) in addition to incrcaxing the water viscosity. How polymer lowers mobility. and the interactions with salinity may be qualitatively illustrated with some di5cusslon of polymer chemistry. Types. Several polymers have been considered for polymer tlooding: xanthan gum, hydrolyzed polyacrylamide (HPAM). copolymers of acrylic acid and acrylamide. copolymers ofacrylamide and 2-acrylamide-2 Imethyl propane sulfonatc (AM/AMPS). hydrouyethylcellulose (HEC). carboxymethylhydroxycthyIccllulose (CMHEC). polacrylamide (PAM). polyacrylic acid, flucan. dextran polycthylencoxide (PEO). and polyvinyl alcohol (PA). Only the first three have actually hccn field tested: however. the variety of entries in this partial listing emphasizes that there arc many potentially suitable chcmlcals. some of which may prove more cfkctivc than thoxc currently LIW~. Ncvcrthclcsj. virtually all 01‘rhe commercially attractive polymers fall into two gcncric classes: polyacrylamidcs and poly\accharide\ (hiopolyme1 or xanthan gum ). The remainder of this discussion deals with these cxclu\ively. Representative molecular structurn\ are given in Fig. 47.3. ‘.’ Polymer
Fig. 47.3B-Molecular
structure for polysaccharlde jbiopolymer).
PAM’s are polymers whose monomeric unit is the acrylamide molecule. As used in polymer flooding, PAM’s have undergone partial hydrolysis. which causes anionic (negatively charged) carboxyl groups (-COO-) to be scattered along the chain. The polymers are called partially hydrolyzed polyacrylamidcs (HPAM’s) for this reason. Typical degrees of hydrolysis arc 30% or more of the acrylamide monomers: hence. the HPAM molecule is quite negatively charged. which accounts for many of its physical properties. The viscosity-increasing feature of HPAM lies in its large molecular weight. which is accentuated by the anionic repulsion between polymer molecules and also between segments on the same molecule. The repulsion causes the molecule in solution to elongate or uncoil and snag on others similarly elongated, an effect that accentuates the mobility reduction at higher concentrations. If the brine salinity and/or hardness arc high. however, this repulsion is decreased greatly through ionic shielding as the freely rotating carbon/carbon bonds allow the molecule to ball up or coil. (Fig. 47.3 shows the molccular structure of hydroxyethylcellulose.) This causes a corresponding decrease in the effectiveness of the polymer, since the snagging effect is rcduccd greatly. Virtually all HPAM properties show a large sensitivity to salinity and hardness. This is an obstacle to usiiyg,HPAM in many reservoirs. On the other hand, HPAM 15inexpensive. relatively resistant to bacterial attack. and exhibits permeability reduction. Polyacrylamides.
Polysaccharides.
the polysaccharidcs.
A second major class of polyniers
arc
which are formed from the polymers-
PETROLEUM ENGINEERING HANDBOOK
47-4
Fig. 47.4-Polymer solution viscosity vs. shear rate and polymer concentration.
Fig. 47.5-Polymer solution viscosity vs. shear rate at various brine salinities.
zation of saccharide molecules (Fig. 47.3). Polysaccharides or biopolymers are formed from a bacterial fermentation process. This process leaves substantial debris in the polymer product that must be removed before the polymer is injected. I6 The polymer is also susceptible to bacterial attack after it has been introduced into the reservoir. These disadvantages are offset by the insensitivity of polysaccharide properties to brine salinity and hardness. The origin of this insensitivity is seen in Fig. 47.3, which shows the polysaccharide molecule to be relatively nonionic and, therefore, free of the ionic shielding effects of HPAM. Polysaccharides are more branched than are HPAM’s and the oxygen-ringed carbon bond does not rotate fully; hence, the molecule increases brine viscosity by snagging and by adding a more rigid structure to the solution. Polysaccharides do not exhibit permeability reduction, however. At the present time HPAM is less expensive per unit amount than polysaccharides; however, when compared on a unit amount of mobility reduction, particularly at high salinities, the costs are close enough so that the preferred polymer for a given application is site-specific. Historically, HPAM’s have been used in about 95% of the reported field polymer floods. I7 Both classes of polymers tend to degrade chemically at elevated temperatures.
unsnagging of the polymer chains when they are placed in a shear flow. Below the critical shear rate the curve is reversible. Fig. 47.5 shows a viscosity/shear-rate plot at fixed polymer concentration with variable NaCl concentration for an AMPS polymer. I9 Note the profound sensitivity of the viscosity to salinity: as a rule of thumb the polymer solution viscosity decreases a factor of 10 for every factorof-10 increase in NaCl concentration. The viscosity of HPAM polymers and HPAM derivatives is even more sensitive to hardness, but viscosities of polysaccharide solutions are relatively insensitive to both. The behavior in Figs. 47.4 and 47.5 is favorable because for the bulk of a reservoir’s volume, P is usually low (about 1 to 5 seconds -I), making it possible to attain a design M with a minimal amount of polymer. Near the injection wells, however, i can be quite high, which causes the polymer injectivity to be greater than that expected on the basis of ~1 ’ The relative magnitude of this enhanced injectivity ef Pect can be estimated once quantitative definitions of shear rate in permeable media and shear-rate/viscosity relations are given. ” The polymer solution viscosity/shear-rate relationship may be described by a power law model. ” pp =K(iy
Because of the complexity of the subject, a comprehensive treatment of polymer properties is not possible. However. qualitative trends, a few quantitative relations and representative data are presented on these properties: viscosity relations, non-Newtonian effects, retention, permeability reduction, and chemical, biological, or mechanical degradation. Viscosity Relations and Non-Newtonian Effects. Fig. 47.4 shows polymer solution viscosity. p,,, vs. shear rate measured in a laboratory viscometer at fixed salinity. I8 At low shear rates, p,, is independent of shear rate. P(~,,=~,,‘), and the solution is a Newtonian fluid. At higher i. p,, decreases, approaching a limiting (p,, =p,’ “) value not much greater than the water viscosity, p,,., at some critical high shear rate (not shown on Fig. 47.4). A fluid whose viscosity decreases with increasing ? is shear thinning. The shear thinning behavior of the polymer solution is caused by the uncoiling and Polymer
Properties.
’,
..
(2)
where K and n are the power-law coefficient and exponent, respectively. Eq. 2 applies only over a limited range of shear rates: below some low shear rate the polymer solution viscosity is constant at pp O, and above the critical shear rate the polymer solution viscosity is also constant p,O”. The truncated nature of the power law is awkward in calculations; hence, another useful relationship is the Meter model. 22 PLpO-P,, m a~,,‘.......““.‘.... .
Pp = P pm+ If
L c p 1%>
where 01 is an empirical coefficient and > ,,? is the shear rate at which CL,,is the average of pLr,’and p,, -. As with all polymer properties, all empirical parameters are functions of salinity, hardness, and temperature.
47-5
CHEMICAL FLOODING
When applied to permeable media flow thcsc gcncral trends and equations continue to apply. cc,, is usually called the “r(17/‘u’.~rr” viscosity and the effective shear rate. in,.. is based on capillary tube concepts.
uii
ic =
,
.. .....
.......
. . . (4)
4&G% where II,,. = superficial flux of polymer-rich (water) phase. k,,. = permeability to polymer-rich (water) phase. S,,. = saturation of polymer-rich (water) phase. fraction, and $ = porosity of medium, fraction. Polymer Retention. All polymers experience retention on solid surfaces because of adsorption or mechanical trapping within a permeable medium. Polymer retention varies with polymer type, molecular weight, rock composition, brine salinity and hardness, flow rate, and temperature. Field-measured values of retention range from 20 to 400 Ibm polymer/acre-ft bulk volume with desirable retention level being less than about 50 lbm/acre-ft. Retention causes the loss of polymer from solution, which can cause the mobility control effect to be destroyed-an effect that is particularly pronounced at low polymer concentrations. Polymer retention also causes a delay in the rate of polymer propagation. Offsetting the delay caused by retention is an acceleration of the polymer solution through the permeable medium. which is caused by inaccessible PV (IPV). The most common explanation for IPV is that the smaller portions of the pore space will not allow polymer molecules to enter because of their size. Thus, a portion of the total pore space is uninvaded or inaccessible to polymer. and accelerated polymer flow results. Large as they arc, however, most polymer molecules will fit easily into all but the smallest pore throats. Hence, a second explanation of IPV ih based on a wall exclusion effect whereby the polymer molecules aggregate in the center of a narrow channel.” The polymer pore fluid layer near the wall has a lower viscosity than the fluid in the center. which causes an apparent fluid slip. IPV depends on polymer molecular weight, media permeability, porosity, and pore size distribution, becoming more pronounced as molecular weight increases and the ratio of permeability to porosity (characteristic pore size) decreases. IPV can be 30% of the total pore space or greater, Permeability Reduction. As mentioned previously HPAM polymers can cause lowered mobility through a permeability reduction effect. This phenomenon has been described through three factors. 24 The resistuncc~,fuctor. FR, is the ratio of the injectivity of a single-phase polymer solution to that of brine flowing under the same conditions:
A,,. FR=-=x,,
k,,/tL,,, k,,cl,, .
where k,, = permeability to polymer solution. h,, = mobility of water-rich phase. and h,, = mobility of polymer solution. For constant-flow-rate experiments. FR is the inverse ratio of pressure drops; for constant-pressure-drop experiments, FR is the ratio of flow rates. F, is an indication of the total mobility-lowering contribution of a polymer. To describe the permeability reduction effect alone. a prl-mwhilit~, rcductiorl ,firctor-. F,.k , is defined as
A final definition is the residual resistctnw jirctor. FRr . which is the mobility of a brine solution before and after polymer injection.
FR,-=-
.
_.
(7)
where A,,.,, is the mobility of water-rich phase before polymer injection and A,,,(, is the mobility of water-rich phase after polymer injection. F,Q is a measure of the permanence of the permeability reduction effect caused by the polymer solution. It is the primary measure of the performance of a channel-blocking application of polymer solutions. For many cases, F,k and FR,- are nearly equal; however. FR is usually much larger than F,.,: because the former contains the viscosity-enhancing effect as well as the permeability-reduction effect. The most common measure of permeability reduction is F,.k. Frk is sensitive to polymer type, molecular weight. degree of hydrolysis, shear rate, and permeable media pore structure. Polymers that have undergone even a small amount of mechanical degradation seem to lose most of their permeability reduction effect. For this reason. qualitative tests based on screen factor devices are common to estimate polymer quality.” F,.k has been correlated to polymer adsorption and rheological properties by Hirasaki and Pope.” Chemical and Biological Degradation. The average polymer molecular weight can be decreased, to the detriment of the overall process, by chemical. biological, or mechanical degradation. Chemical degradation can be minimized by restricting polymer usage to lowtemperature applications, and by adding oxygen scavengers (e.g., sodium sulfate or sodium sulfite) to the polymer solution. Biological degradation can be elimnated by adding oxygen scavengers and biocides (e.g.. formaldehyde or isopropyl alcohol). In fact, nearly all applications contain some of these chemicals. usually in very small quantities (see Ref. 16 or 26). Mechanical Degradation. Mechanical’degradation, on the other hand, is potentially present under all applications. Mechanical degradation occurs when polymer solutions are exposed to high-velocity flows. These can be present in surface equipment (valves. orifices, pumps. or tubing), downhole conditions (perforations or screens). or in the sandface itself. Perforated completions. particularly, are a cause for concern. since large quantities of
47-6
PETROLEUM ENGINEERING
County,
OK.‘”
The figure
fore and immediately injection declining
PLACED
40.
53000
I
ON PRODUCTION
ery (IOR) from a polymer the cumulative oil actually
-
for a technical
Fig. 47.6-Tertiary polymer flood response from North Burbank Unit, Osage County, OK.
through
small holes. For this reason. most polymer done through cause flow an injector.
openhole
or gravel-pack
a number
of
in,jections are
completions.
Be-
velocity falls off quickly with distance from little mechanical degradation occurs within
the reservoir
itself.
All polymers mechanically degrade under high enough flow rates. However. HPAM’s are most susceptible under normal
operating
conditions.
flood is the difference between produced and that which would of the project
waterflood.
Thus.
it is important
to
47.6.
Table 47. I summarizes other field results on more than 250 polymer tloods on the basis of a comprehensive sur-
“EARS
forced
Polymer
flood oil rate decline and an accurate rate. The IOR for North Burbank is
the shaded area in Fig.
arc being
injection.
decline but at a substantialoil or incremental oil recov-
by a continuing
analysis
establish a polymer waterflood decline
solution
polymer
began in late 1970, which quickly arrested a oil rate and an increasing WOR. The oil rate
have been produced
polymer
shows WOR and oil rate be-
after
then resumed its prepolymer ly higher level. The polymer
BARRELS
HANDBOOK
particularly
if the sa-
vcy by Manning rt rrl. I7 The table emphasizes oil recovcry data and screening parameters used for polymer flooding. Approximately one-third of the statistics arc from commercial or field-scale floods. The oil recovery statistics in Table 47. I show average polymer
tlood recov-
cries of 3.56%
oil in place.
remaining
(after watertlood)
and 2.69 STB of IOR for each pound of polymer itljcctcd. with wide variations in both numbers. The large variability reflects the emerging nature of polymer tlooding in the previous decades. Considering the STB IOR per pound of polymer average and the average costs of crude and polymer, it appears that polymer flooding could be a highly attractive EOR process. However. ways should be compared on a discounted
such costs albasis rctlcct-
linity or hardness ofthe brine is large. Evidently, the ionic coupling of these anionic molecules is relatively fragile
ing the time value of money. which will decrease the apparent attractlvencss of polymer flooding because of the
compared with the polysaccharide chains. Also. clongational stress is ar destructive to polymer solutions as is
decreased
shear stress, although the two generally accompany each other. Maerker and others have correlated permanent vis-
injectivity
of the polymer
solutions.
Foam Flooding Gas/liquid
foams
offer
an alternative
to polymers
for
cosity of a polymer solution loss to an elongational stretch rate times length product. 273 On a viscosity/shear-rate
providing mobility control in chemical floods, and have been both proposed and field tested as mobility control
plot (purely
agents in steamfloods.
shear flow),
mechanical
begins at shear rates greater critical
degradation
usually
than the minimum-viscosity
shear rate.
Foams are dispersions of gas bubbles in liquids. Gas/liquid dispersions are normally unstable and usually will break
Field Results. ing field
Fig. 47.6 shows a tertiary
response
from
the North
polymer
Burbank
unit,
tloodOsage
TABLE 47.1-POLYMER
Oil recovery, O/oremaining OIP Oil recovery, STB/lbm Oil recovery, STBlacre-ft Permeability variation, fraction Mobile oil saturation, fraction Oil viscosity, cp Resident brine salinity, g TDSlL Water-to-oil mobility ratio, dimensionless Average polymer concentration, ppm Temperature, OF Average permeability, md Average porosity, fraction
in less than
I second.
If surfactants
FLOOD STATISTICS
Number of Projects*
Mean
Minimum
Maximum
Standard Deviation
50 80 88 118 62 153
3.56 2.69 24.0 0.70 0.27 36
0 0 0 0.06 0.03 0.072
25.3 36.5 188.7 0.96 0.51 1,494
5.63 4.86 36.65 0.19 0.12 110.2
40.4
5.0
133.0
33.4
0.1
51.8
10
are added to
the liquid, however, stability is improved greatly so that some foams can persist indefinitely. To understand foam
87
5.86
93 172 187 193
339 115 349 0.20
51 46 1.5 0.07
3,700 234 7,400 0.38
11.05 343 85 720 0.20
47-7
CHEMICAL FLOODING
propertie
rcqulrcc
wnc
their classifications. surfact~nts
ili5cusvon
of surtactunts
Moat of the discussion
and
SODIUM c:
3s well. /
Surfxtant
Chemistq.
composed
of a nonpolar
DODECYL
SULFATE
applies to MP c
\,/
\cA,i\p\cAo
_ g _ o- No+
A typical xurfactant monomet- is portion (lipophi1c~i.c.. having
strong affinit~~~for oil) and a polar portion
(hydrophile-
I
0
TEXAS NO.1 SULFONATE
i.e.. strong attmity for water): the entire monomer is an amphtphile (has affinity for both oil and vvater) because ofthis
dual nature.
Fig. 47.7 shows the molecular
ture of two common
surfactanta
struc-
(top two panels) and il-
lustrates (lowest panel) a shorthand notation for surfactant monomers: the monomer is represented by a “tadpole” sy~dx~l
with the nonpolar
portion
polar the head. Surfactants
being the tail and the
are classified
into four groups
COMMERCIAL
that depend
on their polar portions (see Table 47.1)3”. Anionic.s. As required by electroneutrality. the an ionic aurfactant molecule is uncharged with an inorganic
metal
cation
(usually
sodium)
associated
with
rclativelv
resistant
to retention.
the
Cationic
surfactants
EOR bccausc they are adsorbed faces of interstitial clays.
Nonionics.
These
surfactants
bonds, but when dissolved
Fig. 47.7-Typical
do
not
use in
form
in aqueous solutions.
ionic
they cx-
Anzphoterics. A final class of surfactants
Within
These surfactants
effect of structure on surfactant and 32. Most commercial surfactants surfactants complexity. factant
are those
types are ignored
Foam Stability.
have
stood by viewing
any one class there is a huge variety
propertics contain
see Refs. 31
distributions
of
and surfactant types that further add to their In the following. distinctions between sur-
tant as the tadpole
that contain aspects of two or more of the previous classes. For example. an amphoteric may contain both an angroup.
surfactant molecular structures
by the anionic sur-
hibit surfactant properties simply by electronegativity contrasts betvveen their constituents. Nonionics arc much less sensittve to high salinities than anionics or cationics.
ionic group and a nonpolar not been used in EOR.
-O-Nat-
R - HYDROCARBON GROUP (non - polar)
stable.
have little
highly
SULFONATES
A
and relatively inexpensive. Cationics. In this case the surfactant ~~dxulc contains a cationic hydrophilc and an inorganic anion to balancc the charpc.
I
R-S
monomer. In an aqueous solution the ~~dx~~le ioniLcs to free cations and the anionic monomer. Anionic surfactants are the most common in EOR because they are good surfactants.
PETROLEUM
0
by simply
structure
treating
of Fig.
the surfac-
47.7.
The stability of a foam may be underthe liquid film separating two gas hub-
bles in cross section as in the lower panel of Fig. 47.8. ‘?
of possible
The hydrophiles
surfactants. Fig. 47.7 illustrates differences in Iipophile molecular weight IC t2 for the sodium dodecyl sulfate
terior
of the surfactant
of the film
are oriented
and the lipophiles
toward
into the inthe bulk gas
(SDS) vs. C th for Texas No. I]. hydrophilc identity (sulfate vs. sulfonate), and tail branching (straight chain for SDS vs. two tails for Texas No. 1) all within the same
phase. Suppose that some external force causes the film to thin as in the lower panel. Since capillary pressure is
class of anionic
sure in the thinned
variations
surfactants.
In addition
in the position ofthe
hydrophile
attachment
the number of hydrophiles (monosulfonates fonatcs. for example). Even small variations surfactant properties drastically (e.g.. less thermally stable than sulfonatcs).
Sulfonaies Sulfates Carboxylates Phosphates Others
proportional
to interfacial portion
the ad,iacent flat portion.
and
vs. disulcan change
sulfates tend to be For details on the
Table 47.2-CLASSIFICATION 4-M Anionics
inversely
to these. there are
curvature.
of the film
the pres-
is lower
This causes a pressure
than in differ-
cnce within the film. liquid flow. and healing. The pressure in the gas phase is assumed constant because of its relatively low density if the foam is static. or low viscosity if in motion.
OF SURFACTANTS
-e’M Cationics
-e+ Amphoterics
Quaternary ammonium Pyridinum lmidazolrnrum Piperidinium Sulfononium Compounds Others
Aminocarboxyltc acids Others
AND EXAMPLES dNonionics AlkylAlkyl-aryl Acyl AcylamindoAcylaminepolyglycol Polyol ethers Alkanolamides Others
ethers
PETROLEUM
47-a
SURFACE TENSION
_ ADSORPTION
/
J
/
/
/
/
/
/I-----
/
ENGINEERING
ble layer
on the interior
attractive
Van der Waal forces bctwccn
of the film
boundary
and the
the molecules
in
the film. If the film becomes substantially smaller than the equilibrium thickness. the fret energy barrier between the repulsive and attractive the film will collapse.
/
Such thinning I I C.Y.C.
contributions
is breached
can be caused spontaneously
and
by diffu-
sion of the gas from small to large bubbles and by gravity drainage. Patton et al.” reported on the rate of spontaneous collapse of a large number of foams as a func-
CONC.
tion of surfactant
type. temperature,
life of the foam heights reported
and pH. tl The half-
in their static tests ranges
from 1 to about 45 minutes. They report that anionic surfactants have greater stability than nonionics. and that the
FlllIl
3
HANDBOOK
0
Hii
Thlnner, Lou Contractlon
Film
stability
adrorptlon,
Larger
aurfece
of sulfonate
tencllon,
panel shows surface tension and adsorption of a surfactant vs. concentration. Lower panel is the Gibbs-Marangoni effect.
DARCY DARCY
0
km
greatly
concentration could do this). local heating. a hydrophobic surface.
Foam Physical
’ 0.22
is affected
by water
External effects that may cause the foam to collapse are the presence of a foam breaker (oil or a high clcctrolyte
Fig. 47.8-Upper
0 km, = 4.41 * k,,, * 0.42
foams
hardness. Foams were generally more unstable at high temperatures, and many could be stabilized by adding a second surfactant.
Properties.
Physically,
or contact with
foams arc char-
acterized by three measures. Qua&. Foam quality, r, is the percentage of the total (bulk) foam volume that is gas volume. The quality can
OMCY
increase with increasing
temperature
and decreasing
pres-
sure both because the gas volume can increase. and also because gas dissolved in the bulk liquid phase can evolve from solution. \ 0
0.10!-
Foam qualities
can bc quite high, approach-
ing 97% in many cases. A foam with quality
*
is a dry foam. Texture. This measure is the average
greater than
90%
texture determines permeable medium.
A
how the foam If the average
bubble
size. The
will flow through a bubble size is larger
than the average pore diameter. the foam flow5 as a progression of films separating individual gas bubbles. Given
typical
foam textures
tion is most nearly 0 0
OF F&i,
and pore sizes, this condiin permeable
flow.
particu-
larly
0.01 60 QUA&Y
realized
PLRCE”SOf
Fig. 47.9-Effective
permeability-viscosity ratio vs foam quality for consolidated oorous media.
for high foam qualities. Bubble Size Range. Foams with a large distribution range are more likely to be unstable because of the gas
diffusion
from
large to small
Mobility
Lowering.
Foams
a gas phase drastically. mobility
bubbles. can reduce
the mobility
of
Fig. 47.9 shows the steady-state
of foams of differing
quality
in Berea cores at
three different permeabilities as a function of quality.” On the extreme right of this figure (r100%). the moThe upper panel in Fig. 47.8 shows that the gas/liquid surface tension is a decreasing function of surface adsorp-
bility should approach the respective air permeability divided by the air viscosity: this mobility is two to three
tion as required by the Gibbs theory. According to this view the thinned portion of the film will have less specif-
factors of 10 greater than any of the experimental points on the figure. When r-0 the mobility should approach the water permeability divided by CL,, Thus. the mobili-
ic adsorption (since the surface area is locally greater) and greater surface tension. This locally high surface tension
ty of the foam is lower
also causes healing. Clearly. the surface tension at the gas/liquid
tuents alone. The mobility of the foam decreases with increasing quality until the films between the gas bubbles
interfaces
play an important role in film stability. Very low surface tension would not be favorable; fortunately gas/liquid sur-
than that of either
begin to break and the foam collapses
of its consti-
(not shown on Fig.
face tensions are rarely lower than 20 dynes/cm even with the best foaming agents. In the absence of external forces.
47.9). Foams are effective in reducing the mobility at all three permeabilities in Fig. 47.9, but the effect of foam quality is more pronounced at the highest permeability.
the film
This is a consequence
is at an equilibrium
ance between
the repulsion
thickness
caused by a bal-
forces of the electrical
dou-
of the foam
of the contrast
between
the tcxturc
and the mean pore size of the mcdium.36
CHEMICAL FLOODING
The
mobility
viewed
47-9
reduction
as an increase
caused
by the foam
in a single-phase
a decrease in the gas-phase
can be
viscosity
permeability.
or as
Representative
data of the second type are in Fig. 47.10, which shows the gas-phase permeability, both with and without foam, and as saturation plotted against the liquid injection f rate. -’ Note that the foam causes a great decrease in gas permeability
at the same rate and even at the same gas
saturation compared to the nonfoaming displacement. analogous analysis performed on the aqueous-phase
The rela-
Ii
l.T
iiiiiii
II:
iiiiil
tive permeability shows that neither the gas saturation nor the presence of the foaming agent affects the aqueousphase relative permeability. The low foam mobilities
j8 in permeable
media flow
PERYEABILITY k--t+sRI
-?-d---GAS
are
3
postulated to be caused by at least two different mechanisms: (I) the formation of or the increase in a trapped
3
residual gas phase saturation and (2) a blocking of pore throats caused by the gas films. From Fig. 47.10 the effect of a trapped gas mobility
gas saturation,
through
which
would
a relative-permeability
lower
the
lowering,
is
much smaller than the pore-throat-blocking effect. The trapped gas-phase saturation effect may become important. however,
during
0.1 0
I
2
3 4
5
6
7
8
9 IO II
12 13 14
LIQUID INJECTION RATE, BARRELS PER. DAY/ SO. FT.
the later stages of a displacement
where the lower pressures could cause more gas to come out of solution. The mobility reduction of foams, viewed as a viscosit enhancement. has been studied in capillary tubes. 38 General
observations
generally
on these data are that foams
shear-thinning
fluids
whose power
cient increases with the capillary oretical
arguments
are
law coeffi-
tube radius.
based on a Newtonian
Fig. 47.10-Effect of liquid flow rate and gas saturation on gas permeability with and without foam
Using the-
fluid
and an
inviscid gas, Hirasaki and Lawson showed that the film thickness of a single moving bubble increases as the bubble velocity to the two-thirds power. 4o Since shear stress in a capillary
is inversely
proportional
to film thickness.
the apparent viscosity of a foam in a capillary tube decreases with increasing velocity. Thus, the shearthinning effect observed in capillary tubes is actually a consequence of the film thickening as velocity A second implication in the Hirasaki-Lawson
increases. theory is
that foam texture occupies as great an importance in determining rheological behavior as does foam quality.
Field Results.
Field tests of foam injection alone have been scarce. Holm reports on the injection of an air/brine foam into a single well in the Siggins field.” Though
Fig. 47.11--Schematic
capillary desaturatjon curves
there was no measureable oil response, the mobility to both air and brine were reduced significantly, and the injection
profile
into the central well became more uniform.
Low-IFT Processes In addition
to stabilizing
gas dispersions,
in MP flooding or generated lowering oil/water IFT.
Lowering
surfactants
in situ can recover
used
of which
N,. =N ,, p ,,,/u,,.<, For a waterflood,
The basic tool for illustrating how lowering IFT reduces ROS is the capillary desaturation curve (CDC) shown in Fig. 47.1 I. The CDC
one form
is a plot of nonwetting-
saturation
is
oil by
ROS
phase residual
4’-w but the most common source of this ed theoretically, curve is experimental measurement. “.” The ratio of viscous to local capillary forces is the capillary number, N,. 1
or wetting-
on the y axis vs. a dimcnsion-
.
(8)
u,,. and p,,, are the superficial
flux and
viscosity of the displacing water, and u,!(, is the IFT between the water and oil phases. For a MP flood a more general definition
is appropriate,
but Eq. 8 and the CDC
less ratio of viscous to local capillary forces on a logarithmic .Y axis. On Fig. 47.1 I, S,,,.,, is the residual oil
can illustrate this case also. The CDC is a nearly horizontal plateau at small N, until a critical value above which both residual phase satu-
(assumed nonwetting), and S,,,. is the irreducible water(wetting)-phase saturation. The CDC has been calculat-
rations decrease. phase saturations
At a second critical N,.. the residual are zero and complete recovery of the
PETROLEUM ENGINEERING
47-10
Fig. 47.12-Schematic
originally trapped phase occurs. The shape of the CDC is determined by the pore geometry of the medium and the wetting behavior of the two phases. The wetting phase rcquircs
a larger
N,. for complete
recovery.
To a lesser
extent. the CDC shape is affected by the mean pore size and pore size distribution of the medium. and the initial saturations. Typical N, ‘s for watertlooding are quite small. which indicates that ROS and S,,, may be assumed constant for this purpose (XC Fig. 47. I I). Because of the logarithmic .Y axis. a decrease by several factors of IO in N,
is necessary
IO significantly
change
either
residual
phase saturation. Ofthc three quantities in Eq. 8 only the IFT can be changed this drastically; a typical value for causing good ROS reduction is in the range of IO ’ dyne/cm. a value that can be obtained aurfactant.
only
with a good
HANDBI 30K
of an MP flooding process.
IMP Flooding MP flooding
has appeared
in the technical
literature
un-
der many names: detergent. surfactant, low-tension. soluble oil. microemulsion. and chemical flooding. There are also several company
names that imply a specific sequence
and type of injected of the oil-recovering
fluids as well as the specific nature MP slug itself. Though there are
differences among company processes. the aspects are more numerous and important.
common
An idealized version of a MP flooding sequence is in Fig. 47.12. The process is applied invariably to tertiary floods (those producing at high WOR’s) and is always implemented in the drive mode (not cyclic or huff ‘n’ puff). The complete process consists of the following.
Prejlush. A volume of brine whose purpose is to change (usually lower) the salinity and hardness of the resident brine so that mixing with the surfactant will not cause the loss of interfacial activity. Pretlushcs have ranged in size from 0 to 100% of the reservoir PV. In some processes a sacrificial
agent is added to lessen the subsequent
sur-
factant retention and also to precipitate divalent cation.” MP Slug. This volume. ranging from 5 to 40% PV in field applications. contains the main oil-recovering agent. the prituut:\~ surfactant, in concentrations ranging from I to 20 ~0170. Several other chemicals (cosurfactants. alcohols. oil. polymer.
biocide,
and oxygen
scav’cnger)
are
usually necessary for good oil recovery. LJ40~i~i~ Buffeer. This fluid is a dilute solution of a water-soluble polymer whose purpose is to drive the MP \lug and banked-up fluids to the production wells. Much of polymer flooding technology carries over to dcsigning and implcmcnting
the mobility
buffer.-18 of brine containgrading between that of
Freshwater Buffer. This i\ a volume ing a concentration buffer
The gradual
concentration
of the unfavorable Fig. 47.13-Schematic
of the CMC
of polymer
the mobility
and mobility
at the front end and zero at the back. mobility
buffer.
decrease
mitigates
ratio between
the effect
the chase water
47-11
CHEMICAL FLOODING
Chase Water. The purpose of the chase water is sirn-
1 _(
ply to reduce the expense of continually injecting polymer. If the mobility and freshwater buffers have been designed properly. it is penetrated,by
Surfactant in brine,
the MP slug will the chase water.
Solutions.
monomer.
before
If an anionic surfactant is dissolved disassociates into a cation and a
the surfactant
If the surfactant
the lipophilic
be dcplcted
portions
concentration
then is increased,
of the surfactant
begin to associate
among themselves to form aggregates or micelIes containing several monomers each. A plot of surfactant monomer concentration
vs.
total
surfactant
concentration
(Fig.
47.13) is a curve that begins at the origin, increases with unit slope, then levels off at the critical micelle concentration (CMC). Above the CMC all further increases in surfactant concentration cause increases only in the micelle concentration.
CMC’s
are typically
10 -’ to IO p4 mol/L). tions for MP flooding
quite
small
the micellc form; hence. the name micellar/polymer ing. The representations
of the micelles
flood-
in Fig. 47.13 and
elsewhere are schematic. The actual micelle structures can take on various forms, which can fluctuate with time. When
this solution
“olcic” indicates oil) the surfactant
I
(about
At nearly all practical concentrathe surfactant is predominantly in
contacts
an oleic
S
WA TEf? EXTERNAL hffCROE~LS/ON I
EXCESS 011 A
phase (the term
that this phase can contain more than tends to accumulate at the intervening
interface. The lipophilic tail dissolves in the oleic phase, and the hydrophilic in the aqueous phase. The accumulation at the intcrfacc causes the IFT between the two phases to lower. The extent of the IFT lowering is proportional to the cxccss surface concentration
of the surf;lctant-the
difference
and
between
the
surface
bulk
concentration-from Gibbs’ theory. as was the case in Fig. 47.X. The surfactant itself and the attending conditions should bc adjusted to maximize the excess surface concent]-ation; however, in doing so the solubility of the sur-
0
OVERALL COMPOSITtW
surfactant Fig. 47.14-Schematic behavior.
of low-salinity surfactantlbrineioil
phase
tactant in the bulk oleic and aqueous phases also is affected. Since this solubility also impinges on the mutual volubility
of brine
this discussion
and oil,
leads naturally
brine/oil phase behavior. many micellar properties.
which
also affects
IFT’s,
to the topic of surfactanti
Curiously, and this is true of the surfactant concentration it-
scribed was presented originally
by Winsor’”
to MP flooding later.50.5’ At low brine salinity, a typical hibit good aqueous (water-rich)
and adapted
MP surfactant phase solubility
will
ex-
and poor
self plays a rather minor role in what follows, compared with the temperature. brine salinity, and hardness.
oleic (oil-rich) phase solubility. Thus, an overall composition near the brine/oil boundary of the ternary will split
SurfactantlBrineiOil
Surfactanti conventionally on
rnicroemulsio~~phase that conoil and a (water-external) tains brine surfactant, and some solubilized oil. The solu-
a ternary diagram. A ternary diagram is an equilateral triangle whose apexes represent pure components. boundarlcs represent two-component mixtures, and interior rep-
core of the swollen micelles. The tie lines within the twophase region have a negative slope. This type of phase
resents
environment
into two phases: an e,xcess oil phase that is essentially hrinc/oil
Phase
phase behavior
three-component
mixtures
the three apexes
Behavior.
is illustrated
mixtures.
For
must represent
complicated “pseudocom-
bilized
oil occurs when globules
is called variously
pure
of oil occupy the central
a Winsor
Type I system.
a lower-phase microemulsion (because it is more dense than the excess oil phase), or a Type II system. The lat-
poncnts” whose composition remains constant throughout the diagram. The pressure and temperature are also fixed. The diagram can represent both the overall com-
ter terminology
position of a surfactantibrineioil mixture. and the equilibrium composition of each phase if the mixture forms more than one phase. Tcrnarica and their accompanying
means that the tie lines have negative slope (Fig. 47.14). The right plait point in such a system. PK. usually is located quite close to the oil apex. Any overall composi-
definitions
tion above
are discussed
MP phase behavior
in Chap.
is affected
23.
strongly
by the salinity
is adopted
the binodal
ous phase. An overall
salinity
Iregion now will
The phase behavior
about to bc dc-
curve
means that no more will)
is single
form and (-)
phase.
For high brine salinities (Fig. 47. IS) electrostatic forces drastically decrease the surfactant’s solubility in the aque-
of the brine pseudocomponent. Consider the sequence of phase diagrams (Figs. 47.14 through 47.16) as the brine is incrcaxcd.
here-11
than two phases can (not necessarily
composition
within
the two-phase
split into an UUJ,S.\ hr-i/~c phase and an
47-12
PETROLEUM ENGINEERING
HANDBOOK
SWOLLEN MICELLE
Na+ Na+ NO+
COMPOSITION
Fig. 47.15-Schematic behavior.
(oil-external) is solubilized micelles
of surfactant/brine/oil high-salinity phase
microemulsion
of the surfactant
phase, which contains
and some solubilized
through
(Fig.
47.15)
COMPOSITION
the formation with brine
brine. of inverted
globules
most
The brine swollen
at their cores.
The phase environment is a Winsor Type II system, an upper-phase microemulsion, or a Type II( +) system. The plait
point,
PI,.
is now close to the brine
phase,
Type
II( -).
suggests
an extraction
mechanism in oil recovery. Though extraction does play some role. it is dwarfed by the IFT effect discussed later. particularly when phase behavior tics is considered.
at intermediate
salini-
II( +) systems and a third surfactant-rich phase is formed. as shown in Fig. 47.16. An overall composition within the three-phase region separates into excess oil and brine phases as in the Type II(-) and II( +) environments. and phase whose composition
sented by an ;U~U~;LUU point.
This environment
Type
III,
a middle-phase
microemulsion.
or
a Type III system. Above and to the right and left of the three-phase region are Type II( -) and II( +) lobes wherein two phases will form as before. Below the three-phase region there is a third two-phase region (as required by thermodynamics) whose extent is usually so small that it two IFT’s
In the three-phase
between
region
the microemulsion
there are now
and oil,
a,,,,, , and
the microemulsion and water, u,~~,,.. Fig. 47.17, a prism diagram, shows the entire progression of phase environments from Type II( -) to II( +). The Type III region forms through
the splitting
cal tie line that lies close to the brine/oil
of a criti-
boundary
as the
salinity increases to C,, (low effective salinity limit for Type III phase environment). 53 A second critical tie line also splits at C,,
At salinities between those of Figs. 47. I4 and 47.15. there is a continuous change between Type II( -) and
into a microemulsion
a Windsor
is neglected.“’
apex.
The two extremes presented thus far are roughly mirror images; note that the microemulsion phase is watercontinuous in the Type II( -) systems and oil-continuous in Type II(+) systems. The induced solubility of oil in a brine-rich
Fig. 47.16-Schematic of surfactant/brine/od phase behavior at optimal salinity.
(high effective
III phase environment)
as salinity
salinity
limit
for Type
is decreased from a Type
II( +) environment. Over the Type III salinity range the invariant point, M, migrates from near the oil apex to near the brine apex before disappearing ical tie lines. The migration
at the appropriate
of the invariant
crit-
point implies
is repre-
essentially unlimited solubility of brine and oil in a single phase, which has generated an Intense research in-
is called
terest into the nature
of the Type
III
microemulsion.
”
CHEMICAL FLOODING
Fig. 47.17-Prism
diagram showing sequence of phase environment transition.
Several variables other than salinity can bring about the Fig. 47.17 phase environment shifts. In general, changing any condition bility
that enhances the surfactant’s
will cause the shift from Type Il( -)
oil solu-
to II( +). Some
of the more important are: (1) decreasing temperature, 5’ (2) increasing surfactant molecular weight, (3) decreasing
tail
branching,“’
(4)
decreasing
oil
specific
tions of surfactant
concentration.
be visualized by tilting Fig. 47.17 about their
This dependency
may
the vertical triangular planes in bases. This dilution effecth’.h5
forms the basis for the salinity
requirement
diagram
de-
sign procedure. ‘UJ The dilution effect is particularly pronounced when the brine contains significant quantities of divalent ions.
and (5) increasing concentration of highmolecular-weight alcohols. 58 Decreasing the surfactant’s
4. The Fig. 47.17 phase-behavior shifts are specific the exact ionic composition of the brine. not simply
oil solubility
the total salinity. For anionic surfactants. other anions in solution have little effect on the MP phase behavior: however. cations readily cause phase-environment changes.
gravity55-57
47.17
will
cause the reverse
could be redrawn
change.
Thus,
Fig.
with any of the above variables
(and several others) on the base of the prism with the variable C,, (effective salinity) increased oil solubility.
Nonideal
Effects.
increasing
in the direction
In much the same manner
of
as the ideal
gas law approximates the behavior of real gases, Fig. 47. I7 is an approximation to actual MP phase behavior. Some of the more important I.
At
nonidealities
are as follows.
high
surfactant concentrations and/or at low or even in the presence of pure surfactemperaturess”.59 tantsL36. phases other than those on Fig. 47.17 have been observed. crystals
These phases tend to be high-viscosity or other condensed
liquid
phases. The large viscosities
are detrimental to oil recovery since they can cause local viscous instabilities during a displacement. Frequently, low- to medium-molecular-weight alcohols (cosolvents) are added to MP formulations to “melt” these undesirable viscosities. When the brine contains polymer. a condensed phase can be observed at low surfactant concentration because of exclusion of the polymer from the microemulsion phase. Cosurfactants can be used to eliminate
this polymerisurfactant
2. When cosurfactants appropriate
incompatibility.”
are present
it is frequently
to lump all of the chemicals
in-
into the surfac-
Divalent
cations
(calcium
and magnesium
to to
are the most
common) are usually 5 to 20 times as potent as monovalent cations (usually sodium). Divalents arc usually present in oilfield brines in smaller quantities than monovalents as shown
in Fig. 47.2,
but their effect
is so pronounced
that it is necessary, as a minimum. to separately account for salinity and hardness. Nonconstant monovalentidivalent ratios also will cause electrolyte
interactions
minerals
The disproportionate
through
cation
exchange.
with clay
effects of the salinity and hardness are accounted for by defining a weighted sum of the monovalent and divalcnt concentrations as an effective salinity. The C,.‘s in Fig. 47. I7 imply
effective
Phase Behavior
salinities.
and IFT. Early
MP flooding
literature
contains considerable information about the techniques of measuring IFT’s and what causes them to be low. 6x IFT’s were found to vary with the types and concentration of surfactant, cosurfactant, electrolyte, oil, and polymer and with temperature. one of the most significant nology,
all IFT’s
However, advances
were shown
the MP phase behavior.
in what was surely in all of MP tech-
to correlate
The correlation
directly
with
was proposed
not partition with the primary surfactant during a displacement the benefit of adding the chemical is lost; hence. surfactanticosurfactant separation effects are important.
by Healy and Reed,“” theoretically substantiatby severed by Huh, 6y and since verified experimentally al others. ‘I.‘” The practical benefit of this correlation is that relatively difficult measurements of IFT’s can be
Efforts
tant apex of the Fig. 47.17
to account
prism.
If the cosurfactants
for the preferential
originally
largely
supplanted
represen-
ments.
Indeed,
are func-
IFT’s has been inferred by a narrower subset of phasebehavior studies based on the solubilization parameter. hs
partitioning
cosurfactant include a quaternary phase behavior tation and a pseudophase theory. 62.63 3. The Type III salinity limits (C,, and C,,)
do
of the
by simple
in the recent
phase behavior literature,
measure-
the behavior
of
PETROLEUM ENGINEERING
To investigate
further
the relation
HANDBOOK
between
IFT’s
and
phase behavior, let V,,, V,, , and V, be the volume fractions of oil, brine. and surfactant in the microemulsion phase, respectively. According to Figs. 47. I4 through 47.16, the microemulsion phase is present at all salinities: hence. all three quantities are well-defined and continuous. Considering the Type II( -) behavior of Fig. 47.14, for example, of the microemulsion curve.
V,,, V,,., and V,, are the coordinates phase composition on the binodal
Solubilization parameters between the microemulsionoleic phases, F,,,, , for Type II( -) and III phase behavior. and between the microemulsion-aqueous phases. F,,,,,.. for Type II( +) and III are defined as F,,,,,=V,,iV,
. . . . . . . . . . . . . . . . . . . . . . . . . . . ..(9a)
and F,,,,,.=l’,,./l’,.
Fig. 47.18--Correlation
of solubilization
ratios with IFT.
. .
The IFT’s between u ,?lM’r are functions
. .
(9b)
the corresponding phases, u,,,(, and only of F,,, and F ,,,,~. Fig. 47.18
shows a typical correlation. ” The corresponding behavior
of the solubilization
pa-
rameters and IFT’s are shown in Fig. 47.19 in a different manner. Consider a locus at constant oil, brine, and surfactant
overall
a variable
salinity.
concentrations
in Fig. 47. I7 but with
If the nonideal
effects
are unimpor-
tant and the locus is at low surfactant concentration intermediate brine/oil ratios, (T,~(, will be defined low salinity
up to C,,,
ties. Both IFT’s III region,
and uInM. from
are the lowest
between
tion parameters
C,,, to high salini-
in the three-phase
C,, and C,,,
where
are also large.
and from
There
Type
both solubiliza-
is, further,
a pre-
cise salinity where both IFT’s are equal at values low enough ( - 10 -3 dyne/cm) for good oil recovery. This for this particular surfacsalinity is the optimal saliniv tant/brine/oil combination and the common IFT is the op-
timal IFT. Optimal
salinities
basis of equal IFT’s,
have been defined
as in Fig.
47.19,
on the
equal solubiliza-
tion parameters,
maximum oil recovery in corefloods, and equal contact angles. 50*71~72All definitions of optima1 salinity give roughly the same value; hence, since optimal phase behavior
salinity
is the same as maximum
ery salinity, generating an interfacially translates into generating this optimal the presence
0
1 4 1 1 I 1 1 I I 1 I L I I 1 I 0.4
0.6
1.2
I.6
SALINITY,
2.0
2.4
2 .a
3.2
“/o NoCI
Generating
of the surfactant
oil recov-
active MP slug salinity in situ in
material.
Optimal Conditions.
been three techniques
Historically for generating optimal
there have conditions
in an MP displacement. Fig. 47.19-IFT
and solubilization ratios
I. The MP system’s optimal salinity can be raised to that of the resident brine salinity in the candidate reservoir. This procedure philosophically is the most satisfying of the three design procedures given here and usually the most difficult.
Though
it has been the sub.ject of in-
tensive research, surfactants that have high optimal salinities that are not (at the same time) thermally unstable at reservoir
conditions,
excessively
retained
by the solid
surfaces, or expensive have not yet been discovered. Field successes with synthetic surfactants have demonstrated the technical
feasibility
of this approach.
however.
73 A scc-
47-15
CHEMICAL FLOODING
Fig. 47.20-Schematic
ond way to make the optimal
salinity
tion equal to the resident brine cosurfactant. 2. Resident salinity of a candidate wered
to match the MP slug’s
of surfactant adsorption on metal oxide surface
of the MP formula-
constant as does the retention
salinity
add
tant concentration). 2. In hard brines
can be lo-
causes the formation
is
reservoir
optimal
salinity.
to
This
is
which
(c,
is the adsorbed
the prevalence
of divalent
of surfactantidivalent
have a low solubility
in brine. ‘*
surfaccations
complexes, Precipitation
of
the main purpose of the pretlush step illustrated in Fig. 37.12. A successful pretlush is appealing because. with
this surfactantidivalent complex will lead to retention. When oil is present this effect is lessened by the surfac-
the resident salmtty
tam’s
oil wherever
lowered.
the MP slug would displace
it goes in the reservoir.
Preflushes
general-
solubility
in the oleic
3. At hardness
levels
phase.
somewhat
lower
than those re-
ly require quite large volumes to lower the resident SBlinity significantly owing to mixing effects and cation
quired for precipitation, the preferred multivalentisurfactmt complex will be a monovalent cation that can
exchange. 7’.75 With some planning, the function of the pretlush could be accomplished during the watertlood
exchange reservoir
preceding the MP flood. 3. The salinity gradient
the aurfactant
chemically with cations originally bound to the clays just as inorganic cations do.‘”
4. In the presence design attempts
ly lower the resident salinity displacement by sandvviching
to dynamical-
of oil in a II( +) phase environment reside in the oil-external
microemul-
the the
sion phase. Because this region is above the optimal salinity, the IFT is relatively large (Fig. 47.18) and this
overoptimal rcsidcnt brine and an underoptimal mobilitybuffer salinity. hh.67 The \ucccss of this procedure relies
phase and its dissolved surfactant can be trapped.” A similar phase trapping effect does not occur in the II( - )
on it being necessary
environment
that only a portion
be in the active region gradient tlonds mot signiticant crv
in
of the MP slug
for good oil rccovcry.
For salinity
the salinity of the mobility buffer is the factor in bringing about good oil rccov
x The salinity
vanrazes
to an optimum during the MP slug between
will
gradient
being
rcstlient
unccrtaintics. in providing the polymer in the mobility and being relatively
design has several other adto
design
and
process
a favorable cnv~ironmcnt for buffer. minimizing retention.
indifferent
to the surfactant
Surfactant
Retention.
Surfactants mechanisms.
are retained
buffer
misci-
microemulsion
Most studies of surfactant retention have not made the previously mentioned mechanistic distinctions; thercforc, which mechanism predominates in a given application is not obvious. high salinity
All mechanisms retain more surfactant at and hardness, which, in turn. can be attenu-
dilution
ated by adding cosurfactants.
through
pin,g,can be eliminated by lowering the mobility buffer salimty, at which conditions the chemical adsorption mechanism on the reservoir clays is predominant. There-
ct‘fcct.
one of at least four
because the aqueous mobility
bly displaces the trapped aqueous-external phase without permanent retention.
Precipitation
fore. there should be some correlation
and phase trap-
of surfactant
rctcn-
I, On metal oxide surfaces (Fig. 47.20) the surfactant monomer will adsorb physically through hydrogen hondinp and micelle-like associations with the monomer tails.
tion with reservoir clay content. Fig. 47.2 I is an attempt to make this correlation by plotting laborator and field surfactant retention data against clay fraction. 2‘) The cor-
and ionically bond vvith cationic higher surt’actant concentrations.
relation is by no means perfect since it ignores variations in MP formulation and clay type distribution as well as
surface sites (I).” C,. this association
At in-
tail-to-tail interactions with the solution monomers with proportionally greater adsorption (II and Ill). At and above the CMC (IV), the supply of monomers bccomcs
clt~dc?~
salinity effects. HowevJer. the figure does capture a general trend that is useful for a first-order estimate of retention in a given reservoir.
47-16
PETROLEUM ENGINEERING
A useful
0 LAB DATA 0 FIELD DATA
way to estimate
the volume
quired for an MP slug is through tal advance lag, FL). ”
1-o FD=p----, 4
HANDBOOK
of surfactant
the dimensionless
refron-
Pr c
(10)
P,C,
where
FD = frontal
WEIQHT
FRACTION
47.21-Surfactant
lag, dimensionless,
of rock,
p\- = density
of surfactant
CLAYS
mass/volume slug,
rock,
mass/volume
solution, C,
Fig.
advance
p,. = density
= concentration
retention and weight fraction of clays.
of surfactant,
surfactantimass 6,
= retained
mass
solution,
surfactant
surfactant/mass
and
concentration, rock (includes
mass all forms
of surfactants).
F” expresses the volume of surfactant retained at its injected concentration as a fraction of the PV. For best surfactant
usage, the volume
of surfactant
injected
should
be large enough to contact all of the PV, but small enough to prevent excessive production of the surfactant. Therefore, the MP slug size, V,I,v, should be equal to or somewhat larger than FD.
Field Response. analyses of Well der River
Fig. 47.22 shows the produced fluid 12- 1 in the Bell Creek (Carter and Pow-
Counties,
MT)
MP flood.
This tlood
used a
high oil content MP slug preceded by a pretlush that contained sodium silicate to lessen surfactant retention and reduce divalent cation concentration. Well 12-l was a producer
in the center of a unconfined
spot pattern.
Further
Refs. 47 and 82. Before MP slug injection Fig.
47.22-MP production response from Well 12-l. Bell Creek Pilot
single 40-acre,
five-
details on the tlood are available in Feb.
1979, Well
in
12-l was
experiencing low and declining oil cuts. MP oil response beginning in late 1980 is superimposed on this decline, reaching
peak cuts of about
13% about 6 months
later.
Note that. just as in polymer flooding, the pre-MP decline must be clearly established for accurate evaluation of the MP oil recovery.
The surfactant
is preceding
the oil in
Fig. 47.22 because of an excessively large content of water-soluble, inactive disulfonate in the MP slug. Simultaneous oil and surfactant production is a persistent feature of field MP floods, probably because of heterogeneities and dispersive mixing. Other significant features in Fig. 47.22 are the evident presence of the pretlush preceding the MP slug, inferred from the maxima
0.6 Et? 0.4 h
0.2 0 0
0.2-0:4
0.6
0.8
MOBILITY
1.0
1.2
1.4
BUFFER SIZE
1.6
1.8
2 0.
3.2
( VM~ 1
in the pH and silicate cient removal factant. Fig. a survey
Recovery Fig.
Efficiency
47.23--Recovery
vs. Mobility
Buffer
Size
efficiencies from 21 MP field tests
47.23
cremental
concentrations.
of the calcium shows
oil
recovery
oil recovered/OIP
and the very
cations
efficiency,
EK
at start of MP process),
of more than 40 MP field
effi-
ahead of the sur-
tests correlated
(infrom as a
function of mobility-buffer slug size. As of the date of the survey there were no commercial projects reported. Similar analyses on other process variables showed no or weak correlation. X3 The strong correlation in Fig. 47.23 indicates the importance of mobility control in MP design.“’ Note also from this figure that ultimate oil recovery
efficiency
averages
about
30%
in field
tests.
47-17
CHEMICAL FLOODING
Performance
Prediction.
be achieved
for efficient
Generally.
three things
oil recovery.
factant slug must be propagated
must
X4 ( I ) the MP sur-
in an interfacially
active
mode, (2) enough surfactant must be injected so that some of it is unretained by the permeable media surfaces, and (3) the MP displacement must be designed so that the active surfactant sweeps a large portion of the reservoir without
excessive
dissipation
(because of dispersion)
or
channeling. Attaining
the first goal is the result of formulation
based on the phase-behavior
work
concepts discussed previous-
ly. The extent to which the second and third goals are satisfied depends on prevailing economics, which, in turn, depends
on the oil-recovering
ability
ess. The next few paragraphs
of the entire
describe
a simple
proc-
Fig. 47.24-Relationship between MP volumetric sweep efficiency, heterogeneity, and slug-size retention ratio.
proce-
dure by which oil recovery and oil rate-time curves may be estimated for an interfacially active MP process. Since there are innumerable ways in which interfacial activity may be lost. the procedure is most accurate for processes
as much as possible, reservoir.
that clearly Recovery
ciency,
with
conditions
of the candidate
fractional flow to give an oil rate-time curve. Space considerations will limit many of the details, which may be
Volumetric Sweep Efficiency. Volumetric sweep effiE v, is the volume of oil contacted divided by the volume of target oil. EV is a function of MP slug size, based on the V,,, , retention, FD, and heterogeneity Dykstra-Parsons coefficient, KDP. Fig. 47.24 shows this KDP may be estimated from geologic study, relationship.
found
from matching
timating
satisfy
the first
design
goal. has two steps: es-
Efficiency. This procedure
the recovery
proportioning
efficiency
this recovery
in Ref.
of an MP flood and then
according
to in.jectivity
and
80.
The recovery efficiency. ER, of an MP flood is the product of a volumetric sweep efficiency, E”. a displacement efficiency. En, and a mobility buffer efficiency. E MB
..
ER=EDEVEMB,
.
(11)
(a typical
the previous
value would
waterflood,
Eq. IO on the basis of the retention slug concentration,
C,,
or from core data
be 0.6). The FD is estimated porosity,
level,
from
C,, . surfactant
and rock and fluid den-
sities. 47.21
C’, can come from a laboratory coreflood, Fig. (if clay fraction is known), or by using C, =0.4
mglg
as a default.
L’,,s and C,, are from
the proposed
design. Each quantity
must be calculated independently. The displacement efficien-
MoKlity
Displacement Efficiency.
ciency,
Buffeer Efficiency.
The mobility
EBB, is a function
buffer
effi-
of EV and KDP.
cy of an MP flood is the ultimate (time-independent) volume of oil displaced divided by the volume of oil contacted. ED=1
-p,
S’,,
.
.(l2)
S OM where
S’,,,
where EMBr is the mobility
are the ROS to an MP and water-
and S,,.
flood, respectively. S,,,,. must be known, be obtained from a large slug (free from
but S’,,, can the effects of
surfactant retention) laboratory coreflood. Low values of S’or indicate successful attainment of good interfacial activity in the MP slug. If coreflood results aren’t availamay be estimated ble, S’,, “field” capillary number.”
from
a CDC
.._..
N,=0.565q~L,,y,~l(h~),
by using
a
..(13)
number,
CL0 = oil viscosity, h = net thickness,
A = pattern
dimensionless,
time,
increasing
linearly
units. For screening
to a peak (maximum)
breaks through,
The first step is to calculate and surfactant
and
oratory purposes,
extrapolated
Calculation of q,, vs. t Plot. The production function (oil rate vs. time) is based on ER and the following procedure. The dimensionless production function is assumed to be triangular with oil production beginning at oil bank
linearly to sweepout time. The triangular by the reservoir heterogeneity.
rate,
area.
Eq. 13 is in consistent
efficiency
(l4a)
The recovery efficiency now may be calculated from Eqs. 1 I through l4a. The reasonableness of the value may be checked with Fig. 47.23.
cut when the surfactant
q = injection/production
buffer
.
to VM~ =0 and VM~ is the mobility buffer volume, fraction V,,. Eq. 14a was obtained from a numerical simulation.
arrival where N,. = capillary
.
E,+,Be=0.71-0.6KDP,
breakthrough
oil
and decreasing shape is imposed
the dimensionless
oil bank
times for a homogeneous
lab-
coreflood.
as-
sume a controlling IFT of lop3 dyne/cm [ 1 pN/m]; the CDC curve chosen to estimate S’,,r should be consistent,
(14b)
PETROLEUM ENGINEERING
! ? M,,-M,, tl)r,h c>
dimensionloss.
and the peak oil cut. ,f&.
tl)1 of,,--I)
.fy,n=
HANDBOOK
i,
,f;,,,
(17)
The final step is to convert the dimensionless production function to oil rate, yo. vs. time. t. This follows from ----
q,,=qf;,
(l&i)
and
.
t=V,,tD/q,
.(18b)
is the oil cut. tD is the dimensionless
wheref,,
.f;, and tn are any points
on the triangular
time. and
oil recovery
which begins at (t’“,,/, ,f;,;). peaks at (t’ljA .f;,,,k). 0). The dimensionless time at comand ends at (t’n,t., plete sweepout, t’D,,,,., is selected to make the arca un-
curve,
II 0
I
b I
I 100
roe
300
500
400
TIME.
J 700
WO
-tlD
der thef;,
equal to ER,
curve
t’D,,l.=t’noh +2E,$,,,.,,Jf;,,,,,
DAYS
Fig. 47.25-Comparison between predicted and observed oil rate-ttme responses for the Sloss MP pilot.
(19)
A comparison of the results of this procedure with the Sloss field MP pilot is in Fig. 47.25. Details of this match and other
matches
are in the original
references.
High-pH Processes The t~,=l+F,-S’,,,.
,
__ (14c)
_.
final
chemical
voir, a finite volume graded mobility buffer
where t Lhh = oil bank arrival time, dimensionless. fraction, s ,,,, = oil bank saturation, S,,, = initial
oil saturation,
fr,,,
= oil bank oil fractional
f,,,
= initial
tLl\
= surfactant
oil fractional arrival
fraction, flow. flow,
time,
jected
fraction.
fraction.
S,,h andf,,,, permeability
laboratory
while
High-pH
dimensionless.
M,.
is high-pH
of the oil-displacing chemical, a driving agent. and the entire proc-
in high-pH
flooding
it is generated
in situ.
Chemistry
anions (OH -). defined as
large concentrations
of the hydroxide
The pH of an ideal aqueous
solution
is
experiment.
The second step is to correct these values for the heterogeneity of the candidate reservoir by using an effective ratio.
process
and
may be estimated from the oil/water relative curve as described previously in Refs. 80
and 85. or from
EOR
ess is driven by chase water. Moreover. for both highpH and MP flooding the oil-displacing chemical is a surfactant; however, for MP flooding the surfactant is in-
High pH’s indicate
mobility
flooding
flooding (Fig. 47.26). As in polymer and MP flooding. there is usually a brine preflush to precondition the reser-
pH= where
where
ioc,
-log
+ ,
.
the concentration
.
of hydrogen
(20) ions,
CH + , is in
mol/L. As the concentration of OH - is increased, the concentration of Hi decreases, since the two con-
(1%
centrations
K,,, = (’ The corrected
breakthrough
times are now
are related through
, .. ..
.
(16a)
(21)
cies or adding gen ions. (16b)
t’D(,,, is the corrected oil bank arrival time, dimensionless, tlDr is the corrected surfactant arrival time.
is nearly constant.
These con-
siderations suggest two means for introducing high pH’s into a reservoir: dissociation of a hydroxyl-containing spe-
Many
chemicals
chemicals
the most commonly where
. . ... .. .
CH~O
and
t’D,=tDs/Mc.
of water,
OH-)(CH+)
and the water concentration
ttDoh=tDot,lMe
the dissociation
that preferentially
bind hydro-
could be used to generate high pH. but used are sodium
hydroxide
(caustic,
NaOH). sodium orthosilicate. and sodium carbonate (Na2C03). NaOH generates OH by dissociation: the
CHEMICAL
47-19
FLOODING
Fig. 47.26-Schematic
latter two through the formation of weakly acids (silicic and carbonic acid, respectively) free H ’ ions from solution. High-pH ally have been used in field applications ranging
up to 5 wt% (in.jected pH’s
slug sizes up to 2O%PV.
tially
less costly.
OH
of 1 I to 13) and with amounts of chem-
the surfactant usage in chemicals are substan-
This cost advantage
by the historically flooding.
lower
oil
dissociating that remove
chemicals generin concentrations
The resulting
icals are quite comparable with MP flooding: however, high-pH
of high-pH flooding process
must be discounted
recoveries
by itself is not a surfactant.
in
high-pH
since the absence of
a lipophilic tail makes it exclusively water-soluble. If the crude oil contains an acidic hydrocarbon component, HA,,. some of this, HA,,., can partition phase where it can react. Xh _.
HA,,F-?A,;+H+.
The exact nature of HA,, dependent
terfaces.
of surfactant Fig.
47.27
is required presents
bers based on the work
Displacement Oil recovery
to saturate oil/brine
a histogram
in-
of acid num-
of Jennings.87.8x
Mechanisms mechanisms
in high-pH
flooding
have been
attributed to eight separate phenomena. 89 This chapter concentrates on only three: IFT lowering. wettability reversal,
and emulsion
formation.
The last two mecha-
nisms also are present in MP flooding but are dwarfed by the low-IFT effect. With smaller ultimate oil recoveries, the distinction among effects becomes important in high-pH
flooding.
to the aqueous
__
is unknown
amount
.
and probably
on crude oil type. The deficiency
e-4
highly
of hydrogen
ions in the aqueous phase will cause the extent of this reaction to be to the right. The anionic species A,; is a surfactant that can have many of the properties and enter into most of the phenomena described above for MP flooding. If there is no HA,, originally present in the crude. little surfactant
can be generated.
A useful
procedure
for
characterizing crudes for their attractiveness to high-pH flooding is through the acid number. The acid number is the milligrams
of potassium
hydroxide
(KOH)
required
to neutralize I gram of crude oil. To make this measurement, the crude is extracted with water until the acldlc species HA HA,,
, A,;,
is removed.
The aqueous
and H ’ is then brought
phase containing
to pH=7
by adding
the KOH. For a meaningful value, the crude must be free of acidic additives (e.g.. scale inhibitor) and acidic gases (CO? or H?S). an acid number
A good high-pH flooding crude will have of 0.5 mgig or greater. but acid numbers
as low as 0.2 mgig may be candidates,
since only a small
0
I
2
ACID INDEX INTERWL
Fig. 47.27-Histogram
4
3 (E&Cl4 05mp.
KOH/p RAffiE)
of acid numbers
3
47-20
PETROLEUM ENGINEERING
M
1 M A
0.26 0.50 1.00
wt. wt. wt.
pH system.
46 NaCI % NaCI ‘16 N&I
However,
Nelson PI a!. ‘)(’show that a cosur-
factant can increase the optimal tem much
like
HANDBOOK
in MP
salinity
in a high-pH
sys-
systems.
See Chap. 28 for a discussion of wettability and its effects on petrophysical properties. Owens and Archery’ showed that increasing the water wetness increased ultimate oil recovery,
IO’
others
I-
\\ \\ \\ \\ \:
Y z
lOOr
where the wettability
was reported
as
decreasing the water/oil contact angle measured on polished synthetic surfaces. This has also been shown by
SOLUSILIZATION
using high-pH
chemicals.9’.YX
The increased
recovery
is the result of two mechanisms:
meability
effect,
which
a relative
causes the mobility
placement to decrease, and a shifting
oil per-
ratio of a dis-
of the CDC (see Fig.
47.1 I).
E a
et al. 94 have reported
Cooke
improved
oil
recovery
with increased oil wetness. Other data show that oil recovery is a maximum when the wettability of a permeable
t
medium
is neither
the latter
lo-’ -
strongly
information,
water-
nor oil-wet.
the important
factor
‘)5 Given
may be the
change in the wettability rather than the actual wettability of the final state of the medium. In the original wetting state of the medium,
the nonwetting
large pores and the wetting
phase occupies
phase small pores. If the wet-
tability of a medium is reversed, there will be nonwetting fluid in small pores and wetting fluid in large pores. IO-’
IO-”
IO-’
WEIGHT Fig. 47.28-IFT’s
IC
% NaOH
for caustic/crude/brine
The resulting fluid redistribution, as the phases attempt to return to their natural state, would make both phases vulnerable High-pH
systems
to recovery through viscous forces. chemicals can cause improved oil recovery
through the formation of emulsions. The emulsification produces additional oil in at least two ways: through a The generated interfaces,
surfactant,
A ,,
aggregates
which can lower IFT. 86 In general,
ering is not as pronounced
as in MP flooding
mobility ratio lowering since many of these emulsions have a substantially increased viscosity and through
at oil/water such lowbut, under
certain conditions, can be large enough to produce good oil recovery. Fig. 47.28 shows IFT measurements of caustic solutions
against Long Beach crude oil at various
brine
salinities. The IFT’s are sensitive to both NaOH concentration and salinity, showing minima in the NaOH concentration range of 0.01 to 0.1 wt %. The decrease in IFT in these experiments is limited by the spontaneous emulsification of the oil/water mixture when the IFT reaches a minimum. There are many MP and high-pH
similarities flooding.
in the low-IFT
effects
The data in Fig. 47.28
in
show
a clear resemblance to the data in the upper plot of Fig. 47.19 except they are plotted vs. NaOH concentration (presumed proportional to A, concentration) instead of salinity. This suggests an optimal wt% NaCl for a 0.03 wt% NaOH
salinity of about solution. Indeed,
I .O the
work of Jennings et al. 87 has shown that there is an optimal NaOH concentration for a given salinity in oil recovery experiments. Moreover, emulsification effect when IFT’s one would expect from Fig. centration above the invariant
the presence of the are low is exactly what
47.17 at a surfactant conpoint surfactant concentra-
solubilization
and entrainment
of oil in a flowing
aque-
ous stream. The first mechanism improves displacement and volumetric sweep as do the mobility control agents discussed previously. Local formation of highly viscous emulsions should be discouraged, however, as these would promote viscous fingering from the less viscous oil-free high-pH solution. The solubilization and entrainment mechanism would be more important when the IFT between the swollen water phase and the remaining crude is low. Fig. 47.28 shows that for certain conditions,
emul-
sification and low IFT’s occur simultaneously. McAuliffe showed that emulsions injected in a core and those formed in situ give
comparable
oil recoveries.96.97
Rock/Fluid
Interactions
Interactions of the high-pH chemicals media minerals can cause excessive propagation ble medium. fluid
of these chemicals throughout the permeaThis chapter discusses three aspects of rock-
interactions:
pounds,
and the permeable retardation in the
cation
formation exchange,
of divalent/hydroxide and mineral
com-
dissolution.
OH - ions themselves are not appreciably bound to the solid surfaces; however, in the presence of multivalent cations
they can form
hydroxyl
compounds,
tion. This suggests that the data in Fig. 47.28 showing a Type II( -) phase environment at low NaOH concentrations are Type II(+) at high (similar to what would be expected from the dilution effect in MP flooding). Further work
is necessary
to establish
phase-behavior definitively, concentration A; is likely
the connection
since the actual to be much lower
M +-‘+x(OH
-)FiM(OH),,,
to MP
which,
being relatively
surfactant in a high-
lution.
This reaction,
(23)
insoluble, in turn,
can precipitate
lowers
tion, and also can cause formation
from so-
the pH of the solu-
damage through
pore
47-21
CHEMICAL FLOODING
blockage and fines migration. The anionic surf&ant species A,, can interact with the inorganic cations in solution just as in MP flooding; however, the interaction with the divalent
cations usually
takes precedence,
particular-
ly in hard brines (see Fig. 47.3) or where there are substantial quantities of soluble multivalent minerals. Because of these interactions A ,;. high-pH
and those involving
processes
the surfactants
are as sensitive
to brine salinity
and hardness as are MP processes. Other high-pH rock/fluid interactions
are intimately
sociated
are hydrous
with the clay minerals.
Clays
asalu-
minum/silicate compounds that occupy the smallest (less than 2 microns) particle size in typical media. Macroscopically. clays occur as segregated streaks of variable degree of continuity throughout a typical reservoir, or as distributed clays.
which can line pore walls or fill pore throats.
Distributed clays are of most concern here, since these have quite large surface areas (15 to 40 m’ig clay), and therefore cally,
can exhibit
considerable
clays can take on a variety
reactivity.
9X Chemi-
of formulas
that differ
substantially in their reactivity even though the differences in their molecular formulas are apparently minor. The ability of a clay mineral to exchange divalent cations with an aqueous solution can drastically change the ionic environment tact. Clays
of a solution
with
have excess negative
substitution of +2-valence erals within the octahedral The cation
exchange
which
charges
it is in con-
caused by the
minerals for +3-valence minor tetrahedral crystal lattice. 99
capacity,
Zv,
excess negative charge; typical Zv’s
is a measure
of this
are I to 10 meqi 100 g
clay for kaolinite and 100 to 180 meq/lOO g clay for montmorillonite. These free anionic sites are covered with cations from the solution, of selectivity
each of which has a specific degree
for the particular
clay site. In general,
H +
has high clay selectivity, and divalent cations are bound more strongly than are monovalents. This means that the anionic
sites
can be occupied
and/or
divalents
predominantly
clays
by
H+
even when clays are in contact with rela-
tively soft brines. Any subsequent lyte environment of the contacting to take or give
change in the electrosolution can cause the
up these cations
with
a possible
detrimental effect on high-pH (and MP) flooding. H ’ cations can exchange on the clay sites with the injected
sodium
according
w
to
Fig. 47.29-Effluent histories pH from laboratory corefloods. Experimental curves are solid lines with points, theoretical results are dashed lines.
is determined
N,, =+k
Sclay-NafH’.
.(24)
where
L/u,,., .
rcverxiblc centration 47.29
represents a mineral
site. I”) The
reaction Eq. 24 will clearly cause the H ’ conto increase with a resulting pH decline. Fig.
shows the extent
by cation exchange of the lower pH’s in-jection to attain Unlike
exchange
MP
of the OH -
in laboratory may require the injected
flooding.
retardation
tloods.
caused
Note that many
more than 3 PV of fluid pH.
high-pH
chemicals
can
react
number,
.
k is the reaction
.(25)
rate constant,
ditions are equivalent and a prototype field
time -’ , and L is
between a laboratory experiment flood, ND, clearly will be much
larger in the field than in the laboratory owing to the much larger length scale. A larger ND, implies more reaction relative
to the residence
time within
the system.
Thus,
it follows that the penetration distance-the distance traveled by full-strength OH - ions-will be considerably smaller in the field than in the laboratory. Bunge and Radke, who illustrate this with several numerical calculations, caution against extrapolating
laboratory-measured
values of OH - consumption to field cases unless the discrepancies in ND, have been taken into account. “”
Field Results High-pH bility
field tests of reversal
articular interest include a wettaflood,Y6 and a test, 99 an emulsion flood. lo3 Fig. 47.30 shows the produc-
polymer-driven tion data from a high-pH
flood conducted
‘04 The crude oil was 20”API
ty, and the 0.2 wt%
NaOH
0.23.PV slug. There are many features where “clay”
DamkGhler
the medium length for a first-order reaction. ND, is the ratio of the reaction rate to the bulk fluid rate. If all con-
field. clay-HfNa’
by a dimensionless
ND,,
in the Whittier
with a 40-cp viscosi-
chemical
was injected
as a
in these data that are common
to the responses of the other chemical
flooding
processes
in Figs. 47.6 and 47.22. The oil production rate declines as the total fluid production increases, indicating a declining oil cut. The oil rate response to the caustic injection is again superimposed is extrapolated
on the waterflood
to estimate the IOR.
decline,
which
(There are two water-
Hood decline curves in Fig. 47.28. one based on the actual decline and one based on computer simulation.) The to 470,000 STB of oil produced by the caustic was considered a success by the operators.
directly with clay minerals and the silica substrate to cause consumption of OH ~ ions. The reactions with clays are
350,000 injection
manifest by the elution of soluble aluminum and silica spe“” The resulting soluble cies from core displacements.
Table 47.3 shows a summary of data from complctcd high-pH field floods. Note the wide range in reservoir
species
and oil characteristics
hydroxyl
subsequently reactions
can
cause
precipitates
through
as in Eq. 24. lo2 The rate of hydrox-
yl consumption from this slow reaction (cation exchange is generally fast enough so that local equilibrium applies)
the flood.
“” IOR.
and in oil saturation
expressed
as a fraction
at the start of of PV. ranges
from 0.0006 to 8.0. which translates into recoveries, expressed as a fraction of the OIP at the project start, that
PETROLEUM ENGINEERING
47-22
TABLE 47.3-SUMMARY
p. at
Field, Location, Operator Bradford, PA (Several tests by several operators) Southeast Texas (Exxon) Harrisburg, NE (Amoco)
30 10
saline 300
1,250 5,900
64 40 (estimated) watered out 51
206 16
36 -
850 -
3.140 -
30
137
fresh hardness (1) -
1,500
15,000
2,200
Whittier, CA (Chevron)
40
120
Brea-Oltnda, CA (Umon)
90
135
17 to 60
140
wjith but slightly floods
47.1).
-
Watered out 50
22.5
155
lower limit on the reservoir permeability. although case of polymers used in polymer or MP flooding
smaller than those report-
(Table
Depth (ft)
16 to 20 33 to 35 15
115
polymer
Porosity Wd
60 40 watered out
2.26 15
ed from
Injection Water Salinity mm TW
Net Thickness ut)
112 200
Northward-Estes, TX (Gulf) Singleton, NE (Sinclair)
arc comparable
Oil Saturation at Project Start WI
ioF)
75 1.5
Orcutt l-111,CA (Union)
OF HIGH-pH FIELD TESTS
Residual Reservoir Temperature
Residual Reservoir Temperature iCP,
HANDBOOK
Of equal impor-
in the there
tance is the STB of IOR produced per pound of chemical in.jccted (0.015 to 0.43 in Table 47.3). This is substan-
is a technical limit imposed by the inability to propagate large molecules through very small pore spaces. Deep
tially lower than the polymer cost of the high-pH chemical
reservoirs usually imply the ability face pressures with accompanying
flood values; however. the is also substantially lower.
rates. This beneficial effect is offset by the susceptibility of polymers to chemical degradation at elevated temper-
Summary Fif.
to apply larger surincrease in in,jcction
atures. High-pH
47.3 I presents screening
guides for the three major
tcmpcrature,
processes arc also more reactive
which
causes excessive
at high
consumption.
chcmicul flooding processes presented in this chapter bused on the work of Taber and Martin. I”’ Though there
The information future development
arc many other possible guidelines. the figure focuses on three common reservoir parameters: oil viscosity at reser-
( I) the development of more cost-effective chemicals such as surfactants and polymers that are more salinity resis-
voir conditions. permeability. and depth. The guides are intended as rules of thumb for candidate reservoir selcction and arc not substltutcs for detallcd reservoir eval-
tant. have minimal or can be recyolcd.
uation.
pH flooding
Chemical flooding application usually is limited moderate to low oil viscosities because ofcconomics.
sign procedures
in Fig. 47.3 I suggest the avenues of for chemical tlooding EOR processes:
retention. can be manufactured onsite. (2) development of more efficient de-
such as applying
design,
MP technology
(3) removing
technical
to high-
limitations
the oil viscosity increases. more of the rcspcctibr: chemcal is rcquircd to attain food mobility control. This causes
diction
a direct
considerable research so that the economic viability chemical flooding will become commonplace.
penality
in increased
in chemical
project
0
cost and an indirect
life.
Similar
1363
1964
considerations
7363
1366
Fig. 47.30-ProductIon
mates.
penalty place a
7367
on
the use of water-soluble polymers. particularly as they relate to temperature sensitivity, and (4) mot-c reliable pre-
to As
7363
1969
techniques, Each
1370
particularly
general
,371
area
1372
response from the Whittier field high-pH flood
as they relate to risk estiwill
1971
continue
to
prompt of
47-23
CHEMICAL FLOODING
TABLE 47.3~SUMMARY
Type of Chemical Material
OF HIGH-pH FIELD TESTS (continued)
Chemical Concentration Injection (WWO)
Acid number (w KOW
-
-
-
IOW
0.013
0.093
0.003
0.03
NaOH NaOH
0.22 low
5.0 2.0
15 8
2.55 0.55
8.0 0.023
0.03 0.042
NaOH
-
0.2
20
0.16
0 05 to 0.07
0.32 to 0 43
0.12
-
-
-
0.42
0.017
0.028
0.0006
ortho-silicate ortho-silicate
A
0.6
Nomenclature = pattern
area
C,,, = low effective
salinity
C Cl, = high effective = concentration = retained
surfactant
concentration. rock
mentioned
forms
shear rate ‘z C’= effective e I;5 = shear rate when polymer
all of the of
solution
is % of high and low EMI,
= mobility
buffer
efficiency
E MBC
= mobility
buffer
efficiency
j;,/,
= oil bank oil fractional
f;,,
= initial
oil fractional
values,
viscosity Eq. 3
extrapolated
flow, flow,
fraction
fraction
= peak oil cut
DEPTH,
FD = frontal advance lag. dimensionless ratios between the F I?,0 = solubilization microemulsionioleic
between
microemulsioniaqueous
F,,: = permeability reduction F, = resistance factor
k,,
resistance
K IIp K,, M,, M* M"
= dissociation = shock
solution
to polymer-rich
(water)
coefficient
coefficient
mobility
mobility
= endpoint
factor
coefficient
= Dykstra-Parsons = effective
the
phases
factor
to polymer
= permeability
K = power-law
mobility
FEET
phases
ratios
k,, = permeability
md
mass
(includes
surfactants)
FRI- = residual
PERMEABILITY,
mass
solution
surfactantimass
= solubilization F 1,111
- CENTIPOISE CONDITION
limit
of surfactant,
previously
OIL VISCOSITY AT RESERVOIR
0.015 to 0.030
limit
salinity
surfactantimass
f”lIL
bbl incremental Oil per Ibm Chemical
3.2 2.0
2.4
Na,CO, NaOH
6,
Recovery, Fraction PV
-
Na,CO,
C,
Slug Size (O/oVP)
Ibm chemical (bbllbbl VP)
ratio ratio ratio
of water
phase
Fig. 47.31-Comparative evaluation of reservoir parameters for chemical flooding.
PETROLEUM
47-24
I, = power-law exponent N, = capillary number. dimensionless PI. = left plait-point designation designation P,q = right plait-point s illi -~ oil bank saturation, fraction =
initial
=
ROS to an MP flood
0,II
=
ROS to a waterflood
St,
=
saturation
t ml/l
=
oil bank arrival
t 'DO/~
=
corrected
s,,i s
I(,).
s
oil saturation.
fraction
of polymer-rich time,
(water)
phase
dimensionless
oil bank arrival
time,
dimensionless
t
t11\
=
'I).!
=
surfactant
arrival
corrected
surfactant
time,
dimensionless
arrival
time,
dimensionless dimensionless superficial
time at complete
flux
phase.
(water)
Lit
superficial
velocity
of water
I',,
=
VMB
=
mobility
v,,, z,/
= =
MP slug size of displaced
cation
sweepout
of polymer-rich
buffer
volume.
exchange
phase
fraction
capacity
hi
=
mobility
x(J
=
mobility
of displacing
fluid(s)
A,,
=
mobility
of polymer
A,,
=
mobility
of water-rich
phase
X,,‘,,
=
tnobility
of water-rich
phase after
agent(s) solution polymer
injection owl?
=
mobility
of water-rich
polymer tJ,l = occ,J -
phase before
injection
apparent
viscosity
polymer
solution
of polymer
solution
viscosity
below
some low
viscosity
above
the
shear rate mP,,
-
polymer
solution
critical CL\,. = Pr P,
shear rate
viscosity
= density = density
of the displacing of rock.
water
mass/volume
of surfactant
slug,
rock
mass/volume
solution u ,,l,i =
IFT
between
the microemulsion
phase and
between
the microemulsion
phase and
oil (-J,,rn =
IFT
water u,ic,
=
IFT
between
the water
and oil phases
Acknowledgments Scvcral useful discussions with R.S. Schechter Pope are gratefully acknowledged.
and G.A.
References
4. Dyer. A.B Caudlc. B.H.. and Ertchwn. R A : “Oil Productnw r,ltcr Brcnhthrqh ah lnllucnccd hy ,Mobdity Ratio: J. PC/. kc II. (Apnl 195-l) 27-32: T~,o/i\. AIME. 201
ENGINEERING
HANDBOOK
5. ClawJge. E.L. “Predictwn (II’ Recwcry III Unstable Misihlc Floodmg.” Sot. PC/. F,ig. J. (Aprd 1977) 143-SS. 6. Reznik. A.A. 1 Enick. R.M.. and Punvclkcr. S B.: “An Analytxal Extemion ot’the Dykstra-Parsons Verttcal Stratificatton DISmete Solution to a Contnwous, Real-Tmw Basis.” .5x. Per. Gr,q. J. (Dec. 19X4) 64-56. 7. Dykstra. H. and Parsons. R L.: “The Prediction of 011 Recovcry by Watertlood: Secondary Recovery of 011 m the United State\.” Bull.. API. Dallas (1950). 8. Johnson, C.E. Jr : “Prediction of Oil Rccwcry by Waler FloodA Simplilied Graphical Treatment of the Dykr. T.J “Factorz Inilw encing Moblllty Control By Polqmcr S~~lut~on\.” J. /‘cr. TK/I. (March 1971) 391-401. T/r,w.. AIME. 251. 7.5. Hlrasahi. G.J. and Pope. G.A : “Analy\i\ of F&%x\ Intluencq Mobility and Adwrption in the Flow OFP[,I)mcr Solution Throu:rh Porow Media.” Sor, Per. i?r,v. J. (Aug. 19741 337-46. 76. Shupc. R.D.: “Chcmad Stahllity of Poly.srylamidc Polymct-\.” J. PC,/. Tdi. (Aug. I981 ) Ii 13-79. 27. Maerher. J.M.: “Mechanlcul Defrnd;mon\ 01 Purtlnll) Hydralyrcd Polyacrylatnidc Solutnw m Unc~n~wl~dated Porou\ ML’dia.“ So. Per. k-q,. J. (Aug. lY76) 177-7-1. 2X. Sertght. R.S.: “The Eltect\ ot Mechamcal Deqrdatton and Viwo~ &\IIC Behavior on In,jcctivq ~~l’P~~I)acrjlam& Solutwn~.” .Sfx PC/. L-q. J. (June 19X3) J75-XS. 20. Clampttt. R.L. and Reid. T.R : “An Econwmc Pol~murllwxJ in the North But-hnnh Unit, 0+x Cwnt>. Ohlahotnn.” papcl SPE 5552 preenccd at the 1075 SPE Annual Technical ConI&cncc and Exhthitlon. Dallas. Scpt 7X-Oct. I.
CHEMICAL
FLOODING
3 I, Gractaa. A.. (‘I trl.: “Criterta for Structurmg Surl’actant~ to MaximILe Solubilizatton ot Oil and Water: Part I-Commerelal NonhllC~.” SOCK.Pet. Or,y. 1. (Oct. 1982) 743-49. 32. Bar&at. Y. <‘fI// : ‘. Crttcrta for Structuring Surtactant\ to Maxttntzc Solubilization of 011 and Water.” J. Cdlortl Irrterfirw Sri. (1983) 92, No. 2. X-74. 33. Ovcrbcek. .I. Th. G: “Colloidh and Surface Chemistry. A SelfStudy SuhJect Guide. Part 2. Lyophobic Cotloids,” 6’lt//.. Center for Advanced Engineermg Study and Dept. of Chemtcal Engineering. Ma\sachusett\ Inst. of Technology. Camhtidge. MA (1972). 34. Patton. J.T.. (‘I ol. “Enhanced Oil Recovery by CO z Foam Flooding.“ tinal report, Contracr No DOEiMC/O325Y-15. U.S. DOE (April 1982) 3.5. Khan. S.A.: -‘The Flow of Foam Through Porous Media.” MS thests. Stanford U.. Stanford. CA (1965) 36. Fried. A.N.: “The Foam-Drive Procr\\ tnr Increasing the Recovcry d Oil.” Report of Invcstigattons 5866. U.S. Dept. of the lnlerior (IYM)) 37 Bernard. G.G. and Helm. L.W.: “Effect of Foam on Pcrmeahihty of Porous Media to Gas.” Snc. Prr. En,is. J. (Sept. 1964) 267-72: Trtrric.. AIME. 231. 38. Bernard. G. G.. H&n. L.W.. and Jacob\. W.L.. “Effect of Foam on Trapped Gas Saturation and on Pcrmcahiltty of Porous Media to Water.” SIX.. Per. &. J. (Dec. 1965) 2Y5-300: Trwts.. AIME. 234. 39. Holbrook. S.T.. Patton, J.T.. and Hhu, W.: “Rheology ot Mohtltty-Control Foam\,” Srx. Per Oz,q J. (June 1983) 456-60 40. Hirasaki. G.J. and Lawon. J.B.: “Mechanisms of Foam Flow in Pornw Media: Apparent Viwosity m Smooth Captllartes.” So<.. Per. Gtg, J. (April 1985) 176-90. 41. Helm. L.W.: “Foam InJectton Test m the Stggtns Field. Illrnot~.“ J Pet. Td?. (Dec. 1970) 1499-1508. 42. Larwn. R.G.. Scrrven. L.E , and Davts. H.T.: “Percolation Thcory ot Residual Phases in Porous Media.” N~~tr#re(lY77) 268, 409-13. 43. Stcgemeter. G.L.: “Mechanisms ot Entrapment and Mohtltrabon of Oil in Porous Media. hnprowtl Oil R~cowry hx Surfiw 1~111, and Polwler F/00&~. ” D.O. Shah and R.S. Schechter (eds ) Academic Press. New York City (1977) 55-93. Flow in Porous 44. Mohanty, K K. and Salter. S.J.: “Multiphase Media: Part 3-Oil Mobilization. Transverse Dispersion. and Wettuhtlity,” paper SPE 12127 presented at the 1983 SPE Annual Technical Conference and Exhihition. San Francisco. Oct. S-8. 45. Larson. R.G.: “From Molecules to Reservoirs. Problems in Enhanced Oil Recovery.” PhD dissertation. U. ofMtnnesota, Minneapoli\ (1980). 46. Catnilleri. D.: “Micellar/Polymer Flooding Experiments and Compartson with an Improved I-D Simulator.” MS thesis. U. of Texas, Austin (1983). 47. Helm. L.W.: “Design. Performance and Evaluatton of the Unitlood Micellar-Polymer Process-Bell Creek Field,” paper SPE I I196 prewntcd at the 1982 SPE Annual Techntcal Conference and Exhibition. New Orleans. Sept. 26-29. 48. Goparty. W B Meabon. H.P.. and Milton, H.W. Jr.: “Mobility Control Dc\ign for Miscible-Type Waterflood\ Using MtcelJar Solutions.” J. Per. Tdz. (Feb. 1970) 141-47. 49. Wmsor. P. A, : .!Xwtr Propmrev rfAmphiphi/ic Contppo~rnrl.~. Butterworth\. London (1954). 50. Healy. R.N.. Reed. R.L., and Stenmark. D.G.: “Multiphase Microemulston Systems.” Sot. Per. Gtg. J. (June 1976) 147-60. 51. Nelw, R.C.. and Pope. G.A.: “Phase Relationships tn Chemcat Floodtng.” SM. PH. 01g. J. (Oct. 197X) 325-38. 52. Anderwn. D.F., et a/ : “Interfacial Tension and Phase Behavior tn Surfactant-Brine-Oil Systems.” paper SPE SE I I. presented at the 1976 SPE Symposium on Improved Oil Recovery. Tulsa. March 22-24. Phase BchaviorS3. Bennett, K.E., CI al.: ” Microemulsion Observations. Thermodynamic Essentials, Mathematical Sumlation.” So<.. Per. &,g. J. (Dec. 1981) 747-62. 54. Scrtven. L.E.: “Equilibrium Bi-Continuous Structures.” M&l/i:atlon. So/uhi/&~tion, and Micrmvd~ion.~, K.L. Mittal (ed.). Plenum Press. New York City (1976).
47-Z
“Three~Paratnrter Representation 5s. Puerto. M.C. and Reed. R.L So<~ Per. E/II+ J. (Aug. of Surfactant/Oil/Brme Interaction.” 1983) 669-82. Crude Oils for Lo\s Intcrfact,~l 56. Caytas. J.L. (‘I nl.: “Modelling Tension.” Sock. Pet. Dl,g. J. (Dec. 1976) 3Sl&S7. 57 Nelson. R.C.: “The Effect of Live Crude on Phase Behavior and Oil-Recovery Effictcncy of Surfactant Floodmp Systems.” Si~c,. Per. G,,y. .I. (June 1983) 501-10. 58 Salter. S.J.: “The lntlucnce 01 Type and Amount of Alcohol on Surfactant-Oil-Brine Phase Behavior and Propertie\.” paper SPE 6X43 pwented at the 1977 SPE Annual Technical Contcrence and Exhtbttion. Denver, Oct. 9-12. s9. Hcaly. R.N. and Reed, R.L.: “Physrcochcmical Aspect, 01 Microemulsion Floodmg.” Sot Per. Eyq. J (Oct. 1974) 49l-SOI; Twos , AIME, 257. 60 Salter. S.J.: “Opttmizing Surfactant Molccul;tr Weight Dt\tribution: 1. Sulfonatc Phase Behavior and Phy+zll Properties.” paper SPE 12036 presented at the 1983 SPE Annual Technical Conference and Exhibition. San Franctwo. Ott 5-X. 61. Trushenshi. S.P.: “MicelIar Flooding: Sulfonate-Polymer Intcructton. ‘. Ir~tpr~wrl Oil Rccow Y /J) SL~I$KI~IIZ~ r~utl Po/wwr F/ad i/)x. D.O. Shah and R.S. Schcchter (cd\.). Academrc Press. Ncb York City (1977) 555-75. 62. Salter. S.J.: “Selection ofPheudo~Comp,nents in Surfactant-OilBrine-Alcohol Systems.“ paper SPE 7056 prcscnted at the 1978 SPE Improved Oil Recovery Symposium. Tulsa. OK. Aprtl 16-19. 63. Hirasaki. G.J.: “Interpretation ofthe Change in Optimal Salmtty with Overall Surfactant Concentration.” Sot. Pcv. E/IX. J. (Dec. 1982) 971-82. 64. Clover. C.J. (‘I cl/.: “Surfactant Phase Behavior and Retention in Porous Media.“ Sot. Per. Eqq. J. (June 1979) 183-93. 65. Bourrel. M. et (I/.: “Properttes of AmphiphileiOrliWater Systems at an Optrmum Formulation Ihr Phase Behavtor.” paper SPE 7450 presented at the 1978 SPE Annual Tcchntcal Conterence and Exhibition. Houston, Oct. l-4. 66. Nelson, R.C.: “The Saltnity Rcqutrcment Dtagram-A Usetul Tool in Chemical Flooding Research and Development.” So<,. PP(. 0)~. J. (April 1982) 259-70. 67. Hirasaki. G.J.. van Domwlaar, H.R.. and Nelson. R.C.: “Evaluatton of the Salinity Gradient Concept in Surfactant Flooding.” Sk. Per. EHR. J. (June 1983) 486-500. 68. Cayias, J.L., Schechter. R.S , and Wade. W.H.: “The Measurement of Low lnterfnctal Tension via the Spinning Drop Technique.” Ad,wrprion UI Intrrf~~ws, L.K. Mittal (ed.). Symposium Series. ACS (1975) No. 8. 1231-39. 69. Huh, C.: “Interfacial Tensions and Solubili,@ Ability of a Microemulsion Phase that Coexists with Oil and Brine.” .I Co/loid I~~~filcr Sci. (1979) 71. No. 2, 408~26. 70. Glinsmann, G.R.: “Surfactant Flooding with Mtcroemulsions Formed In-situ-Effect of011 Characteristtca.” paper SPE 8326 presented at the 1979 SPE Annual Technical Conference and Exhibition. Las Vegas. Sept. 23-26. 71. Reed, R.L. and Healy. R.N.: “Some Physico-Chemical Aspects of Mtcroemulsion Flooding, A Review. “Irnprow~l 0ii RKUI~ cry hi Sur$mcrm md Po/wwr Flooding. D.O. Shah and R.S. Schechter (eds.). Academic Press. New York City (1977) 383-438. 72. Reed. R.L. and Healy. R.N : “Contact Angles for Equtlihrated Microemulsion Systems.” Ser. Pet. Erq J. (June IY84) 342-50. 73. Bragg. J.R. et al.: “Loudon Surfactant Flood Pilot Teht.” paper SPE 10862 presented at the 1982 SPE Enhanced Oil Recovery Symposium, Tulsa, April 4-7. 74. Lake, L.W. and Helfferich. F.: “Catton Exchange tn Chemical Flooding Part 2-The Effect of Dtspersion, Catton Exchange. and PolymerISurfactant Adsorpbon in Chemical Flood Environment.” Sw. Per. Ot,e. J. (Dec. 1978) 435-44. 75. Pope. G.A.. Lake, L.W., and Helffertch. F G : “Catton Exchange in Chemical Floodmg, Part I-Basic Theory Without Dtsperston.” Sot. Per. f31,q. J. (Dec. 1978) 418-34. 76. Paul. G.W. and Froning. H.R.: “Salinity Effects of Mtcellar Flooding, J. Per. Tech. (Aup. 1973) 957-58. 77. Harwell, J.H.: “Surfactant Adsorption and Chromatographic Movement with Application in Enhanced Oil Recovery.” PhD dtssertation. U. of Texas, Austin (1983).
47-26
79
X0.
XI
87
Xi X4
85. X6.
87.
PETROLEUM
Hill. H J. and L&c. L.W.: “Cation Exchanee ,n Chcnucal Flwtllng: Part .i-Experimental.“ So< PC/. &q. J. (Dec. 1978) 345-56. Paul. G.W. (‘I crl “A Slmpllficd Predictive Model lor M~cclIwPolymer Floodmg.” paper SPE 1073.1 prewnted at the 1982 SPE Cal~fomia Resmnal Meeting. San Francwx~. March 24-26. L&c. L.W.. Stock. L.G., and Lawson. J.B.: “Screening E\timation of Recovery Efficiency and Chemical Reyulremcnt\ for Chemical Fiotrding.” paper SPE 706Y prtxnted at the 197X SPE lmprovcd 011 Recover) Symposium. Tuls,~. OK. April l6- IY. Aho. G.E and Bush. J.: “Rc\ult\ ol’the Bell Creek Unit ‘A’ MIcelIar Polymer Pilot.” paper SPE I II95 prerentcd at the 1982 SPt Annual Technical Conference and Exhlhitwn. Ncu Orlcdn\. Sept. 26-20. Lake. L W. and Pope. G.A. “Statu5 of Mwllar-Polymer biekl Tat\.” Prr. G?q /n,/. (Nov. 1979) 51. 3X-60. Waterllwlinp.“ ChIliland. H.E. and Conley. F.R.: “Surrktanl paper presenccd xt the 1975 Sympwium on Hydnrarbon Eupkr&m. Drillq. and Productwn. Paris. France. Dee IO- I?. Pope. G.A.’ “The Apphcatmn of Fractlonul Flow Thcq to Enhanccd Oil Rccorery.” .‘%c PC,. Cr,q. ./. (June 1980, 191~205. R:lm;&ri\hnan. T.S. and Wassan. D.T : “A Model for Inta%xd Activity ol Au&c CNde Od/Caustlc System\ tar Alkdlinc Floodmg.” S/K Per. hg. J. (Aug. 1983) 602m I?. Jenning\. H.Y. Jr.. Johnxm. C.E. Jr and McAullffc. C.D.: “A Caustic Waterlloodlnp Procw for Heavy Oil\.” /. PI,,. T&. I Dee 1974) 1344-52
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HANDBOOK
floodmg tar Wettahility Alteration-Ev;llu;ltinF a Potential F&l Application.” J. Pcl. 7&. (Dec. 197-I) I33533. Y4. Cooke. C.E. Jr.. Williams, R.E.. and Kolodz~e. P.A.: “Oil Recovery by Alkalme Waterflooding,” J. Per. Twh. (Dec. 1974) 1344-52. 95. Lorenz. P.B.. Donaldson. EC. and Thornag. R.D: “U\e ol Centrifugal Measurcmentr of Wettahility to Predict Oil Rcco%cry.” Bull. RI 7873. U.S. Dept. of Interior (lY741. Y6. McAul~ffc, C.D.: “Oil-in-Water Emulsions and Their Flow Properties in Porous Media.” J. Pet. Tech. (June 1973) 727-33. 97. McAuliffe. C.D.: “Crude-Oil-in-Water Emulww To Improve Fluid Flaw in an 011 Reaervnir.” J. Per. 7i~Ir (June 1973) 721-26. 98. Grim. R.E.: C/ov Mir~ercrir~~qv, McGraw-Hill Booh Co. Inc.. Nrw York City (1968) 99. Brownkw. A.H. : Gwr~/~er~~rrrrv.Prentice-Hall. Inc.. Englavood Cliffs, NJ (1979). 100. Somerton. W.H. and Rndke. C.J.: “Role of Clays in the Enhanced Recovery of Petroleum from Some California Sands.” J. PC/. Ted. (March 1983) 643-54. of Alkalme Pulvx 101. Bunpe. A.L. and Radkc. C.J : “Migratmn in Raervoir Sands.” Sot. I’<>/. Org. J. (Dee 19x1) 9YX~IOIZ. 102. Sydansk. R.D.: “Elevuted-Temperature Castic&mdstonc Interaction: Implications for Improving Oil Recovery.” Sot,. PO/ E/q. J. (Aug. 1982) 453-62. 103. Sloat. B. and Zlomke. D.: “The Isenhnur Unit-A Unique Polymer-Augment Alkaline Flood,“ paper SPE I07 Ii) praented at the 1982 SPE Enhanced Oil Recovery Symposium. Tulsa, OK. April 4-7. 104. Grwe. D.J. and Johnson. C.E. Jr.: “Field Trial of Caustic Flooding Process.” .I. Per. TX/I. (Dec. 1974) 1353-.5X.
90 Nelson.‘R.C. er rrl.: ‘.Courfact;nt-Enhanced Alhnlinc Floodme.” paper SPE 12672 prcscntcd at the 1984 SPE Enhnnccd 011 R&very Sympowm. ?ulsa. April I5m I X. 91. Owens. W.W. and Archer. D.L.: “The Effect of Rock Wettahility on Oil-Water Relatwe Permeability Relationships,” J. Per. Twh. (July 1971) X73-78: kiwis.. AIME. 251.
105. Mayer. E.H.. (‘1 (I/.: “Alkaline InjectIon for Enhanced Oil (Jun. 1983) 209-21. Recowx-A Status Report. ” J. PC/. T~I. 106. Taher. J.J. and Martin. F.D.: “Tcchmcal Screening Guidcr for Enhanced Oil Recovery” paper SPE I2069 presented at the I983 SPE Annual Technical Conference and Erhihitlon. San Francisco. Oct. s-x.
Chapter 48
Reservoir Simulation K.H. Coats, Scientific Software-Intercom
Introduction Webster’s dictionary defines simulate as to assume the appearance ofwithout the reality. Simulation of petroleum reservoir performance refers to the construction and operation of a model whose behavior assumes the appearance of actual reservoir behavior. The model itself is either physical (for example, a laboratory sandpack) or mathematical. A mathematical model is simply a set of equations that, subject to certain assumptions, describes the physical processes active in the reservoir. Although the model itself obviously lacks the reality of the oil or gas field, the behavior of a valid model simulates (assumes the appearance of) that of the field. The purpose of simulation is estimation of field performance (e.g., oil recovery) under one or more producing schemes. Whereas the field can be produced only once, at considerable expense, a model can be produced or run many times at low expense over a short period of time. Observation of model performance under different producing conditions aids selection of an optimal set of producing conditions for the reservoir. The tools of reservoir simulation range from the intuition and judgment of the engineer to complex mathematical models requiring use of digital computers. The question is not whether to simulate but, rather, which tool or method to use. This chapter attempts to summarize the evolution and current status of reservoir simulation practice involving usage of the mathematical, computerized models. The relatively modern nature of this practice is indicated by the first edition of this handbook (1962) not including a chapter on reservoir simulation. The nearly exponential growth in annual rate of simulation-related publications from the mid-1960’s to the present indicates the industry’s widespread acceptance of mathematical simulation as an engineering tool. This acceptance has been and remains qualified by questioning and improvement of accuracy in simulation model results. Thus a significant portion of the extensive literature deals
with model (1) evaluation or validation through comparison of field (laboratory) and model results and (2) improvement by use of new techniques related to model mathematics and representation of reservoir fluid and rock description parameters. The volume and increasing complexity of publications related to the latter item preclude a detailed mathematical description of current simulation technology in this chapter. Rather, emphasis is given to a general description of reservoir simulation models, how and why they are used, choice of different types of models for different reservoir problems, and reliability of simulation results in the face of model assumptions and uncertainty in reservoir fluid and rock description parameters. The chapter concludes with an abbreviated description of simulation model technology consisting of comments on a number of highly technical publications. Various texts l-4 give detailed descriptions of simulation technology through me late 1970’s, including finite-difference approximations, model formulations, iterative solution techniques, and stability analyses.
A Brief History In a broad sense, reservoir simulation has been practiced since the beginning of petroleum engineering in the 1930’s. Before 1960, engineering calculations consisted largely of analytical methods, ‘$ zero-dimensional material balances, 7,8 and one-dimensional (1 D) BuckleyLeverett9,10 calculations. The term simulation became common in the early 1960’s, as predictive methods evolved into relatively sophisticated computer programs. These programs represented a major advancement because they allowed solution of large sets of finite-difference equations describing two- and three-dimensional (2D and 3D), transient, multiphase flow in heterogeneous porous media. This advancement was made possible by the rapid evolution of
PETROLEUM
I - 0 IMENSIONAL
fL3Gm
ii
yx c2-DIMENSIONAL
CROSS-SECTION
(*g
Fig. 48.1-l-,
2-, and 3D grids.
large-scale, high-speed digital computer. and development of numerical mathematical methods for solving large systems of finite-difference equations. During the 1960’s, reservoir simulation efforts were devoted largely to two-phase gas/water and three-phase blackail reservoir problems. Recovery methods simulated were limited essentially to depletion or pressure maintenance. It was possible to develop a single simulation model capable of addressing most reservoir problems encountered. This concept of a single, general model always has appealed to operating companies because it significantly reduces the cost of training and usage and, potentially, the cost of model development and maintenance. During tbe 1970’s, the picture changed markedly. The sharp rise in oil prices and governmental trends toward deregulation and partial funding of field projects led to a proliferation of enhanced-recovery processes. This led to simulation of processes that extended beyond conventional depletion and pressure maintenance to miscible flooding, chemical flooding, CO2 injection, steam or hotwater stimulation/flooding, and in-situ combustion. A relatively comfortable understanding of two-component (gas and oil) hydrocarbon behavior in simple immiscible flow was replaced by a struggle to unravel and characterize the physics of oil displacement under the influence of temperature, chemical agents, and complex multicomponent phase behavior. In addition to simple multiphase flow in porous media, simulators had to reflect chemical absorption and degradation, emulsifying and interfacial tension (IFT) reduction effects, reaction kinetics, and other thermal effects and complex equilibrium phase behavior. This proliferation of recovery methods in the
ENGINEERING
HANDBOOK
1970’s caused a departure from the single-model concept as individual models were developed to represent each of these new recovery schemes. Research during the 1970’s resulted in many significant advances in simulation model formulations and numerical solution methods. These advances allowed simulation of more complex recovery processes and/or reduced computing costs through increased stability of the formulations and efficiency of the numerical solution methods.
General Description of Simulation Models A number of papers”-l4 present general, largely nonmathematical discussions of reservoir simulation. Odeh ’’ gives an excellent description of the conceptual simplicity of a simulation model. He illustrates the subdivision of a reservoir into a 2- or 3D network of gridblocks and then shows that the simulation model equations are basically the familiar volumetric material balance equation7y8 written for each phase for each gridblock. The phase flow rates between each gridblock and its two, four, or six (in lD, 2D, or 3D cases, respectively) adjacent blocks are represented by Darcy’s law modified by the relative permeability concept. Fig. 48.1 illustrates l-, 2-, and 3D grids representing a portion of a reservoir. The block and its two or four neighbors are denoted by B and N in the 1D and 2D grids. One can visualize an interior block of the 3D grid with its six neighbors, two on either side of the block in the n, y, and z directions. The subsea depths to the top surface of each grid in Fig. 48.1 vary with areal position, reflecting reservoir formation dip. Reservoir properties such as permeability and such as pressure, porosity, and fluid properties temperature, and composition, are assumed uniform throughout a given gridblock. However, reservoir and fluid properties vary from one block to another; fluid properties for each gridblock also vary with time during the simulation period. A simulation model is a set of partial-difference equations requiring numerical solution as opposed to a set of partial differential equations amenable to analytical solution. Tbe reasons for this are (1) reservoir heterogeneityvariable permeability and porosity and irregular geometry, (2) nonlinearity of relative permeability and capillary pressure vs. saturation relationships, and (3) nonlinearity of fluid PVT properties as functions of pressure, composition, and temperature. The models require high-speed digital computers because of the large amount of arithmetic associated with the solutions. The large amount of arithmetic performed by a simulation model stems from the large number of gridblocks representing the reservoir and from the number and complexity of equations describing the oil-recovery process. Total arithmetic or computing expense for a given model run is at least linearly proportional to the total number of gridblocks, N,N,N,, where N,, NY, and N, are the numbers of gridblocks specified in the X, y and z directions , respectively. The individual gridblocks are customarily identified by subscripts i, j, k, where blocks are numbered i = 1,2.. .N, in the x direction, j=1,2...N, in the y direction, and k= 1,2.. .N, in the z direction. Most simulators use noflow or closed boundary conditions at the exterior boundaries [x=(O,LX), y=(O,L,) and z=(O,L,)] with provision
RESERVOIR
48-3
SIMULATION
for aquifer influx along the areally exterior boundary. ‘Ihe nonrectangular, areal (x-y) shapes of most reservoirs are represented by zero gridblock porosity and permeability in the appropriate area1 portions of the x-y grid. Preceding statements described the simulation model as a set of equations expressing conservation of mass for each phase for each gridblock. More precisely, the model equations express conservation of mass of each reservoir fluid component for each block, The number and identity of these components depend on the nature of the original reservoir fluid and the particular oil-recovery process, as discussed in the following. The total number of mass conservation equations is then N,N,N,N, where N is the number of components necessary to describe the reservoir fluids. Each conservation equation states that the mass rate of flow into a gridblock minus the mass rate of flow out must equal the rate of change or accumulation of mass within the block. These N mass-balance equations (one for each component) apply to each gridblock. The block is an open system, in the thermodynamic sense, because of fluid flow between the block and its six neighbors and fluid injection or production if a well is perforated in the block. The center of gridblock (i,j,k) is located at (xi.yj,zk). This block has six neighboring blocks (i-tl,j,k),(i,j-t 1,k) and (i,j,kk 1). For brevity and clarity, the interblock flow rates are written here in terms of only r-direction flow between blocks (i- 1,j,k) and (i,j,k), the indices j and k are suppressed, and the general symbol C, denotes concentration (mass/volume) of component I in the various phases. The three immiscible phases (water, oil, and gas) are denoted by subscripts w, o, and g, respectively. The interblock flow rate of component I, according to Darcy’s law modified by relative permeability, is
+%l,(ApO
-y,AZ)+&@,
-ysAZ) P8
1
J
,
If subscript J=1,2,3 is used to denote phases w,o,g respectively, then Eq. 1 simplifies to
The first term in parentheses is the interblock trunsmissib&y, TIJ, for flow of component I in phase J, requiring evaluation here at (i- %,j,k)-i.e., between blocks i - 1 and i. The M/L portion of T is normally calculated as the harmonic or series-resistance mean value using block i- 1 and block i properties. The remaining portion of T normally is evaluated at the upstream gridblocki.e., the block from which the phase is flowing. Thus Eq. 2 becomes simply
representing interblock flow of component I from gridblock i- 1 to gridblock i. The right-hand or accumulation terms of the mass balances are 3 ;6
d
c J=l
(SJCIJ)
1 ,
. . . . . . . . .
. . . .
. , . .
(4)
where V = grid block volume, hxi AYj AZk 6 = time difference operator, 6X=X,,+, -X,, n = time level, t,+l =t,+At, At = timestep, $I = porosity, fraction, and SJ = saturation of phase J, fraction of pore space. Eqs. 3 and 4 give the final form of the component I mass-balance equation for gridblock (i,j,k) as
. . . . . . . . . . . . . . . . . . . . . . . . . . . . (1) where 41 = component I interblock flow rate, mass/time, k= absolute permeability, A= AyiAZk =cross-sectional area normal to flow, L= distance between adjacent block centers, (AX-1 fAri)/ k rP = relative permeability to phase P (P=w,o,g). p’p = viscosity of phase P C IP = concentration of component I in phase P, mass/volume, APP = pressure of phase P YP = specific weight of phase P Ax = X,-l -x,, where x is p or Z, and subsea depth, measured positively z= downward.
[
3
C A[TIJ(APj-r./Az)l-4p~ J=l
(5)
where q,,I is the mass rate of production of component I from the block resulting from any well perforated in the block and the Laplacian term of type A(TAp) is defined as
and
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For the general case where each component is present (soluble) in all three phases, Eq. 5 is Nequations in 3N+6 unknowns. The unknowns are 3N CIJ values, 3 phase saturations, and 3 phase pressures. Thus an additional 2N-t 6 equations are required for a determinate or solvable model having equal numbers of equations and unknowns. The N Eqs. 5 are referred to as primary equations while the additional 2N+6 equations are denoted constraint equations. The constraint equations are manipulated in the model programming to eliminate 2N+6 variables (unknowns) in terms of the remaining N (primary) unknowns. The result is then the set of N primary Eqs. 5 in N primary unknowns. The constraint equations are relations between unknowns pertaining only to the particular gridblock (iJ,k) to which Eqs. 5 apply. The N primary Eqs. 5, however, involve unknowns (e.g., pi) at the gridblock (i,j,k) and its six neighboring blocks, owing to the nature of the interblock flow terms on the lefthand side. The 2N+6 constraint equations are illustrated here for the case of an isothermal, compositional model where the N components are HZ0 and N- 1 hydrocarbon components (e.g., methane, ethane.. .C ,). The first three constraints are S,+S,+S,=l.O,
........
. ..(6)
. .... .. .
po -pw =Poy,(S,),
. . . . (7)
and pg -p.
............
=P,,(S,),
..
(8)
where P,, =water/oil capillary pressure and P,, =gasJ oil capillary pressure. These constraints express the requirement that the phase saturations sum to unity and also eliminate the water and gas phase pressures in terms of the unknown oil pressure phase using capillary pressure curves. For this compositional case, concentration C,J =p where pi is the molar density of phase J (moMvolume) and xIJ is mol fraction of component I in phase J. The next three constraints require that the mol fractions of all components sum to unity in each of the three phases, Jx/J
N
c
x[J=l.o
....
.... .... ,,..
..
.
I=1
where J=w,o,g or 1,2,3. The remaining 2N constraints express equilibrium of each component among the three phases, j-r, =fr,
..... .. ..
. . . . (104
and
j-i,=fr, ........... .... ...............(lob) where fIJ is the fugacity of component I in phase J. These fugacities can be expressed in terms of mol fractions and pressure by use of an equation of state (EOS). Altematively, they can be replaced by equilibrium K-value relation-
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ships (e.g., y=Kx) with K-values given as functions of pressure or of pressure and composition. The 2N + 6 constraint Eqs .6 through 10 are manipulated to eliminate one-phase saturation, two-phase pressures and 2N-3 mole fractions (x,J) from the N primary Eqs. 5. aThe final result is a model consisting of the N Eq. 5 in N unknowns consisting of two saturations, one pressure, and N-3 mole fractions. Each coeffkient or term remaining in the N primary equations is then either one of the N primary unknowns or a function of one or more of the primary unknowns. Types of Models Different types of simulation models are used to describe different mechanisms associated with different oilrecovery processes. The most widely used types are black oil, compositional, thermal, and chemical flood. The four basic recovery mechanisms for recovering oil from reservoirs are (1) fluid expansion, (2) displacement, (3) gravity drainage, and (4) capillary imbibition. Simple fluid expansion with pressure decline results in oil expulsion from and subsequent flow through the porous matrix. Oil is displaced by gas and injected or naturally encroaching water. Gravity drainage, caused by positive (water/oil and oil/gas) density differences, aids oil recovery by causing upward drainage of oil from below an advancing bottomwater drive and downward drainage from above a declining gas/oil contact. Finally, imbibition, generally normal to the flow direction, can be an important recovery mechanism in lateral waterfloods in heterogeneous sands with large vertical variation of permeability. Accommodation of compositional and the enhancedrecovery processes in this discussion requires the addition of a fifth mechanism, oil mobilization. This loosely defined term includes widely differing phenomena that create or mobilize recoverable oil. Some of these phenomena are not really distinct from the first four. The black-oil model accounts for the four basic mechanisms in simulation of oil recovery by natural depletion or pressure maintenance (e.g., waterflooding). This isothermal model applies to reservoirs containing immiscible water, oil, and gas phases with a simple pressuredependent solubility of the gas component in the oil phase. The two-component representation of the hydrocarbon content I5 presumes constant (pressure-independent) compositions of the oil component and the gas component, no volatility of the oil component in the gas phase, no solubility of the oil and gas components in the water phase, and no volatility of water (H20) in the oil and gas phases. The oil component is stock-tank oil and its unit of mass is 1 STB (1 bbl at stock-tank pressure and temperature). The gas component is surface system gas and its unit of mass is 1 standard cubic foot (scf). The water component unit of mass is 1 STB. For water and gas, components and phases are identical while the oil phase is a mixture of the oil component and the gas component. The number of components (N) and therefore the number of Eqs. 5 per gridblock is three for the black-oil model. Table 48.1 gives the definitions of component concentrations, CIJ, for this model. The water phase, gas phase, and saturated oil phase, reciprocal formation volume factors, b, (STB/RB), bR (scf/RB), and b, (STB/RB), respectively, are given smgle-valued functions of pressure. For undersaturated oil, b, is dependent on
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pressure and solution gas (R, , scf/STB). As discussed later original work in formulations’6m’8 led to a number of papers ‘9m23describing black-oil models during the 1960’s. The remaining model types discussed here account for some mobilization mechanisms in addition to the four basic recovery mechanisms. The isothermal compositional model represents reservoir fluids by N components, including water and N- 1 hydrocarbon components. Generally, but not necessarily, solubilities of water in the oil and gas phases and of hydrocarbon components in the water phase are considered negligible. For water, then, the concentration in Eqs. 5 is as given in Table 48.1. The hydrocarbon component I concentration CIJ is P as mentioned earlier, for J=o,g or 2,3. Gas/oil phase equilibrium and phase densities within each gridblock are calculated using equilibrium K-values from pressure- and composition-dependent correlations or, more recently, from EOS’s. 25-28 Unlike the black-oil model, the compositional model can represent the mobilization of oil by outright (single-contact) or dynamic (multicontact) miscibility, oil swelling and viscosity reduction by solution of an injected nonequilibrium gas (e.g., CO,), and stripping or vaporization of an oil’s lighter ends by injection of a dry gas. With one exception,29 recent papers 29-33describing compositional models are based on equilibrium K-values obtained from EOS’s. A thermal simulation model is a set of N conservation equations, similar to Eq. 5, which expresses conservation of mass of H2 0 and N-2 hydrocarbon components and conservation of energy. With energy designated as “component” N, the last (I=N) of Eqs. 5 becomes the energy balance upon addition of terms representing heat conduction and overburden heat loss. An additional requirement is the use of pJHJ for in the well and interblock flow terms and p J UJ for in the right side accumulation term. HJ and are enthalpy and internal energy, respectively, energy/mole. If the in-situ combustion capability is included then the mass conservation equations include source (sink) terms represented by Arrhenius reaction rate expressions for cracking and oxidation of hydrocarbon components and the energy balance includes heat of reaction terms. For the same number of fluid components, a thermal model has one more (energy) conservation equation than the compositional model and one additional unknown, temperature T. For steam-injection processes, thermal model components are typically H 2 0, heavy (nonvolatile) and light (solution gas or distillable) hydrocarbon components and energy. For in-situ combustion studies, typical components are HzO, heavy-oil component, a lighter (distillable) oil component, solid coke, 02, CO*, N2, and energy. Frequently CO2 and N2 are lumped as one component to reduce computing expense. The steam tables and/or an EOS are used to calculate liquid Hz0 (water phase) properties and the Hz0 gas/water phase K-value as functions of pressure and temperature. In most applications, Hz0 is assumed insoluble in the oil phase. In most current models, the distribution of other (non-H20) components among all phases is represented by user-provided K-values dependent on only pressure and temperature. Thermal simulators are applied to steam-injection or insitu combustion processes in heavy-oil reservoirs where oil is mobilized primarily by (1) reduction of oil viscosiJX
cNJ
CNJ
UJ
IJ,
TABLE 48.1-DEFINITIONS OF CONCENTRATIONS C,, FOR THE BLACK-OIL MODEL
Phase I 1 2 3
Component water oil gas
-
J=l Water bw 0
J=2 __Oil 0 bo
0
b,Rs
J=3 - Gas 0 0 b,
ty with increased temperature, (2) distillation of intermediate hydrocarbon components from the oil phase to the more mobile gas phase, and (3) cracking of the oil phase [usually above 500°F (26O”C)l with subsequent distillation. Thermal models developed from 1965 to 198234-40 generally exhibit a trend toward inclusion of more dimensions, more components and dual capability of steamflood and in-situ combustion. Chemical flood models include polymer, micellar (surfactant), and alkaline (caustic). Polymer waterflooding improves oil recovery by lowering the oil/water mobility ratio, by reducing the effective permeability to water, and/or by increasing water viscosity. In micellar flooding, surfactants greatly reduce oil/water IFT, thereby solubilizing oil into the micelles and forming an oil bank. 4’ The surfactant slug and mobilized oil normally are propelled toward the production well by a graded bank of polymerthickened water. The mechanisms responsible for improved oil recovery in alkaline flooding are thought to include low IFT, wettability alteration, and emulsification. 42 Chemical flooding processes involve complicated fluid/fluid and rock/fluid interactions such as adsorption, ion exchange, viscous shear, and three- (or more) phase flow. Several recent papers 43-45 describe implementation of these complex chemical flood mechanisms in numerical simulators. The four types of models described above are defined or distinguished by the recovery process and the nature of the original reservoir fluid. Considering the nature of the reservoir formation leads to a fifth, fractured-matrix type of simulation model. While in theory any recovery process can be implemented in a fractured-matrix reservoir, most simulation work reported to date is concerned with black oil fracture&matrix models. Three-dimensional models are described by Thomas et a1.“6 for the threephase case and by Gilman and Kazemi4’ for two-phase water-oil flow. Their models consider a discontinuous array of matrix blocks in a continuous 3D fracture network. Flow throughout the reservoir and to the wells occurs in the fracture system and the matrix blocks are treated as sink/source terms in that system. Their model equations include the set of N conservation Eqs. 6 written for each gridblock in the fracture system. Each gridblock may contain a number of similarly behaving matrix blocks. However, additional terms are added to Eqs. 6, representing matrix-fracture flow. Also, for each gridblock additional equations are required to express mass conservation of each component in the matrix blocks included in the gridblock. These additional equations can be eliminated or combined with the basic N (fracture system) flow equations4”v4’ so that the final model includes only N equations (per block) possessing interblock flow terms. Blaskovich et a1.48 describe a fractured-matrix model
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which allows for reservoir-wide flow through the matrix as well as the fracture system. This extension leads to a model including 2N equations (per block) possessing interblock flow terms. Model Input Data and Calculated
Results
A simulation model requires three types of input data. First, reservoir description data include (1) overall geometry, (2) grid size specification, (3) permeability, porosity, and elevation for each gridblock, and (4) relative permeability and capillary pressure vs. saturation functions or tables. Geological and petrophysical work, which involves logs and core analyses, is necessary for Items 1 and 3. Laboratory tests on core samples yield estimates of relative permeability and capillary pressure relationships. Second, fluid PVT properties, such as formation volume factors, solution gas or component equilibrium K-values, and viscosities are obtained by laboratory tests. Finally, well locations, perforated intervals, and productivity indices (PI’s) must be specified. Each well must be assigned a production (injection) rate schedule and/or a limiting producing (injecting) pressure for use in calculating well deliverability (injectivity). Model output or calculated results include spatial distributions of fluid pressure, saturations and compositions, and producing GOR and WOR and injection/production rate (for wells on injectivitylproductivity) for each well at the end of each timestep of the computations. Internal manipulation of these results gives average reservoir pressure and instantaneous rates and cumulative injection/production of oil, gas, and water by well and total field vs. time. Current models offer various levels of visual output display features that ease the engineer’s assimilation and interpretation of simulator results. Example features are contour maps of pressure, saturations, compositions and temperature, concise tabular summaries of individual well or well-group performance, and field or well timeplots of quantities such as production rates and WOR’s and GOR’s.
Purpose of Reservoir Simulation Reservoir simulation is used to estimate recovery for a given existing producing scheme (forecasting) to evaluate the effects on recovery of altered operating conditions, and to compare economics of different recovery methods. Black-oil models have been widely applied to forecast oil recovery and to estimate the effects on oil recovery of (1) well pattern and spacing, (2) well completion intervals, (3) gas and/or water coning as a function of rate, (4) producing rate, (5) augmenting a natural water drive by water injection and desirability of flank or peripheral as opposed to pattern waterflooding, (6) inlill drilling, and (7) gas vs. water vs. water-alternating-gas (WAG) injection. A few of many reported studies are briefly mentioned here. Henderson et al.49 applied a single- (gas) phase model to optimize the locations and numbers of wells necessary to meet peak deliverability requirements in a gas storage field. Mann and Johnson” showed good agreement between model-predicted and actual field performance. Thomas and Driscol15’ applied a black-oil model in estimating locations of bypassed oil for the urpose of designing an infdl drilling plan. Two studies P2,53
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report extensive results related to rate-sensitivity of various Alberta reservoirs subjected to water-oil displacements. Thakur ef al. 54 applied a black-oil model to characterize (through history matching) offshore Nigerian reservoirs and estimate incremental recovery of waterflooding over natural depletion, with infill drilling and removal of allowable rates. Compositional models also are used for most of Purposes 1 through 7 listed previously, but only in cases where the black-oil assumption of constant composition oil and gas components is invalid. Example compositional model applications include (1) depletion of a volatile oil or gas condensate reservoir where hydrocarbon phase compositions and properties vary significantly with pressure below bubble- or dewpoint, (2) injection of nonequilibrium gas (dry or enriched) into an oil reservoir to mobilize oil by vaporization into the more mobile gas phase or by attainment of outright (single-contact) or dynamic (multicontact) miscibility, and (3) injection of CO2 into an oil reservoir to mobilize oil by stripping of light ends, oil viscosity reduction, and oil swelling. Compositional simulation has been performed to estimate (1) loss of recovery caused by liquid dropout during depletion of retrograde gas condensate reservoirs and the reduction of this loss by full or partial cycling (reinjection of gas from surface facilities) and (2) effects of pressure level, injected gas composition, and CO2 or N2 injection on oil recovery by vaporization or miscibility. Graue and Zana55 describe application of a compositional model in estimating Rangely (CO) field oil recovery by CO2 injection as a function of injected composition and pressure level. Results of compositional simulation of a CO2 project include CO;! breakthrough time and rate and composition of produced fluids. These are required to design production facilities and CO2 recycling strategies. 56 Modeling is also useful to optimize pattern size and CO2 /water-injection rates to overcome the effects of reservoir heterogeneity. 57 Thermal models are applied in reservoir studies of insitu combustion and are used to simulate performance of cyclic steam simulation and steamflooding. In steam injection, questions addressed by simulation relate to effects of injected steam quality and injection rate, operating pressure level, and inclusion of gas with the injected steam. One question in cyclic stimulation concerns the optimal time periods per cycle for steam injection, soak, and production. The flooding case introduces the issues of well pattern and spacing. A number of steam-injection field studies using models have been published. Herrera and HanzlikS8 compare field data and model results for a cyclic stimulation operation. Williams59 discusses field performance and model results for stimulation and flooding, and Meldaum discusses field and model results related to addition of gas to the in’ected steam. Gomaa et al. 6’ and Moughamian et al. 61 applied steamflood simulation in identifying and optimizing operating parameters in pilot and field drive operations. Numerical simulation has been used to estimate chemical flood performance in a reservoir environment where the processes are very complex and many reservoir parameters affect the results. Chemical flood simulation has been used to construct a screening algorithm for the selection of reservoirs suitable for micellar/polymer flooding63 and to examine competing EOR strategies-
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e.g., CO* vs. surfactant flooding.@’ For caustic65 and polymeP applications, as well as for the micellar process, chemical flood modeling is useful to discern controlling process mechanisms and to identify laboratory data required for process description. In recent years, simulation has been used increasingly to estimate and compare recoveries from a given reservoir under alternative enhanced-recovery processes, such as CO2 injection, thermal methods (steam injection and in-situ combustion), and several types of chemical flooding.
Considerations in Practical Application of Simulation Models This section describes the procedure followed and certain questions faced by the engineer conducting a reservoir simulation study. The engineer must select the appropriate type of simulation model, select the grid network, and specify rock and fluid description data. Then the engineer must attempt to reduce or at least estimate inaccuracies in simulation results which stem from uncertain rock/fluid description data and from spatial truncation error. Selection of Model Type As mentioned earlier, selection of model type may depend on both the nature of the original reservoir fluid and upon the recovery process(es) to be studied. As a rough guide, an original reservoir oil solution gas or GOR value, R,, below 2,000 scf/STB indicates a black oil, whereas a higher value indicates a volatile oil or retrograde gas condensate requiring compositional treatment. For a black-oil reservoir, a black-oil model may be used to study natural depletion, water injection and/or equilibrium gas injection operations. However, a compositional model is generally necessary to estimate recovery by injection of dry or enriched gas, solvent, or CO*. An exception here is the applicability of a modified black-oil model67 in simulation of CO2 or solvent injection where outright (single-contact) miscibility occurs. Compositional simulation is generally employed for volatile oil reservoirs. However, a less expensive blackoil model study is adequate for simulating abovebubblepoint waterflooding performance. Compositional models have generally been employed to study retrograde gas condensate reservoirs. The compositional model is necessary in the case of below-dewpoint cycling. However, in some cases natural depletion or abovedewpoint cycling can be simulated at less expense using a black-oil model modified to account for volatility of the oil (condensate) component in the gas phase. 6sm70 The alkaline and surfactant-flood processes generally require use of the complex chemical flood simulation model. However, some (augmented) black-oil models offer the capability to simulate polymer and alkaline flooding. Selection of Model Grid Selection of the x-y-z gridblock network involves many factors, including available budget and the engineer’s judgment and experience. For any type of model, the arithmetic or computing expense per timestep is at least linearly proportional to the total number of gridblocks
48-7
employed. The computing expense of a single model run is proportional to the product of the number of gridblocks and the number of timesteps required by the model to cover the total time period of interest. In many cases, the timestep size is controlled by the maximum rate of change (overall gridblocks) in one or more calculated quantities such as pressure and saturations. This maximum rate of change generally occurs at or near a well or in the vicinity of a flood front. A doubling of the number of gridblocks can result approximately in a doubling of this maximum rate of change since each gridblock is (on the average) one-half as large. The average timestep size, then, might decrease by a factor of two if the number of blocks were doubled. The final result is a computing expense per model run which can approach a proportionality to the square of the total number of gridblocks. This indicates the importance of selecting the smallest number of gridblocks consistent with reservoir/well description, recovery process characteristics, and the questions asked regarding reservoir performance. The number of gridblocks and resultant study computing expense are the lowest in cases where the engineer can justify use of a representative element of the total field as the basis for the model study. This may be possible in reservoirs developed with repeated well patterns, for any recovery process-waterflooding, CO* injection, steamflooding, etc. In such cases, the representative element ideally should be a symmetrical element of the reservoir. In strict terms, this requires (1) a repeated, regular pattern of identically completed and operated wells, (2) a horizontal, areally homogeneous reservoir formation of uniform thickness, and (3) areally uniform initial fluid saturation distributions. If these conditions were met, then questions regarding total field optimization, forecasting and comparative evaluation of recovery processes could be addressed inexpensively by simulation of the single pattern (element). While actual reservoirs never satisfy these conditions exactly, representative-element simulation studies are frequently performed for repeated pattern processes. In some cases, a substantial portion of the reservoir may exhibit only moderate areal heterogeneity and thickness variation. Resultant variation in performance from one pattern to another may be sufficiently small for engineering purposes to justify scale-up of single-pattern results to total field performance. Representative-element simulation is often performed where the study purpose is comparative evaluation of alternative recovery processes as opposed to forecasting of total field performance for a specific process and operating scheme. The justification of single-element simulation implied in such cases is that the resultant ranking of alternative processes is unaffected by the variations in pattern (element) properties over the field. This justification can be and frequently is checked by repeating the various process simulations for two or more patterns of different properties representative of different portions of the reservoir. Finally, the relatively inexpensive single-element simulation applies to design or optimization studies of a specific recovery process operated in a repeated pattern mode. For a repeated-pattern steamflood, single-pattern model runs have been performed to “optimize” pattern type (e.g., five-, seven- or nine-spot) and size, injected
48-8
steam quality and rate, well completions, etc. Occasional publications describe single-pattern simulation studies using a one-quarter five-spot or one-quarter nine-spot as the symmetrical element of the respective pattern. Actually, a one-eighth five-spot or nine-spot (and xZ seven-spot) are the smallest symmetrical elements and should be used to minimize computing expense. 71 Currently, a major portion of the industry-wide effort and computing expense in simulation studies is associated with total-field forecasting of black-oil reservoir performance under a sequence of recovery processes. Typically, the engineer must select a 3D grid for a large reservoir with significant heterogeneity, large areal variation in dip and thickness, irregular well locations and increasing numbers of wells with successive development stages. The engineer may face a several- to many-year period of historical performance under natural depletion, frequently with some natural water encroachment. Study objectives may include history matching, followed by matching and forecasting for a waterflood period, in turn followed by forecasting for some tertiary scheme such as CO2 injection. The total number of gridblocks is the product of the number of areal blocks, N,N,, and the number of grid layers, N,. Different considerations enter into selection of these two numbers of spacings. Factors indicating a need for fine area1 grid spacing are high well density and sharp or rapid changes (areally) in permeability, porosity, thickness, and dip. Since these factors frequently vary over the field, thex- and y-direction grid spacings are often nonuniform. Grid spacings generally increase toward the downdip reservoir boundaries and increase greatly with distance into the aquifer if the latter is present and included in the grid. In general, of course, the number of area1 gridblocks required increases with the size of the reservoir and the number of wells. However, grid spacings ranging from very fine to very coarse may be appropriate for different reservoirs of comparable size. The smallest numbers of areal blocks (coarsest areal spacings) are associated with reservoir studies limited to natural depletion and crestal or flank gas and/or water injection. In such a case, a coarse grid may result in a number of area1 blocks that include two or more similar type (e.g., production) wells, with little loss in engineering significance of the simulator results. Large numbers of area1 blocks may be required in cases of pattern waterfloods or enhanced recovery processes. A rough guide in this case is the need for at least two, preferably three or more, gridblocks separating each injection-production well pair. However, recent studies describe estimation of pseudorelative-permeability curves, which allow adjacent-block placement of an injectoriproducer well pair. 72,73 The major factors affecting the number of grid layers (vertical gridblocks) required are the formation stratification, vertical communication, and total thickness. Many reservoirs possess a number of formation layers, which correlate from well to well over much of or all the field. Variations of layer thickness, permeability, and porosity may be significant areally and even greater from one layer to another. The vertical communication (vertical permeability) between adjacent layer-pairs may vary from zero to very high, both areally and from one layer-pair to another. In general, at least one grid layer should be
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used for each correlatable formation layer. However, common sense and budget constraints argue against detinition of a large number of very thin grid layers. Threedimensional reservoir studies typically employ 4 to 12 grid layers, and one or more of these grid layers may be a lumped representation of several thin formation layers. The need for subdivision of one formation layer into two or more grid layers depends on the layer thickness and fluid-segregation characteristics of the recovery process and operating rates. Most recovery processes result in moderate to severe gravity segregation of oil and injected fluids; injected water or gas tend to underrun or override oil, respectively; many steamflood projects exhibit severe override of oil by the steam. A formation layer that has significant thickness and zero to poor vertical communication with layers above and below may exhibit a pronounced phase segregation and require two or more grid layers. In the idealized example of a fieldwide, pronounced gravity override in a vertically homogeneous reservoir, a variable grid spacing increasing from top to bottom might be specified. That is, four layers of thicknesses 5, 10,20, and 25 ft might give more accurate results than four layers of equal 15ft thickness. A customary approach to determining NZ involves use of the simulation model itself in 2D cross-sectional (X-Z slice) mode. For the particular recovery process of interest, X-Z model runs are performed by using different numbers of grid layers. Pseudorelative-permeability curves reflecting phase segregation are calculated from model runs performed with fine vertical grid spacing. 74-76 These pseudocurves are then used in equivalent x-z model runs using fewer grid layers to obtain coarse (vertical) definition results similar to the fine-spacing “correct” results. The fewer grid layers of the coarse definition are then employed in the 3D reservoir study grid. This concept of generating pseudocurves for coarse vertical grids that reproduce vertical fine-grid results (using rock or laboratory relative permeabilities) has been extended to the areal spacing problem, 72.75 as mentioned earlier. Obviously, a minimum computing expense follows from use of a single grid layer representing the entire formation thickness. This results in a 2D X-Yarea1 grid as opposed to a 3D grid and occasionally is justified in the two extremes of a very high vertical permeability and a layered formation with zero vertical permeability. Pseudorelative permeability and capillary pressure curves are discussed for the former case in papers describing the vertical equilibrium (VE) concept21,77 and for the latter case by Hearn. 78 Specification of Reservoir Fluid Description Data
Rock and
Geological and petrophysical work based on logs and core analyses yields maps of structure, net dh, and w1 products for each of the several reservoir layers. The kh and +h data often are augmented or modified by results of drillstem, pressure buildup, and pulse tests. For each layer, the engineer can overlay his area1 x-y grid spacing network on these maps and read off the values of subsea depth, I#& and kh at the center of each gridblock. These values along with gross thickness of each block are then transposed to a data file in a format compatible with that
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SIMULATION
required by the simulation model. Current research effort is directed toward developing computer programs that accept digitized core analysis, log and geological data, the selected grid network, and, through mapping and interpolation techniques, automatically prepare the simulation input data file. Laboratory core analysis work includes measurement of relative-permeability, k,., and capillary-pressure, P,, curves for a number of field cores. Variations in rock lithology may result in different sets of k, and P, curves for different layers and/or different areal portions of the reservoir. Most simulation models allow multiple sets of such data in tabular form with assignment of each set to a user-specified layer/portion of the reservoir. If the rock water/oil (gas/oil) capillary pressure values are small, the water/oil (gas/oil) transition zone in the reservoir may be a very small fraction of total formation thickness. In such cases, pseudocapillary-pressure curve(s) should be used. l7
For black-oil studies, laboratory tests are performed to determine gas compressibility factor and saturated oil and gas viscosities vs. pressure. Differential and/or constantcomposition expansion tests on oil samples yield the saturated oil pressure-dependent formation volume factor, B, (RB/STB), and solution gas, R, (scf/STB). The resulting oil and associated gas properties vs. pressure are entered in the data file in tabular form compatible with simulator input requirements. For gas condensate depletion studies, constant-volume and constantcomposition expansion tests yield the required pressure-dependent liquid content, CL (STB/scf), and condensate density values. A wide variety of laboratory tests are performed for compositional model studies that involve injection of a nonequilibrium fluid (dry or enriched gas, CO?, N2, etc.). Swelling tests yield relative volumes, saturation pressures, and equilibrium phase compositions for each of a sequenceof mixtures of, say, 1 mole of original reservoir oil and injected fluid. 79 Various single- and multicontact tests may be augmented by ID corefloods and/or slim-tube displacements. Orr et al. 8o*81discuss a variety of C02-oil laboratory tests. Much of the laboratory PVT test data must be processed to yield correlations or a calibrated EOSs2-85 for simulator input requirements. History Matching In most simulation studies, reservoirs have some period of historical performance data that include WOR, GOR, individual phase rates and cumulatives, and pressure measurements by well. Ideally, periodic (e.g., monthly), accurate measurements of all these data would be recorded and available for all wells. In the typical case, many of these data are unrecorded or unavailable and some of the reported values may be of questionable accuracy. The reservoir description based on log and core analysis data reflects a very small (volumetric) sampling of the reservoir. The historical reservoir-performance data reflect the reservoir description, and its impact on pressure/fluid movement behavior, on a much larger scale. The previously mentioned geological and petrophysical work yields an initial reservoir description. History matching yields a refinement of that description, which improves agreement between model results and observed reservoir behavior. The history-match phase of
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the simulation study entails a sequence of model runs in which input reservoir description parameters are altered to improve this agreement. This is a trial-and-error procedure frequently requiring considerable engineering judgment and experience. The description parameters obtained from the geological/petrophysical work often are used to establish legitimate ranges of parameter variation in the history-match model runs. This history-match phase can consume half or more of the total simulation study (match plus prediction) computing effort and expense, depending on the length of the history period, complexity of the reservoir, and amount of available performance data. Refs. 86 through 90 describe methods and applications of inverse simulation or automatic history matching. This concept requires user-specification of a finite set of reservoir description parameters to be determined (e.g., zonal permeability, porosity values), a finite set of observed reservoir performance data to be matched, and a regression procedure coded interactively with the simulator. A single computer submittal is then performed, which in turn executes many model history runs. The regression procedure automatically varies description-parameter values from run to run to determine that set of descriptionparameter values that maximize agreement between model results and the set of observed data. This concept is especially appealing to the engineers who have experienced the frequently high frustration levels associated with trial-and-error matching of complex reservoir behavior. However, to date the trial-and-error procedure still predominates with isolated successes reported with automatic history matching. Two factors complicating the latter approach are (1) the expense of the required single computer submittal can be very large, (2) the a priori choice of description parameters (or zonation) can be difficult, subjective, and lead to a questionable reservoir description.
Validity of Simulation Results Uncertainties or errors in simulation model results may arise from (1) questionable assumptions or mechanisms not represented in the differential form of the model, (2) spatial and time truncation error introduced by replacement of the model differential equations by finitedifference approximations, and (3) inadequately known reservoir rock and/or fluid description data. In addition, the exact solution of the difference equations is not attained because of round-off error introduced by the finite word length of the computer. Round-off error is generally negligible compared with errors from the other three sources. With some exceptions, the above sources of error are listed in order of increasing importance. However, successful history matching can reverse the importance of the second and third sources. Comparisons of model and laboratory experiment results can indicate model validity in the absence of the Uncertainty 3 above. Several such comparisons show good model-experiment agreement for gas/oil systems,91,92 water/oil coning,93 and fractured-matrix imbibition. 94 Model Assumptions An assumption common to many black-oil models is complete re-solution of free gas in accordance with the
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saturated R,(p) curve during repressurization. This may be a poor assumption in a case where gridblock thickness is large and gas/oil gravity (vertical) segregation is pronounced. Prior to repressurization in a given block, the free gas may exist as a high gas saturation in only the upper portion of the block. This contradicts its representation in the model as a lower saturation distributed throughout the entire block volume. In the segregated state, the gas will redissolve only in the lower or residual oil saturation in the upper, gas-occupied portion of the block volume. However, the model will allow re-solution in the entire block’s oil volume. Pressure hysteresis in the R,(p) curve has been used to cope with this problem; an alternative remedy where the computing budget permits is the use of more grid layers. An assumption common in early black-oil models was that the reservoir oil obeyed a single pair of B,(p) and R,(p) curves. Some black-oil reservoirs exhibit a significant variation of oil API gravity and PVT behavior with depth or with depth and areal location. In some such cases, this variation can be represented in a black-oil model by simply allowing initial solution gas R, to vary with depth in the undersaturated oil column, retaining a single set of B,(p) and R,(p) curves. In other cases, multiple sets of these curves and two oil components are necessary and the single oil-type assumption in a black-oil model can lead to appreciable error. Mechanisms or phenomena that are significant in some reservoirs and may not be represented in the model include compaction, hysteresis in wetting and nonwetting relative permeabilities, and interlayer wellbore crossflow. The latter is a particularly difficult modeling problem and the subject of continuing research. A production well completed in a number of layers may exhibit production from some layers and, simultaneously, injection (backflow or recirculation) into others. Factors that promote this possibility are low-pressure drawdown (high PI and/or low rate) and poor vertical communication between the reservoir layers in the vicinity of the well. A rigorous treatment of this problem requires modeling of wellbore multiphase hydraulics and phase segregation combined with calculation of correct phase mixtures for the layers undergoing injection. Spatial Truncation
Error
Spatial and time truncation error theoretically can be reduced to any desired low level by sufficiently reducing gridblock dimensions and timestep size. However, the resultant increased number of blocks and timesteps frequently lead to prohibitive computer expense and memory storage requirements. Time truncation error is generally insignificant. In most applications timestep size is restricted by considerations other than time truncation error, such as model stability, frequencies of printout, and frequencies of changes in well data (rates, completions, new wells, etc.). In any given case, the level of time truncation error can be estimated by repeating a run or portion of a run with a smaller (or larger) timestep. Insensitivity of results to timestep size indicates low-time truncation error. Spatial truncation error appears in the forms of numerical dispersion, grid-orientation effects, and error in calculated well WOR and GOR values. Spatial truncation error can be expressed in mathematical terms through
ENGINEERING
HANDBOOK
complex manipulation of the model differential equations and Taylor series expansions. In simpler terms, this error can be viewed as a consequence of replacing the physical continuum (reservoir formation) by a 3D network of mixing cells (gridblocks). This consequence is the contradictory requirements that any variable value (pressure, saturation, temperature, concentration) simultaneously represents the value at the grid point (e.g. block center) and the entire block’s volumetric average value. This requirement is not met (1) during a frontal displacement as a sharp front enters the gridblock, (2) when gravity forces result in phase segregation within the block’s thickness, and/or (3) when area1 cusping or coning causes sharp localized saturation gradients within the block volume. Numerical dispersion generally appears as falsely smeared spatial gradients of water saturation in waterflooding, temperature in steamflooding, solvent in miscible flooding, and chemical agent in chemical flooding. This excessive smearing occurs primarily in the areal (X or y) directions and, if uncontrolled, results in too early calculated breakthrough times of water (heat, solvent, etc.) at production wells. This numerical dispersion generally increases with increasing areal gridblock size (AX and AJJ). Lantz95 quantitatively related the difference equation truncation error term to an artificial, second-order diffusion term in the differential equation. The engineer can anticipate possibly significant numerical dispersion effects in simulating two types of miscible displacement. The first type is slug or bank, as opposed to continuous, injection of solvent or CO?. Numerical dispersion erodes the calculated solvent concentration within the bank. If miscibility requires maintenance of solvent bank integrity or a certain solvent peak concentration, then this numerical dispersion can result in a calculated (false) loss of miscibility. The second type is multicontact miscibility For continuous solvent injection in 1D simulations, several studies 3’X97 report the need for 100 to 300 gridblocks to reduce the effect of numerical dispersion on miscible front velocity. Kyte and Berry 75 describe control of numerical dispersion in simulation of waterflooding through large area1 gridblocks. They use pseudorelative-permeability curves obtained from detailed (fine-grid) cross-sectional simulations. Harpole and Hearn98 used their method in a 3D black-oil study. To date, steamflood simulation generally has been confined to pattern studies for which a sufficient number of gridblocks between unlike wells is used to minimize numerical dispersion effects. Killough et al. 73 describe their reduction of numerical dispersion in a stratified, heterogeneous, repeated pattern black-oil reservoir study. They performed fine-grid, 3D singlepattern simulations and then used regression to determine pseudorelative permeabilities for a 2 x 2 four-block area1 grid representation of the pattern. Agreement between the 3D fine-grid results and four-block pattern results was good enough to allow fieldwide simulation by use of the latter coarse, areal definition. Several recent papers99-‘01 describe local grid refinement, the method of characteristics, and other methods to reduce numerical dispersion effects. Pronounced grid-orientation effects have been noted in simulation of adverse mobility ratio floods with models incorporating the commonly used five-point difference scheme and single-point upstream weighting. The value
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48-l 1
SIMULATION
.
5-POINT ---------
g-POINT
PARALLEL-\ GRID
A / / \\ i’ 2 /‘3 r-7 \
/
-DIAGONAL GRID
/
.
3 INJECTION WELL . PRODUCTION WELL
Fig. 48.3-Nine-spot
Fig. 48.2-Five-point
and nine-point
difference
schemes
of the coefficient krJCIJIpJ in Eq. 2 obviously affects the interblock Darcy flow rate from gridblock i-Z to block i. Intuition might dictate evaluation of this coefficient at some average of variable values (pressure, saturations, etc.) in the two blocks. However, considerations of stability and numerical dispersion frequently have led to its evaluation at conditions existing in the block from which the flow occurs-i.e., the upstream block. This is referred to as single-point upstream weighting. The five-point difference scheme is reflected in the form of terms of type A(7Ap) in Eq. 5 for the case of 2D flow. These terms represent the interblock Darcy flow rates in the mass balance equation for each gridblock. The solid arrows of Fig. 48.2 illustrate these flow rates between the gridblock and each of its four neighbors. A strong rid-orientation effect was first reported by Todd et al. ” for highly adverse mobility waterfloods and later observed for pattern steamfloods. lo3 An area1 grid with the usual perpendicular x and y axes may be placed over a five-spot pattern with the x axis either parallel to or at a 45” angle to the line connecting the injector to a producer (Fig. 48.3). These parallel and diagonal grids lo2 can result in markedly different calculated shapes of the water or steam front and the breakthrough times. This difference was reduced by the nine-point finite difference formulation described by Yanosik and McCracken, to4 illustrated by the four extra dashed-line diagonal flow terms in Fig. 48.2. The ninepoint scheme has been programmed into many simulators treating adverse mobility ratio waterfloods, steamfloods, and CO2 solvent displacements. As an example of this grid orientation effect, Fig. 48.3 shows a 3-acre nine-spot steamflood pattern with the diagonal grid and 45”-shifted parallel grid. This pattern
grids
has three types of wells-labeled 1 (injector), 2 (near producer), and 3 (far producer). Reservoir formation and fluid properties and well rates used in the simulation model are reported elsewhere. l4 The calculated results in Table 48.2 show the pronounced effect of grid orientation on steam breakthrough times calculated by use of the fivepoint difference scheme. Obviously, steam should arrive at the near producer, Well 2, before it reaches the far producer, Well 3. The parallel grid with the five-point scheme actually gives breakthrough at Well 3 at 117 days, before breakthrough at Well 2 (204 days). Table 48.2 shows that the nine-point difference scheme virtually eliminates the effect of grid orientation for this problem. Figure 48.4 usesparallel and diagonal grids to show calculated steamfront shapes at 80 days for the two different schemes. The difference between the nine-point fronts for two grids is small and about equal to the error of manual interpolation. A two-point, upstream weighting method lo2 was proposed to reduce both numerical dispersion and gridorientation effects. Abou-Kassem and Aziz lot discuss this and other methods 1oe-108for reducing the orientation effect. They conclude that the nine-point scheme is the most effective in reducing steamflood grid-orientation effects. Two studies105-‘09 show very significant reduction of grid-orientation effects in pattern steamflood simulation results when areally homogeneous, square grids (AX= Ay=constant) are used with the Yanosik and McCracken nine-point scheme. However, the effects persist for a nonsquare, uniform grid (Ax=2Ay)‘09 and the latter scheme yields physically unreasonable results for the cases of heterogeneity and nonuniform grids where AX (or Ay) varies with x (y). The latter shortcoming is addressed by several recent papers110‘112 that propose new or altered nine-point schemes. Frauenthal et al. ‘I3 describe a modified five-point difference scheme and Pruess et al. It4 present a seven-point, hexagonal gridblock scheme for reducing grid-orientation effects. The engineer can anticipate possibly significant gridorientation effects in simulating single- or repeatedpattern, adverse mobility ratio displacements. Preliminary areal, single-pattern model runs allow estimation of the level of such effects and the need for use of a nine-point scheme or other remedy. The discussion and references cited obviously indicate the current concern regarding effects of numericaldispersion and grid-orientation effects on the validity of
PETROLEUM
48-12
DIFFERENCE-SCHEME
GRID
5-POINT
PARALLEL ---
DIAGONAL
5-POINT
----
EITHER
g-POINT
TIME-80
Fig. 48.4-Calculated
DAYS
0
INJECTOR
l
PRODUCER
shape of steamflood
front in a nine-spot
pattern.
simulation results. However, these numerical effects are not serious in many simulation studies. Numericaldispersion effects are generally demonstrated as smearing of theoretically sharp fronts in l- or 2D horizontal displacements in homogeneous formations. Actual reservoir behavior frequently reflects strong gravity effects such as a gas or solvent override or a water underrun. These gravity effects combined with reservoir structure (areal variation in dip angle) can have an influence on fluid movement patterns, which dominates the numerical effects just discussed. In addition, reservoir heterogeneity can play the same relatively dominant role as gravity forces. In highly stratified or layered reservoirs, the different rates of travel of injected fluid through different layers can dominate the numerical dispersion effect at the leading edges of the individual layer displacement fronts. Finally, a given level of numerical-dispersion or gridorientation effect is acceptable if its impact on calculated reservoir performance is inconsequential in an engineering sense-i.e., in light of the questions being asked. The model itself often can be used to estimate the level of these numerical errors and the degree of their acceptability. Before selecting the full study grid, preliminary model runs using grids of varying coarseness can be performed for a representative cross-section or 3D portion
TABLE 48.2-CALCULATED STEAM BREAKTHROUGH TIMES (DAYS) FOR A NINE-SPOT PATTERN Well 2
Five-point Nine-point
Well 3
Diagonal
Parallel
Diagonal
Parallel
47.0 87.7
204 75.5
1,400 900
117 1,000
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of the reservoir. The results can be helpful in selecting the coarsest grid spacing compatible with acceptably low numerical dispersion. In fieldwide simulation, spatial truncation error may affect calculated values of well productivity, wellbore producing pressure, and WOR and GOR. Without special measures, the model calculates the well behavior with only the gridblock’s average values of pressure, saturations, etc. However, the actual well behavior may reflect nearwell coning, liquid dropout, or gas evolution effects. The dimensions of this near-well region may be two orders of magnitude smaller than the areal block dimensions (b, Ay). Thus the block’s average conditions may provide a poor basis for calculating well behavior. This problem can be significant for a well completed throughout formation thickness and even more significant for a partially penetrating well. The simplest remedy to this problem is applicable in some cases where good vertical communication results in a high degree of vertical phase segregation. In this case, well pseudorelative-permeability curves have been used. 1’5,1’6 These curves reflect the location of the completion interval and relate well behavior to average block conditions. A more complicated approach requires use of multivariable correlations relating well WOR and GOR to average block conditions. ’“g118 These correlations are developed from a number of single-well r-z (radial-depth) model runs with fine grid spacing near the wellbore. The most rigorous treatment of this problem incorporates individual 1D radial or 2D ~-2 simulations for each well simultaneously within the fieldwide 3D simulation. ’19,120 Again, in any given case, the model itself can be used to estimate the severity of this problem through comparison of single-well, r-z and representative 3D (portion of reservoir) model results. Uncertain
Reservoir
Description
Data
Errors in reservoir description data clearly contribute to errors in simulation model results. Since the description data are never exactly known, one might infer that model results are necessarily erroneous and unreliable. A number of considerations contribute, in contradiction of this inference, to model results being widely used to select and to design oil-recovery processes and to forecast oil recovery. Accurate determination of all reservoir description data is not necessary for reliability of model results. The required accuracy of any description parameter is proportional to its influence on computed results (reservoir performance). The simulation model should be used to perform preliminary sensitivity runs to determine which description data are important. Expense and effort should then be concentrated on obtaining or refining only those “sensitive” description data. The particular parameters found to be important will vary from study to study, depending on the nature of the reservoir, the recovery process(es) of interest, and study objectives or questions. For example, if computed oil recovery is insensitive to wide variations in the gas relative-permeability curve, then the accuracy of this curve might deserve little attention. In a case where the gravity drainage mechanism is dominant, the oil relative-permeability curve at low and midrange oil saturations has a large effect on oil recovery and deserves effort of definition. Gas viscosity, relative
RESERVOIR
48-13
SIMULATION
permeability, and capillary pressure may play virtually no role and their accuracies are irrelevant. All phase relative permeabilities may be unimportant in a natural or flank waterflood of a relatively clean, thick high-relief sand where gravity forces are dominant with pronounced phase segregation. Only relative-permeability curve endpoints may be important in such cases. However, thinner sand or stratification, lower permeability and/or higher rates can increase the importance of water and oil relativepermeability curve shapes. While capillary pressure is unimportant in many reservoir studies, it can provide the dominant, cross-imbibition, mechanism in waterflooding thin, heterogeneous water-wet sands. In some studies, the engineer is less concerned with the absolute accuracies of both model results and description data than with the sensitivity of calculated results to variations in those data. An example is a study performed to compare oil recoveries under alternative recovery processes. Model runs performed for each process, with reservoir description data varied over estimated ranges of uncertainty, may yield substantially invariant process rankings and incremental oil recovery differences. If so, any significant history-matching effort may be unnecessary and the only concern regarding accuracy of description data should be the estimated ranges of uncertainty. Another example is a design study of a given recovery process performed to optimize pattern type and size, well completions, and rates. Model runs, as just described, may show that minimal history-match and/or laboratory efforts for reservoir description are necessary to meet the study objective. As previously mentioned, reservoir description data are altered through history matching to improve agreement between model results and reservoir performance data. Frequently, the study objectives involve estimation of reservoir performance under displacement conditions not present or recovery processes not active during the history period. In such cases, some description parameters that significantly influence future performance may not be reflected in the historical performance. An example is a heavy-oil reservoir that was produced for nearly 40 years under natural depletion with no water drive. Solution gas was very low and interstitial water saturation was immobile. A 50% water cut developed in time as a large pressure decline caused water mobility through water expansion and porosity reduction. Performance data included WOR, GOR, and pressure data for a number of wells. The only description parameters influencing these data were formation permeability, compressibility, critical gas saturation, water relative permeability at saturations slightly above SwC, and gas relative permeability at saturations slightly above S,,. The history-match effort gave a good match of performance with a unique set of these parameter values. However, it provided no information regarding the full-range relative-permeability curves necessary to estimate oil recovery under waterflood and steam stimulation or flooding. Laboratory relative-permeability measurements and waterflood and thermal pilots were conducted in this case. Laboratory work and well pressure testing can be performed to estimate values of some reservoir description parameters that are not reflected in performance data. These parameters, together with others determined by history matching, can be used in model runs to estimate
oil recovery under the various alternative recovery schemes within the study scope. Field pilot tests then may be planned for one or more of the recovery processes, subject to the model results and engineering judgment. Argument has persisted for years regarding uniqueness of the reservoir description obtained by history matching. A thorough treatment of this question requires length and mathematical complexity beyond the scope of this chapter. Any such treatment requires careful definition of terms. For example, define a reservoir description as a bounded set of m numbers {Xi} representing selected zonal permeabilities and porosities and parameters characterizing relative permeability curves. Let the sets of N numbers {dj*}, {dj} represent observed and model calculated performance data where dj=dj(x, ,x2.,.x,). If N>m, each xi affects one or more dj, and the d. are independent functions of {Xi} (in a mathematics i sense undefined here), then with rare exceptions a unique set of parameter values {Xi} will minimize the difference between the observed and calculated data. An altered zonation gives a physically different parameter set {ii}. Again, a unique set of values of {ai} generally will minimize the difference between observed and calculated data. However, for this two-parameter set “experiment,” comparable matches of observed data would allow a claim of nonuniqueness. As a practical matter, study budget and time constraints prevent exhaustive trials of different parameter sets and even limit the number of model runs with different combinations of parameter values within a given set. Generally, difficulty encountered in a history-match effort is that of finding any reasonable description that gives good agreement with history. The effort rarely ends with difficulty in selecting among significantly different reservoir descriptions that give comparably good matches. In any event, the pertinent question regarding reservoirdescription data is not related to correctness or uniqueness in an absolute sense. The pertinent question concerns the engineering significance of variations in parameter values within ranges of uncertainty. As discussed previously, the model itself is useful in estimating this significance.
Simulation Technology Simulation technology can be divided roughly into the categories of model definition, model formulation, solution techniques, and special techniques related to numerical dispersion control, viscous fingering, and gridorientation effects. Model definition includes specification of the problem (process) addressed, component identities, mass transport laws or expressions, fluid PVT and rock property relationships and, finally, the set of finitedifference equations expressing conservation of mass for each gridblock. These equations are generally nonlinear. Before they can be solved for pressures, saturations, etc., they must be linearized and manipulated into a set of simultaneous linear algebraic equations. The term formulation refers to these manipulations and the final form of this set of linearized equations. In a general sense, this set of equations can be expressed in the matrix form Ap = b where A is a very sparse, banded Nb xN~ matrix and the known t, and unknown e are column vectors of dimension Nb . A rapidly expanding portion of the simulation literature describes increasingly efficient, iterative solution techniques for this problem.
.
48-14
Model Formulations In 1959, Douglas et al. I6 proposed leap-ffog and simultaneous formulations for incompressible 2D twophase flow. During 1960-69 a number of authors21-24 described two- and three-phase, 2D and 3D black-oil models based on this simultaneous formulation. In 1960, Stone and Garder I8 and Sheldon et al. I7 introduced the concept of eliminating saturation derivatives among the black-oil model equations to obtain a sin le difference equation in pressure. Fagin and Stewart 1$ in 1966 and Breitenbach et al. *O in 1968 described three-phase blackoil models based on this implicit-pressureiexplicitsaturation (IMPES) formulation. The IMPES formulation is explicit in saturation and composition in that relative permeabilities and concentrations are expressed explicitly in the interblock flow terms. Solution of the pressure equations over the grid is followed by an explicit updating of phase saturations and compositions in each gridblock. In 1969, Blair and Weinaug12’ published a fully implicit formulation which expresses all terms in the interblock flow and well production expressions implicitly. This requires simultaneous solution of all N model equations. A number of later papers describe implementation of the implicit formulation in black-oil, “* compositional 3’ and thermal 39 models. In 1970, MacDonald’23 improved the stability of the IMPES method for the two-phase water/oil case by following the pressure equation solution with solution of a water-saturation equation over the grid using implicit (new-time-level or end-of-timestep) values of relative permeabilities in the interblock flow terms. Spillette et al. 124 extended this concept to the three-phase case and called the formulation sequential. The IMPES formulation can become unstable if the volumetric flow through a gridblock in a timestep exceeds a small fraction of the block PV. The more stable sequential formulation remains stable to much larger ratios of gridblock volumetric throughput/PV. The tolerable throughput ratio for the implicit formulation is significantly larger than that of the sequential method. Arithmetic (or computing cost) per timestep and timestep size both increase from IMPES to sequential to implicit formulations. Since the total cost of simulating a given time period is proportional to the product of arithmetic per timestep and timestep size, all three formulations are used widely today. The sequential formulation can fail to preserve material balances in some problems where adjacent ridblock compositions differ greatly. ‘25 Meijerink ‘*Q described a stabilized IMPES formulation, which improves the stability of IMPES to a lesser extent than the sequential method but reduces material balance error in regions of steep composition gradients. Thomas and Thurnau 127 describe an adaptive implicit formulation, which allows different levels of implicitness in different gridblocks. These various levels may change with timestep number and with iteration number within a given timestep. As previously mentioned, the implicit formulation 12’requires simultaneous solution of N equations for each block over the entire grid. The corresponding arithmetic effort of solution is proportional to N3. Since N= 1 for IMPES, the implicit formulation obviously requires considerably more computing time per timestep
PETROLEUM
ENGINEERING
HANDBOOK
than does IMPES. For each gridblock, the adaptive implicit method internally senses (without user intervention) which dependent variables (e.g., saturations, pressure, mole fractions) require implicit dating for stability. For most practical reservoir problems this results in one equation per gridblock for a major fraction of the grid and an overall average number of equations per block considerably less than N. Thus the method can attain the stability of the implicit formulation with considerably less computing expense. Also, computer storage requirements are reduced significantly. Future implementations of this formulation may contribute to increased model reliability (stability) and efficiency in simulations of all types of recovery processes. Single-well coning studies generally involve radial grid spacings, resulting in very small gridblocks near the well and large throughput ratios. For these studies, the IMPES formulation is unsuitable, and the implicit formulation is generally the most efficient. ‘** For field-scale, 3D blackoil studies, the overall computing time is frequently less with the sequential than with the IMPES or implicit formulation. The typical black-oil simulator applied today in 1,OOO-or more gridblock, field-scale studies is an IMPES model with a user-specified option of sequential solution. Smaller black-oil studies and preliminary crosssectional, coning, and sensitivity studies associated with the large problems frequently employ the implicit formulation. Recent thermal models involve implicit formulations. With one exception 3’ recent compositional models29-33 are based on the IMPES formulation. The popular IMPES and more recent implicit formulations are illustrated here for the case of 3D two-phase flow of water and undersaturated oil. This illustration is in the form of the Newton-Raphson procedure, which Blair and Weinaug l2 ’ used in describing their implicit formulation. For clarity, rock compressibility, gravity, and capillary pressure are neglected, and phase (component) production rates are fixed, independent of pressure and saturations. The terms explicit and implicit refer to the time level of evaluation for variables or terms in the left side, interblock flow terms of Eqs. 5. Explicit dating denotes evaluation at the beginning of the timestep, t, (level n), while implicit dating denotes evaluation at the end of the timestep, t,+i (level n+ 1). The implicit formulation of Eq. 5, then, appears for each gridblock as
=f(S,,p)=O
. . . . ., . .
..
. . . . . . . . (lla)
and A(T,Ap)-qpo =g(S,,p)=O,
-+,S,
-@Jo),1
....... ......... ..
. (llb)
where T p qpp VP
= = = =
interblock transmissibility, pressure, production rate of phase P, oil or water PV of gridblock,
RESERVOIR
48-I 5
SIMULATION
where T and C are 2 X 2 matrices and P and R - are 2 X 1 column vectors:
Atp = timestep bp = reciprocal formation volume factor of phase P, ST vol/res vol, Sp = saturation of phase P, and f, g = function of. Gridblock indices ij, and k on all terms are suppressed for clarity. All terms at time level n are known from the previous timestep’s calculations. The absence of time level subscript denotes the implicit level, n + 1. Thus all terms T,,T,,b,,b,,S,,S,,p in Eq. 11 represent unknown values at time level n + 1, For all Nb gridblocks, Eqs. 11 are ~Nz. eouations in the 2Nh unknowns }. For a particular gridblock, Eqs. ~s,ikniYltPi,‘kn+I 11 a;k ‘two e&rations in the 14 unknowns consisting of (S,,p) pairs in the block and its six neighbors. Thesesix neighbor pairs are introduced by the Laplacian interblock flow terms. Oil saturations are not additional unknowns the transmissibilities T and reciprocal since S, =I-S,; formation volume factors (b) are functions of S ,,, and p. Application of the well-known Newton-Raphson iterative procedure to Eq. 11 gives
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
(15)
The coefficients Tll , TzI arise from saturation derivatives of relative permeabilities in the transmissibilities. The C matrix elements are obvious upon inspection of The compressibilEqs. 13 (e.g., c,* = VplA,(S,b,c,). ities (c, ,c,) appear through the definition c = (1 ib)dbidp. Eq. 14 written for all gridblocks is a set of Nb linear parabolic difference equations in the Nt, unknowns {Pi,.,k}. Following solution by a direct or iterative technique, the new iterates are calculated as S,$+’ =S$+ are recalculated at 6Sw ,P p+’=pp+Gp. Coefficients 1+1 (SK, .p “I ) for all blocks and Eq. 14 is solved again. These outer or Newton iterations are continued until the maximum values over the grid of { IAS,,,I , ISp I } are less than some prescribed tolerances. The term inner iterations refers to iterations performed by an iterative solution technique in solving Eq. 14 for a given Newton iteration. The IMPES formulation treats transmissibilities explicitly SO that the first terms in Eqs. 11 are A(T, Ap) and A(T,,Ap), where T,, and T,, are calculated from known saturations at time level n. This results, upon application of Eq. 12, in zero values for transmissibility derivatives with respect to neighboring block saturations and Eq. 16 replaces Eq. 13:
........................(124 f6p=o and
b? pls g(s,,p)=g(sppf)+ W, (-6S, 1 w Wb) where P is iteration number, superscript Pdenotes evaluation at (S&‘), hp=p’+’ -pp, and S,f,,pp approach the desired S, ,p values as 4 increases. The terms containing derivatives are actually sums of seven terms because of the previously mentioned functional dependence on neighboring block unknowns. Substituting from Eqs. 11 into Eqs. 12, performing the differentiation and rearranging the result gives A(7-p11A&S,)+A(TP,2A8p)-
VP -b&E, AI
“P
.
(134
and
and A(T,,Asp)
+ %b$S,
.
.
(16b)
The single saturation unknown, 6S,, can be eliminated by multiplying Eqs. 16a and 16b by B,fz and BJ, respectively, and adding to obtain
-J$S
.
.
.
,L,cM.+SSUcO)E~p+B~~fY+BljigY=O,.
(17)
(13b)
or in condensed matrix form, ... ..
.(16a)
B,$ A(T,.,A&p) + B,PA(T,,,A&p)
VP -b,ySS, At
-- “P At (S,b,c,)pGp+g(S~,pe)=O,
A(Tc)-Cc+B=O,
,+b ,c,)‘6p+f(S$,,pp)=0..
-~(S,b,c,)‘6p+g(S&pp)=0.
- pt(S,b”c,)Y6P+f(S~,PY)=O
A(TpZ,A6S,)+A(Tp*2A6p)+
-z(S
. (14)
where B is the formation volume factor, l/b. This is a set of Nb single or scalar, linear parabolic difference equations in the Nb pressure unknowns {Gp+ } As described before, a number of outer or Newton iterations are performed with pressure updated and coefficients
48-16
PETROLEUM
recalculated after each iteration. After convergence, saturation S, is explicitly calculated, block by block, from Eq. 1 la (with T,, in the first term). Eq. 17 can be written more simply for the section to follow as A(TAGp)-c++r=O,
...
. ..
(18)
where T, 6p,c, and r are scalars. Solution Techniques Eq. 18 written for all Nb gridblocks can be expressed in matrix form as AP=b,
. . _.
. ....
..............
(19)
where A is a nonsymmetric, sparse Nb xN~ matrix and &’is the Nb x 1 column vector (Sp Uk) . Direct solution (Gaussian elimination) or iterative methods can be used to solve Eq. 19. The arithmetic effort required in direct solution strongly depends on the pattern of nonzero elements in the A matrix. This pattern in turn depends upon the particular linear ordering or numbering of the Nb gridblocks. An ordering is simply a one-to-one correspondence between a linear index m = 1,2 . Nh and the gridblock indices {ij,k}, i= 1,2. . .N,, j=1,2,. . .N,, k = 1,2. . NZ . Here the term natural ordering denotes numbering the blocks consecutively first in the shortest direction, then in the next shortest direction, and finally in the longest direction. For example, if N, >N, > N,, then m=k+(j-l)N,+(i-l)NYN,.
.
.... .
(20)
Breitenbach et al., ‘29 Peaceman, ’ and others illustrate the diagonal-band form of the A matrix and minimum direct solution effort which result from this natural ordering. The half bandwidth of the A matrix is N,N, and the arithmetic effort (number of multiplications) of direct solution is roughly proportional to Nb(NyN,)*. Iterative methods require an arithmetic effort roughly proportional to Nb. Thus increasing problem size, Nh, renders iterative solution increasingly preferable to direct solution. For large problems, computer storage requirement is also significantly less for iterative than direct solution. Price and Coats I30 described reduced bandwidth direct solution methods based on diagonal (D2) and alternatediagonal (D4) gridblock orderings. For certain test problems and iterative methods, they showed a D4 direct/iterative work ratio less than unity for half bandwidths up to about 30. Compared with natural ordering, D4 ordering can reduce direct solution computational effort by factors up to four and six for the 2D and 3D cases, respectively. Woo et al. 13’ described other techniques that take advantage of matrix sparsity to reduce direct solution effort. In spite of these advancements in direct solution, iterative methods remain preferable for large reservoir studies. Successive-overreluxation (SOR) iterative methods described bv Young 132,‘33have been used in simulators from the early 1960’s. Block SOR (BSOR) methods, including line (LSOR), two-line, and planar SOR, have proved especially popular. The BSOR methods require direct solution within each block, which means that direct
ENGINEERING
HANDBOOK
solution must be performed for tridiagonal matrices in LSOR and pentadiagonal matrices in planar SOR. As the block size is increased the arithmetic work per iteration increases because of the increased arithmetic associated with this direct solution within each block. However, convergence rate generally increases and the total number of iterations correspondingly decreases with increasing block size. To some extent, optimal block size can be determined by mathematical analysis ‘33,134 of this tradeoff between work per iteration and number of iterations. The SOR methods remain popular because of ease of coding, low computer storage requirement and automatic determination of the optimum value of the single iteration parameter. Varga ‘~4 describes the power method for this parameter determination and Breitenbach et al. 129 illustrate its application. In 1971, Watts135 presented an additive correction method which improves LSOR convergence rate in highly anisotropic problems. A highly anisotropic problem is one where, throughout the grid, transmissibibties in one direction are much reater than those in other direction(s). Settari and Aziz ’B6 extended Watts’ method to other iterative solution techniques. Alternating-direction iterative methods (ADI) were developed for 2D by Peaceman and Rachford 137 in 1955 and for 3D by Douglas and Rachford ‘38 in 1956. These methods were widely used in simulation throughout the 1960’s and into the 1970’s. The AD1 methods require a sequence or set of iteration parameters. While mathematical analysis yields an optimal parameter set for certain cases, 1,137actual reservoir cases frequently require some trial-and-error effort. In 1968, Stone 139 described the strongly-implicit procedure (SIP); Weinstein et al. t4’ described SIP in 3D. Again, a set of iteration parameters is required. Parameter estimation methods associated with AD1 have proved useful for SIP * but, again, some trial-and-error effort is required or beneficial in man reservoir studies. A number of studiest29~136~15~141 compare direct solution, LSOR, ADI, and SIP methods for a variety of test and reservoir problems. There is no simple answer to which method is best. The ranking of the methods is problem-dependent in that it depends on the range of variation in coefficient (transmissibility) values in the A matrix and the pattern (e.g., highly anisotropic), if any, of their variation. In general, the more difficult reservoir problems have a very large range from the smaller to larger transmissibilities and this large ratio is not uniformly associated with a particular direction throughout the grid. SIP became widely used throughout the 1970’s and remains in use today because it frequently outperforms the other methods in these difficult cases. A new class or type of iterative methods is the subject of a number of papers’4’-‘50 published since the mid 1970’s. Basically, the methods involve approximate factorization of the A matrix into an LU product, followed by an iterative sequence wpk+’
-pk)=rk,
,......
.
..
(21)
where L = a lower triangular for j>i),
matrix (all entries Pii =0
RESERVOIR
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SIMULATION
V = an upper triangular matrix (all entries uii = 0 forj
Nomenclature A = a nonsymmetric, sparse Nb x Nh matrix A = Ay,AZk =cross-sectional area normal to flow bp = reciprocal formation volume factor of phase P, ST vol/res vol C = 2x2 matrix C,J = concentration of component I in phase J C,p = concentration of component I in phase P CNJ = concentration of component N in phase .I f,J = fugacity of component I in phase J
HJ = enthalpy, energy/mole k rP = relative permeability to phase P (P=w,o,g) L= a lower triangular matrix (all entries e,=O forj>i), see Eq. 21 L= distance between adjacent block centers, (AT~-~ +Ax;)/2, see Eq. 1 m= 1, 2. _ .Nb, linear index Nb = total number of gridblocks, N,N,N, N, = number of gridblocks in x direction N, = number of gridblocks in y direction N, = number of gridblocks in z direction n= time level, t n+, =t, +A\t P= Nbxl column vector {6pijk}, see Eq. 19 P ego = gas/oil capillary pressure P two = water/oil capillary pressure 9I = component I interblock flow rate, mass/time qpi = mass rate of production of component I qpp = production rate of phase P (water or oil) R= 2 X 1 column vector s,, = critical gas saturation SJ = saturation of phase J s WC= critical water saturation T= interblock transmissibility and T=2 x 2 matrix TN = interblock transmissibility for flow of component I in phase .I T,, = oil transmissibility at time level 12 T wn = water transmissibility at time level n V = an upper triangular matrix (all entries uij=O forj
References 1. Peaceman, D.W. : Fundamenta1.s of Numerical Reservoir Simulation, Elsevier Scientific Pub. Co., New York City (1977). 2. Criehlow, H.G.: Modem Reservoir Engineering-A Simulation Approach, Prentice-Hall, Inc., Englewood Cliffs, NJ (1977). 3. Aziz, K. and Set&i, A.: Petroleum Reservorr Simulation. Applied Science Publishers, London (1979). 4. Thomas, G.W.: Principles of Hydrocarbon Reservoir Simulation, second edition, Intl. Human Resources Dev. Corp.. Boston (1982). 5. Muskat, M.: The Flow of Homogeneous Fluids Through Porous Media, J.W. Edwards, Inc., Ann Arbor, MI (1946). 6. Muskat, M,: Physical Properties ofOil Production, McGraw-Hill Book Co. Inc., New York City (1949)
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7. Muskat, M.: “The Production Histories of Producing Gas-Drive Reservoirs,” J. Applied fhys. (1945) 16, 147. 8. Katz, D.L.: “Methods of Estimating Oil and Gas Reserves,” Trans., AIME (1936) 118, 18-32. 9. Buckley, S.E. and Leverett, M.C.: “Mechanism of Fluid Displacement in Sands,” Trans., AIME (1942) 146, 107-17. 10. Welge, H.J.: “A Simplified Method for Computing Oil Recoveries by Gas or Water Drive,” Trams, AIME (1952) 195, 91-98. 11. Odeh, A.S.: “Reservoir Simulation-What Is It?” J. Pet.Tech. (Nov. 1969) 1383-88. 12. Staggs, H.M. and Herbeck, E.F.: “Reservoir Simulation Models-An Engineering Overview,” J. Pet. Tech. (Dec. 1971) 1428-36. 13. O’Dell, P.M.: “Numerical Reservoir Simulation: Review and State of the Art,” paper presented at the 1974 National AIChE Meeting, Tulsa, OK, March 11-13. 14. Coats, K.H.: “Reservoir Simulation: State of the Art,” J. Per. Tech. (Aug. 1982) 1633-42. 15. Craft, B.C. and Hawkins, M.F. Jr.: Applied Petroleum Reservoir Engineering, Prentice-Hall, Inc., Englewood Cliffs, NJ (1959). 16. Douglas, I. Jr., Peaceman, D.W., and Rachford, H-H., Jr.: “A Method for Calculating Multi-Dimensional Immiscible Displacement,” Trans., AIME (1959) 216, 297-308. 17. Sheldon. J.W.. Harris. C.D.. and Bavlv, D.: “A Method for General’Reservoir Behavior Simulation dn Digital Computers,” paper SPE 1521-G presented at the 1960 SPE Annual Meeting, benver. Oct. 2-5. 18. Stone, H.L. and Garder, A.O. Jr.: “Analysis of Gas-Cap or Dissolved-Gas Drive Reservoirs,” Sac. Pet. Eng. J. (June 1961) 92-104; Trans., AIME, 222. 19. Fagin, R.G. and Stewart, C.H. Jr.: “A New Approach to the TwoDimensional Multiphase Reservoir Simulator,” Sot. Per. Eng. J. (June 1966) 175-82; Trans., AIME, 237. 20. Breitenbach, E.A., Thumau, D.H., and Van Poolen, H. K.: “The Fluid Flow Simulation Equations,” paper SPE 2020 presented at the 1968 SPE Symposium on Numerical Simulation of Reservoir Performance, Dallas. April 22-23. 21. Coats, K.H. etal.: “Simulation ofThree-Dimensional. Two-Phase Flow in Oil and Gas Reservoirs,” Sot. Pet.Eng. J. (Dec. 1967) 377-88; Trans., AIME, 240. 22. Peery, J.H. and Herron, E.H. Jr.: “Three-Phase Reservoir Simulation,” J. Pet. Tech. (Feb. 1969) 21 l-20; Trans., AIME, 246. 23. Snvder. L.J.: “Two-Phase Reservoir Flow Calculations.” Sot. Pe;. Eng. J. (June 1969) 170-82. 24. Sheffield, M.: “Three-Phase Fluid Flow Including Gravitational, Viscous and Capillary Forces,” Sot. Pet. Eng. 2. (June 1969) 255-69, Trans., AIME, 246. 25. Zudkevitch, D. and Joffe, J.: “Correlation and Prediction of VaporLiquid Equilibria with the Redlich-Kwong Equation of State,” AlChE J. (Jan. 1970) 16, 112-19. 26. Soave, G.: Chem. Eng. Sci. (1972) 27, 1197. 27. Peng, D.Y. and Robinson, D.B.: “A New Two-Constant Equation of State,” Ind. Eng. Chem. Fund. (1976) 15, 59. 28. Martin, J.J.: “Cubic Equations of State-Which?” Ind. Eng. Chem. Fund. (May 1979) 18, 81. 29. Kazemi, H., Vestal, C.R., and Shank, G.D.: “An Efficient Multicomponent Numerical Simulator,” Sot. Per. Eng. J. (Oct. 1978) 355-68. 30. Fussell, L.T. and Fussell, D.D.: “An Iterative Technique for Compositional Reservoir Models,” Sot. Pet. Eng. J. (Aug. 1979) 211-20. 31. Coats, K.H.: “A Equation of State Compositional Model,” Sot Per. Eng. J. (Oct. 1980) 363-76. 32. Nghiem, L.X., Fong, D.K., and Aziz, K.: “Compositional Modeling With an Equation of State,” Sot. Pet. Eng. J. (Dec. 1981) 688-98. 33. Young, L.C. and Stephenson, R.E.: “A Generalized Compositional Approach for Reservoir Simulation,” Sot. Pet. Eng. J. (Oct. 1983) 727-42. 34. Gottfried, B.S.: “A Mathematical Model ofThermal Oil Recovery m Linear Systems.” Sot. Pet. Eng. J. (Sept. 1965) 196-210; Trans., AIME, 234. 35. Shutler, N.D.: “Numerical Three-Phase Model of the TwoDimensional Steamflood Process,” Sot. Pet. Eng. J. (Dec. 1970) 405-17; Trans., AIME, 249. 36. Weinstein, H.G., Wheeler, J.A., and Woods. E.G. : “Numerical Model for Thermal process,” Sot. Pet. Eng. J. (Feb. 1977) 65-78; Trans., AIME, 263.
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37. Crcokston. H.B., Culham, W.E., and Chen, W.H.: “A Numerical Simulation Model for Thermal Recovery Processes,” Sac. Pet. Eng. J. (Feb. 1979) 37-58; Trans., AIME, 267. 38. Youngren, G.K.: “Development and Application of an In-Situ Combustion Reservoir Simulator,” Sot. Pet. Eng. J. (Feb. 1980) 39-5 1. 39. Coats, K.H.: “In-Situ Combustion Model,” Sot. Pet. Eng. .I. (Dec. 1980) 533-53. 40. Hwang, M.K., Jines, W.R., and Odeh, A..%: “An In-Situ Combustion Process Simulator With a Moving-Front Representation,” Sot. Pet. Eng. J. (April 1982) 271-79. 41. Gogarty, W.B.: “Status of Surfactant or Micellar Methods,” J. Pet. Tech. (Jan. 1976) 93-102. 42. Johnson, C.E. Jr.: “Status of Caustic and Emulsion Methods,” J. Pet. Tech. (Jan. 1976) 85-92. 43. Pope, G.A. and Nelson, R.C.: “A Chemical Flooding Compositional Simulator,” Sot. Pet. Eng. J. (Oct. 1978) 339-54. 44. Todd, M.R. and Chase, CA.: “A Numerical Simulator for Predicting Chemical Flood Performance,” Proc., Fifth SPE Symposium on Reservoir Simulation (1979) 161-74. 45. Fleming, P.D. III, Thomas, C.P., and Winter, W .K.: “Formulation of a General Multiphase, Multicomponent Chemical Flood Model,” Sot. Per. Eng. J. (Feb. 1981) 63-76. 46. Thomas, L.K., Dixon, T.N., and Pierson, R.G.: “Fractured Reservoir Simulation,” Sot. Pet. Eng. J. (Feb. 1983) 42-54. 47. Gilman, J.R. and Kazemi, H.: “Improvements in Simulation of Naturally Fractured Reservoirs,” Sot. Pet. Eng. J. (Aug. 1983) 659-707. 48. Blaskovich, F.T. er al.: “A Multicomponent Isothermal System for Efficient Reservoir Simulation,” paper SPE 11480 presented at the 1983 SPE Middle East Oil Show, Manama, March 14-17. 49. Henderson, J.H.. Dempsey, J.R. and Tyler, J.C.: “Use of Numerical Models to Develop and Operate Gas Storage Reservoirs,” J. Pet. Tech. (Nov. 1969) 1239-46. 50. Mann, L.D. and Johnson, G.A.: “Predicted Results of Numeric Grid Models Compared With Actual Field Performance.” J. Pet. Tech. (Nov. 1970) 1390-98. 51. Thomas, J.E. and Driscoll, V.J.: “A Modeling Approach for Optimizing Waterflood Performance, Slaughter Field Chickenwire Pattern,” J. Pet. Tech. (July 1973) 757-63. 52. “A Study of the Sensitivity of Oil Recovery to Production Rate.” Proc., Alberta Energy Resources Conservation Board, No. 75 11 (Feb. 1974) Schedule 1, Shell Canada Ltd. 53. Stright, D.H. Jr.. Bennion, D. W., and Aziz, K.: “Influence of Production Rate on the Recovery of Oil From Horizontal Waterfloods,” J. Pet. Tech. (May 1975) 555-63. 54. Thakur, G.C., et al. : “G-2 and G-3 Reservoux, Delta South Field, Nigeria: Part 2-Simulation of Water Injection,” J. Pet. Tech. (Jan. 1982) 148-58. 55. Graue, D.J. and Zana, E.T.: “Studv of a Possible CO? Flood in Rangely Field, Colorado,” J. Pet.‘Tech. (July 1981) 1~12-18. 56. Bloomquist, C.W., Fuller, K.L., and Moranville, M.B.: “Miscible Gas Enhanced Oil Recovery Economics and the Effects of the Windfall Profit Tax,” paper SPE 10274 presented at the 1981 SPE Annual Technical Coifeience and Exhibition, San Antonio, Oct. 5-7. 57. Todd, M.R., Cobb, W.M., and McCarter, E.D. : “CO2 Flood Performance Evaluation for the Cornell Unit, Wasson San Andres Field,” J. Pet. Tech. (Oct. 1982) 1583-90. 58. Herrera, J.Q. and Hanzlik, E.J.: “Steam Stimulation History Match ofMultiwel1 Pattern in the Sl-B Zone, Cat Canyon Field,” paper SPE 7969 presented at the 1979 California Regional Meeting, Ventura, April 18-20. 59. Williams, R.L.: “Steamflood Pilot Design for a Massive, Steeply Dipping Reservoir,” paper SPE 10321 presented at the 1981 SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 5-7. 60. Meldau. R. F., Shipley, R.G., and Coats, K.H .: “Cyclic Gas/Steam Stimulation of Heavy-Oil Wells,” J. Pet. Tech. (Oct. 1981) 1990-98. 61. Gomaa, E.E., Duerksen, J.H., and Woo, P.T.: “Designing a Steamflood Pilot in the Thick Monarch Sand of the Midway-Sunset Field,” J. Per. Tech. (Dec. 1977) 1559-68. 62. Moughamian, J.M., et al. : “Simulation and Design of Steam Drive in a Vertical Reservoir,” J. Per. Tech. (July 1982) 1546-54. 63. “Selection of Reservoirs Amenable to Micellar Flooding,” First Annual Report, Dept. of Energy (Dec. 1980) BC/OOO48-20. 64 Fayers, F.J., Hawes, R.I., and Mathews, J.D.: “Some Aspects
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of the Potential Application of Surfactants or CO2 as EOR ProcessesinNorth Sea Reservoirs,” J. Per. Tech. (Sept. 1981) 1617-27. dezabala, E.F., er al.: “A Chemical Theory for Linear Alkaline Flooding,” Sot. Pet. Eng. J. (April 1982) 245-58. Patton, J.T., Coats, K.H., and Colegrove, G.T.: “Prediction of Polymer Flood Performance,” Sot. Per. Eng. J. (March 1971) 72-84; Trans., AIME, 251. Todd, M.R. and Longstaff, W.J.: “The Development. Testing, and Application of a Numerical Simulator for Predicting Miscible Flood Performance,” J. Per. Tech. (July 1972) 874-82; Trans., AIME, 253. Cook, R.E., Jacoby, R.H., and Ramesh, A.B.: “A Beta-Type Reservoir Simulator for Approximating Compositional Effects During Gas Injection,” Sot. Per.Eng. J. (Oct. 1974) 471-81. Patton, J.T., Coats, K.H., and Spence, K.: “Carbon Dioxide Well Simulation: Part I-A Parametric Study,” J. Per. Tech. (Aug. 1982) 1798-1804. Coats, K.H.: “Simulation of Gas Condensate Reservoir Performance,” paper SPE 10512 presented at the 1982 SPE Reservoir Simulation Symposium, New Orleans, Feb. 1-3. Coats, K.H.: “Simulation of l/8 Five-/Nine-Spot Patterns,” Sot. Pet. Eng. J. (Dec. 1982) 902. Killough, I.E., et al.: “The Kuparek River Field: A Regression Approach to Pseudorelative Permeabilities,” paper SPE 1053 1, presented at the 1982 SPE Symposium on Reservoir Simulation, New Orleans, Feb. 1-3. Killough, I.E., er al.: “The Prudhoe Bay Field: Simulation of a Proc., Intl. Petroleum Exhibition and COIIIpleX ReSeNOir,” Technical Symposium, Beijing (1982) 777-94. Jacks, H.H., Smith, O.E., and Mattax, C.C. : “The Modeling of a Three-Dimensional Reservoir With a Two-Dimensional Reservoir Simulator-The Use of Dynamic Pseudo Functions,” Sot. Pef. Eng. J. (June 1973) 175-85. Kyte, J.R. and Berry, D.W.: “New Pseudo Functions to Control Numerical Dispersion,” Sot. Pet. Eng. J. (Aug. 1975) 269-76. Killough, J.E. and Foster. H.P. Jr.: “Reservoir Simulation of the Empire Abe Field: The Use of Pseudos in a Multilayered System.” Sot. Per. Ert~. J. (Oct. 1979) 279-88. Coats, K.H., Dempsey. J.R.. and Henderson, J.H.: “The Use of Vertical Equihbrrum in Two-Dimensional Simulation of ThreeDimensional Reservoir Performance,” Sot. Per. Enx. J. (March 1971) 63-71; Trans.. AIME, 251. Hear”, C.L.: “Simulation of Stratified Waterflooding by Pseudo Relative Permeability Curves,” J. Per. Trch. (July 1971) 80-13. Simon. R., Rosman. A.. and Zana. ET.: “Phase-Behavior Properties of CO*-Reservoir Oil System,” Sot. Pet. Eng. J. (Feb. 1978) 20-26. Orr, F.M. and Silva, M.K.: “Equilibrium Phase Compositions of CO 2 /Hydrocarbon Mixtures-Part 1: Measurement by a Continuous Multiple-Contact Experiment,” Sot. Per. Eng. J. (April 1983) 272-80. Orr, F.M., Silva, M.K., and Lien, C.: “Equilibrium Phase Compositions of CO2iCrude Oil Mixtures-Part 2: Comparison of Continuous Multiple-Contact and Slim-Tube Displacement Tests,” Sot. Pet. Eng. J. (April 1983) 281-91. Katz, D.L. and Firoozabadi, A.. “Predicting Phase Behavior of Condensate/Crude-Oil Systems Using Methane Interaction Coefficients,” J. Pet. Tech. (Nov. 1978) 1649-55; Trans., AIME, 265. Yarborough, L.: “Application of a Generalized Equation of State to Petroleum Reservoir Fluids,” Equations of St&e in Engineering, Advances in Chemisrgv Series, K.C. Chao and R.L. Robnson (eds.), American Chemical Society, Washington, D.C. (1979). 182, 385-435. Whitson, C.H. and Tarp, S.B.: “Evaluating Constant-Volume Depletion Data,” J. Per. Tech. (March 1983) 610-20. Coats, K.H. and Smart. G.T.: “Application of a Regression-Based EOS PVT Program to Laboratory Data,” paper SPE 11197, presented at the 1982 SPE Annual Technical Conference and EXhibition, New Orleans, Sept. 26-29. Coats, K.H., Dempsey, J.R., and Henderson, J.H.: “A New Technique for Determining Reservoir Description from Field Performance Data,” Sot. Pet. Eng. J. (March 1970) 66-74; Trans., AIME, 249. Thomas, L.K. and Hellurns, L.J.: “A Nonlinear Automatic History Matching Technique for Reservoir Simulation Models,” Sot. Pet. Eng. J. (Dec. 1972) 508-14; Trans.. AIME, 253. Wasserman, M.L., Emanuel, A.S., and Seinfeld, J.H.: “Practical Application of Optimal-Control Theory to History-Matching
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Multiphase Simulator Models,” Sot. Pet. Eng. J. (Aug. 1975) 347-55; Trans., AIME, 259. 89. Bobcrg, T.C., etal.: “Application of Inverse Simulation to a Complex Multireservoir System,” J. Pet. Tech. (July 1974) 801-08; Trans., AIME, 257. 90. Watson, A.T., et al. : “History Matching Two-Phase Petroleum Reservoirs,” Sot. Per. Eng. J. (Dec. 1980) 521-32. 91. Blair, P.M. and Peaceman, D.W.: “An Experimental Verification of a Two-Dimensional Technique for Computing Performance of Gas-Drive Reservoirs,” Sot. Pet. Eng. J. (March 1963) 19-27; Trans., AIME, 228. 92. Ridings, R.L., et al. : “Experimental and Calculated Behavior of Dissolved-Gas-Drive Systems,” Sot. Pet. Eng. J. (March 1963) 41-48; Trans., AIME, 228. 93. Mungan, N.: “A Theoretical and Experimental Coning Study,” Sot. Pet. Eng. J. (June 1975) 247-54: Trans., AIME, 259. 94. Kazemi, H. and Merrill, L.S.: “Numerical Simulation of Water Imbibition in Fractured Cores,” Sot. Per. Eng. J. (June 1979) 175-82. 95. Lantz, R.B.: “Quantitative Evaluation of Numerical Diffusion (Truncation Error),” Sm. Pet. Eng. J. (Sept. 1971) 315-20: Trans., AJME. 251. 96. Van-Quy, N., Simandoux, P., and Corteville. I.: “A Numerical Study of Diphasic Multicomponent Flow,” Sot. Pet. Eflg. J. (April 1972) 171-84; Trans., AIME, 253. 97. Fussell, D.D., Shelton, J.L., and Griffith, J.D. : “Effect of ‘Rich’ Gas Composition on Multiple-Contact Miscible DisplacementA Cell-to-Cell Flash Model Study,” Sot. Per. Eng. J. (Dec. 1976) 310-16; Trans., AIME, 261. 98. Harpole, K.J. and Heam, C.L.: “The Role of Numerical Simulation in Reservoir Management of a West Texas Carbonate Reservoir,” froc., Intl. Exhibition and Technical Symposium. Beijing (1982) 759-76. 99. Heinemann, Z.E., et al.: “Using Local Grid Refinement in a Multiple-Application Reservoir Simulator,” Proc., SPE Symposium on Reservoir Simulation, San Francisco (1983) 205-18. 100. Ewing, R.E., Russell, T.F., and Wheeler, M.F.: “Simulation of Miscible Displacement Using Mixed Methods and a Modified Proc., SPE Symposium on ReserMethod of Characteristics,” voir Simulation, San Francisco (1983) 71-82. 101. Carr, A.H. and Christie, M.A.: “Controlling Numerical Diffusion in Reservoir Simulation Using Flux-Corrected Transport.” Proc., SPE Symposium on Reservoir Simulation, San Francisco (1983) 25-32. 102. Todd, M.R., O’Dell, P.M., and Hirasaki, G.J.: “Methods for Increased Accuracy in Numerical Reservoir Simulators,” Sot. Pet. Eng. J. (Dec. 1972) 515-30; Trans.. AIME, 253. 103. Coats, K.H., et al.: “Three-Dimensional Simulation of Steamflooding,” Sot. Pet. Eng. J. (Dec. 1974) 573-92; Trans., AIME, 257. 104 Yanosik, J.L. and McCracken, T.A.: “A Nine-Point, FiniteDifference Reservoir Simulator for Realistic Prediction of Adverse Mobility Ratio Displacements,” Sot. Pet. Eng. J. (Aug. 1979) 253-62; Trans., AIME, 267. 105. Abou-Kassem, J.H. and Aziz. K.: “Grid Orientation During Steam Displacement,” paper SPE 10497 presented at the 1982 SPE Symposium on Reservoir Simulation, New Orleans, Feb. 1-3. 106 Holloway, C.C., Thomas, L.K., and Pierson, R.G.: “Reduction of Grid Orientation Effects in Reservoir Simulation,” paper SPE 5522 presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 28-Oct. 1. 107. Robertson, G.E. and Woo, P.T.: “Grid-Orientation Effects and the Use of Orthogonal Curvilinear Coordinates tn Reservon Simulation,” Sot. Pet. Eng. J. (Feb. 1978) 13-19. 108. Vinsome, P.K.W. and Au, A.D.K.: “One Approach to the Grid Orientation Problem in Reservoir Simulation,” paper SPE 8247 presented at the 1979 SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 23-26. 109. Coats, K.H. and Ramesh, A.B.: “Effects of Grid Type and Difference Scheme on Pattern Steamflood Simulation Results,” paper SPE 11079 presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 26-29. 110. Bet-tiger, W.I. and Padmanabhan. L.: “Finite-Difference Sohtions to Grid Orientation Problems Using IMPES,” paper SPE 12250 presented at the 1983 SPE Symposium on Reservoir Simulation, San Francisco, Nov. 16-18. 111. Shah, P.C.: “A Nine-Point Finite Difference Gperator for Reduction of the Grid Orientation Effect,” paper SPE 12251 presented
48-20
at the 1983 SPE Symposium on Reservoir Simulation, San Francisco, Nov. 16-18. 112. Coats, K.H. and Modine, A.D.: “A Consistent Method for Calculating Transmissibilities in Nine-Point Difference Equations,” paper SPE 12248 presented at the 1983 SPE Symposium on Reservoir Simulation, San Francisco, Nov. 16-18. 113. Frauenthal, J.C., Towler. B.F., and diFranco, R.: “Reduction of Grid-Orientation Effects in Reservoir Simulation By Generalized Upstream Weighting,” paper SPE 11593 presented at the 1983 SPE Symposium on Reservoir Simulation, San Francisco, Nov. 16-18. 114. Pruess, K. and Bodvarsson, G.S.: “A Seven-Point FiniteDifference Method for Improved Grid Orientation Performance in Pattern Steamfloods,” paper SPE 12252 presented at the 1983 SPE Symposium on Reservoir Simulation, San Francisco, Nov. 16-18. 115. Emmanuel, A.S. and Cook, G.W.: “Pseudo-Relative Permeability for Well Modeling,” Sm. Pet.Eng. J. (Feb. 1974) 7-9. 116. Chappelear, J.E. and Hirasaki, G.J.: “A Model of Oil-Water Coning for Two-Dimensional, Area1 Reservoir Simulation,” Sot. Per. Eng. J. (April 1976) 65-72; Trans., AIME, 261. 117. Woods, E.G. and Khurana, A.K.: “Pseudofunctions for Water Coning in a Three-Dimensional Reservoir Simulator,” Sot. Pet. Enn. J. (Aun. 1977) 251-62. 118. Ad>on, D.V.: “An Approach to Gas-Coning Correlations for a Large Grid Cell Reservoir Simulator,” J. Pet. Tech. (Nov. 1981) 2267-74. 119. Akbar, A.M., Arnold, M.D., and Harvey, A.H.: “Numerical Simulation of Individual Wells in a Field Simulation Model,” Sot. Pet. Eng. J. (Aug. 1974) 315-20. 120. Mrosovsky. I. and Ridings, R.L.: “Two-Dimensional Radial Treatment of Wells Within a Three-Dimensional Reservoir Model,” Sot. Pet. Eng J. (April 1974) 127-31. 121. Blair, P.M. and Weinaug, C.F.: “Solution of Two-Phase Flow Problems Using lmphcit Difference Equations,” Sot. Per. Eng. J. (Dec. 1969) 417-24; Trans., AIME, 246. 122. Bansal, P.P. et a[.: “A Strongly Coupled, Fully Implicit. ThreeDimensional, Three-Phase Reservoir Simulator,” paper SPE 8329 presented at the 1979 SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 23-26. 123. MacDonald, R.C. and Coats, K.H.: “Methods for Numerical Simulation of Water and Gas Coning,” Ser. Pet. Eng. J. (Dec. 1970) 425-36; Trans., AIME, 249. 124. Spillette. A.G.. Hill&ad. J.G., and Stone, H.L.: “A High-Stabilitv Sequential-Solution Approach to Reservoir Simulation,“-paper SPE 4542 presented at the SPE 1973 Annual Meeting, Las Vegas, Sept. 30-Oct. 3. 125. Coats, K.H.: “A Highly Implicit Steamflood Model,” Sot. Pet. Eng. J. (Oct. 1978) 369-83. 126. Meijerink, J.A.: “A New Stabilized Method for Use in IMPESType Numerical Reservoir Simulators,” paper SPE 5247 presented at the 1974 SPE Annual Meeting, Houston, Oct. 6-9. 127. Thomas, G.W. and Thumau, D.H.: “Reservoir Simulation Using an Adaptive implicit Method,” Sot. Pet. Eng. J. (Oct. 1983) 759-68. 128. Trimble, R.H. and McDonald, A.E.: “A Strongly Coupled, Fully implicit, Three-Dimensional, Three-Phase Well Coning Model,” Sot. Pet. Eng. J. (Aug. 1981) 454-58. 129. Breitenbach, E.A., Thurnau, D.H., and Van Poollen, H.K.: “Solution of the Immiscible Fluid Flow Simulation Equations,” Sot. Per. Eng. J. (June 1969) 155-69. 130. Price H.S. and Coats, K.H.: “Direct Methods in Reservoir Simulation,” Sot. Pet. Eng. J. (June 1974) 295-308; Trans., AIME, 257. 13 I, Woo, P.T., Roberts, S.J., and Gustavson, F.G.: ‘‘Apphcation of Sparse Matrix Techniques in Reservoir Simulation,” Sparse Matrix Computations, J.R Bunch and D.E. Rose (eds.), Academic Press Inc.; Washington, D.C. (1976) 427-38. 132. Young, D.M.: “The Numerical Solution of Elliptic and Parabolic Partial Differential Equations,” Survey ofNumerical Analysis, J. Todd (ed.), McGraw-Hill Book Co. Inc., New York City (1963) 380-438. 133. Young, D.M : Iterative Solution of Large Linear Systems. Academic Press Inc., Washington, D.C. (1971). 134. Varga, R.S.: Matrix I&rat& Analy‘sis, Prentice-Hall, Inc., Englewood Cliffs, N.J. (1962) 322.
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135. Watts, J.W : “An Iterative Matrix Solution Method Suitable for Anisotropic Problems,” Sot. Per. Eng. J. (March 1971) 47-5 I; Trans., AIME, 251. 136. Settari, A. and Aziz, K.: “A Generalization of the Additive Correction Methods for the lterative Solution of Matrix Equations,” Sm. Ind. Appl. Math. J. Number Analysis (1973) 10, 506-21. 137. Peaceman, D.W. and Rachford, H.H.: “The Numerical Solution of Parabolic and Elliptic Differential Equations,” Sot. Ind. Appi. Math. J. (1955) 3, 28-41. 138. Douglas, J. and Rachford, H.H.: “On the Numerical Solution of Heat Conduction Problems in Two and Three Space Variables,” Trans., American Math. Sot. (1956) 82, 421-39. 139. Stone, H.L.: “Iterative Solution of lmpliclt Approximation of Multidimensional Partial Differential Equations,” Sot. Ind. Appl. Math. J. Number Analysis (1968) 5, 530-58. 140. Weinstein, H.G.. Stone, H.L., and Kwan. T.V.: “Iterative Procedure for Solution of Systems of Parabolic and Elliptic Equations in Three Dimensions,” IEC Fundamentals (1969) 8, 281-87. 141. Watts, J.W. III: “A Conjugate Gradient-Truncated Direct Method for the Iterative Solution of the Reservoir Simulation Pressure Equation,” Sot. Per. Eng. J. (June 1981) 345-53. 142. Hestenes, M.R. and Stiefel, E.: “Methods of Conjugate Gradients for Solving Linear Systems,” J. of Research (1952) 49, 509-36. 143. Concus, P. and Golub, G.H.: “A Generalized Conjugate Gradient Method for Nonsymmetric Systems of Linear Equations,” Report STAN-CS-76-535, Stanford U.. Stanford, CA (Jan. 1976). 144. Vinsome, P.K.W.: “Orthomin, an Iterative Method for Solving Sparse Banded Sets of Simultaneous Linear Equations.” paper SPE 5729 presented at the 1976 SPE Symposium on Numerical Simulation of Reservoir Performance, Los Angeles, Feb. 19-20. 145. Meijerink, J.A. and Van Der Worst, H.A.: “An Iterative Solution Method for Linear Systems of Which the Coefficient Matrix is a Symmetric M-Matrix,” Math. of Camp. (Jan. 1977) 148-62. 146. Kershaw, D.S.: “The Incomplete Cholesky-Conjugate Gradient Method for the Iterative Solution of Systems of Linear Equations,” J. Compt. Physics (1978) 26, 43-65. 147. Young, D.M. and Jea. N.C.: “Generalized Conjugate Gradient Acceleration of Nonsymmetric Iterative Methods,” Linear Algebraic Applicarions (1980) 34, 159-94. 148. Tan, T.B.S. and Letkeman, J.P.: “Application of D4 Ordering and Minimization in an Effective Partial Matrix Inverse Iterative Method,” paper SPE 10493 presented at the 1982 SPE Symposium on Reservoir Simulation, New Orleans, Feb. 1-3. 149. Behie, A. and Forsyth, P.A.: “Practical Considerations for Incomplete Factorization Methods in Reservoir Simulation.” paper SPE 12263 presented at the 1983 SPE Symposium on Reservoir Simulation, San Francisco, Nov. 16-18. 150. Wallis, J.R.: “Incomplete Gaussian Elimination as a Preconditioning for Generalized Conjugate Gradient Acceleration,” paper SPE 12265 presented at the 1983 SPE Symposium on Reservoir Simulation, San Francisco, Nov. 16-18. 151. Coats, K.H.: “Reservoir Simulation: A General Model Formulation and Associated Physical/Numerical Sources of Instability,” Bounaivy and Interior Layers-Computational and Asymptotic Methods, J.J. Miller (ed.), Boole Press, Dublin (1980) 62-76. 152. Mrosovsky, I., Wong, J.Y., and Lampe. H.W.: “Construction of a Large Field Simulator on a Vector Computer,” J. Pet. Tech. (Dec. 1980) 2253-64. 153. Woo, P.T.: “Application of Array Processor to Sparse Elimination,” Proc., paper SPE 7674 presented at the 1979 SPE Symposium on Reservoir Simulation, Denver, Jan. 31-Feb. 2. 154. Nolen, J.S., Kuba, D.W., and Kasic, M.J. Jr.: “Application of Vector Processors to Solve Finite Difference Equations,” Sot. Pet. Eng. J. (Aug. 1981) 447-53. 155. Calahan, D.A.: “Performance of Linear Algebra Codes on the CRAY-I,” Sot. Pet. Eng. J. (Oct. 1981) 558-64. 156. Killough, J.E. and Levesque, J.M.: “Reservoir Simulation and the In-House Vector Processor: Experience for the First Year,” paper SPE 10521 presented at the 1982 SPE Symposium on Reservoir Simulation, New Orleans, Feb. 1-3.
General Reference Mattox. C.C. and Dalton, R.L.: Rescwoir Simtdariort. Monograph Series. SPE, Dallas: to be published in 1986.
Chapter 49
Electrical Logging M.P. Tixier, Consulting Engineer *
Fundamentals spectrometry) surveys, acoustic surveys, wireline formaWell logging is an operation involving a continuous tion tester, etc.]. recording of depth vs. some characteristic datum of the As explained later, several types of resistivityformations penetrated by a borehole. The record is called a log. In addition, a magnetic tape is usually made. measuring systems are used that have been designed to obtain the greatest possible information under diverse Many types of well logs are recorded by appropriate conventional devices (normals and conditions-e.g., downhole instruments called sondes, lowered into the laterals), induction log (IL), Laterolog” (LL), wellbore on the end of a cable. The winch of the logging microresistivity devices, and electromagnetic propagacable is generally brought to the well on a special logtion logs. Table 49.1 gives the service company ging truck (Fig. 49. l), which also carries the recorders, nomenclature for various logging tools. power sources, and auxiliary equipment. The parameters The typical appearance of a standard electrical log is being logged are measured in situ as the sonde is moved illustrated in Fig. 49.2. The left track of the log contains along the borehole. The resulting signals from the sonde the SP curve. The middle track contains a l&in. short are transmitted through electrical conductors in the cable normal (shallow-investigation resistivity curve), recordto the surface, where the continuous recording, or log, is ed on both regular and amplified sensitivity scales as made. Electrical logging is an important branch of well logsolid curves, and a 64-in. normal (medium-investigation ging. Essentially, it is the recording, inuncased sections resistivity curve, dashed curve). The right track contains an 1%ft 8-in. lateral (deep-investigation curve). ofa borehole,of the resistivities (or their reciprocals, the Logs recorded with other combinations of resistivityconductivities) of the subsurface formations, generally along with the sponfaneous potentials (SP) generated in measuring devices have a similar general appearance, the borehole. although the corresponding devices differ in principle and performance. Microresistivity logs generally include Electrical logging has been accepted as one of the most efficient tools in oil and gas exploration and production. a microcaliper curve (hole-diameter recording), which is When a hole has been drilled, or at intervals during the useful in the location of permeable zones. Of late, fourdrilling, an electrical survey is run to obtain quickly and logarithmic tracks are often replacing the two-arithmetic economically a complete record of the formations track mentioned previously. penetrated. This recording is of immediate value for The curves are recorded on the most appropriate of geological correlation of the strata and detection and several available sensitivity scales. The usual depths of evaluation of possibly productive horizons. The informascales are 2 in. = 100 ft (regular) and 5 in.=100 ft tion derived from the electrical logs may at the same time (detail). Less frequently a scale of 1 in. = 100 ft is used. be supplemented by sidewall samples of the formations For cases where great detail is involved, as in micrologtaken from the wall of the hole or by still other types of ging and dipmeter logging, special expanded scales are borehole investigations that can be performed by using available. In many parts of the world, metric depth additional wireline equipment available for use with the scales are used instead of English scales. logging truck [deviation surveys, caliper (hole-diameter) surveys, dipmeter surveys, temperature surveys, Earth Resistivities radioactivity (gamma ray, density, neutron, and nuclear Formation resistivities are important clues to probable ‘Authors of rhe orlglnal chapler on this top!c in the 1962 edltion included fhts author. Ii G Doll, M. MarIm. and F Segesman.
lithology and fluid content. With a few exceptions that are rare in oilfield practice, such as metallic sulfides and
PETROLEUM
49-2
HANDBOOK
graphite, dry rocks are very good insulators but, when their pores are impregnated with water, they conduct electric current. Subsurface formations in general have finite measurable resistivities because of the water contained in their pores or adsorbed on their interstitial clay. Formation resistivity also depends on the shape and the interconnection of the pore spaces occupied by the water. These depend on the formation lithology and, in the case of reservoir rocks, on the presence of nonconductive oil or gas.
CABLE TENSION MEASUREMENT
CONTROL
Units of Resistivity and Conductivity. In electrical logging, the resistivity is usually measured. An exception is induction logging, in which the conductivity is recorded along with its reciprocal, the resistivity. Measurements made with electromagnetic propagation are discussed later. The resistivity (specific resistance) of a substance to the flow of electrical current, at any given temperature, is the resistance measured between opposite faces of a unit cube of that substance. In electrical-logging work,
Fig. 49-l-Setup for wireline logging operations in wells (schematic).
TABLE 49.1-SERVICE
COMPANY NOMENCLATURE Welex
Dresser Atlas
Gearhart
Schlumberger
ENGINEERING
Electrical Log
Electrical Lag
Electrolog
Electric Log
Induction Electric Log (IEL)
Induction Electric Log
Induction Electrolog
Induction Electric Log
Induction Spherically Focused Log (ISF) Dual Induction Spherically Focused Log
Dual Induction-Laterolog
Dual Induction Focused Log
Dual Induction Log
Laterolog.3 (LL3)
Laterolog-3
Focused Log
Guard Log
Dual Laterolog
Dual Laterolog
Dual Laterolog
Dual Guardlog
Microlog (ML)
Micro Electrrc Log
Minilog
Contact Log
Microlaterolog (MLL)
Microlaterolog
Microlaterolog
F,R,,
Microspherically
Log
Proximity Log
Proximity Log (PL) Focused Log (MSFL)
Borehole Compensated Sonic Log
Sorehole Compensated Sonic Log
Sorehole Compensated Sonic Log
Acoustic Velocrty Log
Long Spacing BHC Acoustilog
Long Spaced Sonic Log
Microseismogram
Cement Bond/Variable Density Log
Sonic Cement Bond System
Acoustic Cement Bond Log
Gamma Ray Neutron
Gamma Ray Neutron
Gamma Ray Neutron
Gamma Ray Neutron
Sidewall Neutron Porosity Log
Sidewall Neutron Porosity Log
Sidewall Epithermal Neutron Log
Srdewall Neutron Log
Compensated Neutron Log (CNL)
Compensated Neutron Log
Compensated Neutron Log
Dual Spaced Neutron Log
Neutron Lrfetime Log
Thermal Neutron Decay Time Log
Dual Detector Neutron
Dual Spacing TDT Compensated Formation Density Log
Compensated Density Log
Compensated Densilog
Density Log
Four Electrode Dipmeter
Diplog
Diplog
Formation Tester
Formation Tester
Litho-Density Log High Resolution Dipmeter Formation Interval Tester Repeat Formation Tester
Selective Formation Tester
Formation Multi Tester
Sidewall Sampler
Sidewall Core Gun
Corgun
Sidewall Coring
X-Y Caliber
Caliper Log
Caliper Log
Electromagnetic
Propagation Log
Bore Hole Geometry Tool Ultra Long Spacing Electric Log Natural Gamma Ray Spectrometry
Spectralog
General Spectroscopy Tool
Carbon/Oxygen
Well Seismic Tool Fracture Identification
Log
Fracture Detection Log
Log
49-3
ELECTRICAL LOGGING
the meter was chosen as the unit of length; so the unit of resistivity is taken as the (Q.m)‘/m, or more simply, the ohm-meter, 52.m. Since conductivity is the reciprocal of resistivity (C=lIR), a possible unit of conductivity would be l/(Q.m), or G/m. However, since this unit would necessitate extensive use of decimal fractions, a unit one-thousandth as large, the millimho/meter (mu/m), is employed. Thus, formations having resistivities of 10, 100, or 1,000 Q*rn have conductivities of 100, 10, or 1 mu/m, respectively.
Dependence of Water Resistivity on Salinity and Temperature. The resistivity of an electrolytic solution decreases as the amount of chemicals therein increases. At any given temperature the electrical conductivity of a formation water or a drilling mud will depend on the concentration and nature of the dissolved chemicals. In most cases the predominant solute is sodium chloride (NaCl); therefore, the NaCl conversion chart (Fig. 49.3) may generally be used to obtain resistivity from concentration. If other chemicals are present in relatively large amounts, it is possible to convert the concentrations of such chemicals into equivalent concentrations of NaCl to find the resistivity. To make the conversion, apply the appropriate multipliers given in Table 49.2 for the concentration of each separate ion [in parts per million (ppm) or (m 3/m 3 ) by weight, or in grains per gallon (gr/gal) or (kg/m’)], and add the products. ’ Note that concentrations expressed in milligrams per liter (mg/L) and in ppm may be appreciably different at high concentrations. Below about 50,000 ppm, however, measurements at room temperature in the two units may be used interchangeably without serious error.
tt
Fig. 49.2-Typical
f
t
electrical log.
CONCENTRATION G/G-
RESISTIVITY
Fig. 49.3~Resistivity
OF
SOLUTION
LATERAL
OHM-METERS
vs. concentration for NaCl solutions at various temperatures.
PETROLEUM ENGINEERING
49-4
The resistivity of an electrolytic solution decreases as its temperature increases. This is of great importance, since temperature in the earth increases with depth. Before the resistivity of the drilling mud (measured at surface temperature) can be compared with that of a formation (measured at a much higher temperature in a deep well) the resistivities must be converted to values that would have been observed at a common temperature. The temperature conversion is accomplished by means of Fig. 49.3, which shows for NaCl solutions the effects of both salinity and temperature on resistivity . Downhole temperatures may be estimated from a so-called “bottomhole temperature” (BHT) obtained by means of a maximum-reading thermometer inserted in the body of the sonde. Resistivities of Formation Waters. Formation waters can vary remarkably with geographic location, depth, and geological age. Shallow groundwaters are usually fresh (not saline), with resistivities sometimes exceeding 20 to 50 !l. m at room temperature. They also may contain appreciable amounts of calcium and magnesium salts, which make them “hard.” At great depths, formation waters generally tend to be more saline. In deep wells, formation-water resistivities sometimes may correspond to complete saturation (0.014 O.rn at 200°F). A knowledge of R,., the formation-water resistivity. is important in electrical-log interpretation. R,,may be obtained from the readings of the SP curve (Eq. 9) or from resistivity measurements on samples of formation water recovered from production or in drillstem tests. It also may be estimated from measurements of the resistivity of the permeable formations of interest when they are 100% water-saturated, Ro,if the porosity or formation factor is known (Eqs. 1 and 2). R, may be computed, as has been explained, from analyses of formation waters. Resistivity of formation waters is discussed further in Chap. 24. Mud, Mudcake, and Mud-Filtrate Resistivities. Resistivities of the mud, R,, the mudcake, R,,, and the are all important in log interpretation. mud filtrate, R,,,f, R, is obtained by direct measurement on a mud sample. R,,,f and R, are obtained by direct measurements on filtrate and mudcakes pressed from a sample of the mud, or they can be estimated from average statistical data on the basis of mud resistivity. 2-4 Correction for the variation of these resistivities with temperature is made by use of Fig. 49.3. Formation Resistivity Factor. If R. is the resistivity of a clean (nonshaly) formation completely saturated with water of resistivity R,, the ratio Ro/R, will be a constant that depends on the lithologic structure of the for-
TABLE 49.2-CONVERSIONS
FOR CATIONS AND ANIONS Anions
Cations Na Ca WI
1.0 0.95 2.0
Cl so4 co3 HCO,
1.0 0.5 1.26 0.27
HANDBOOK
mation and not on the resistivity, R,, of the saturating water. This constant is the formation resistivity factor, FR,commonly called “formation factor. ”
Ro FR=- R,
.... .... .... ...
.(I)
Dependence of Formation Factor on Porosity and Lithology. The formation factor, F, , of a clean formation can be related to its porosity, 6. by an empirical formula of the form F~=alc$'?', where a and m are constants. The exponent m, sometimes called the cementation exponent or factor, varies with the lithology. In the construction of many graphs for log interpretation, 2 the “Humble formula” proposed by Winsauer et a1.5 has been generally adopted:
0.62 FR= ~2.,5. .... .... .... ....I...
(2)
An early formula proposed by Archie, which fits particularly well for consolidated formations such as hard sandstones and limestones, is
FR=L. ................................(3) 4J2 Limestones often contain vugs, interconnected with fissures, which add their porosity to that of the matrix. When the vugs and fissures are spaced closely, compared with the spacings of the resistivity-measuring devices, Eq. 3 often can be used as in the case of sandstones or limestones with only granular porosity. Nevertheless, it is sometimes advisable to use values of m greater than two as required to fit local observations. Shaly (Dirty) Formations. Shales and clays are themselves porous and are generally impregnated with mineralized water. Therefore, they have appreciable conductivity, which is enhanced by ion-exchange conduction through the shale matrix. (This shale conduction is sometimes, though not quite properly, referred to as resulting from “conductive solids. “) On the other hand, the size of the shale pores is so small that practically no movement of fluid is possible. Accordingly, shale, whether deposited in thin laminations or dispersed in the interstices of the sand, contributes to the conductivity of the formation without contributing to its effective porosity. The relation between formation resistivity and porosity becomes more complex for shaly formations than for clean formations. Because of the additional shale conductance, the ratio of formation resistivity to water resistivity (i.e., the formation factor) is not constant when the resistivity of the impregnating water changes. 6 Nevertheless, if the shale content is not too great, experimental observations show that for low enough values of water resistivity this ratio is almost constant, as though the conductance of the shale were then negligible in comparison with that of the water; and a limiting formation factor is found, which is related approximately to the effective porosity in the same way as the formation factor of a clean sand.
49-5
ELECTRICAL LOGGING
Relation Between Formation Resistivity and Saturation. When a part of the pore space is occupied by an insulating material such as oil or gas, the resistivity of the rock, R,,is greater than the resistivity that it has when 100% water-bearing, R,. The resistivity of such rock is a function of the fraction of the PV occupied by water. For substantially clean formations, the water saturation, S,, is related to R, (resistivity of formation containing hydrocarbons and formation water, with a water saturation S,) and R,J (resistivity of same formation when 100% saturated with the same water) b an empirical relation known as the Archie equation. 7
l/II
. .... ..........
.. ...(4)
Empirically determined values of n range between 1.7 and 2.2, depending on the type of formation. Experience shows that n =2 should give a sufficiently good approximation. Then, combining Eqs. 4 and 1 gives
SW=(+)1/i =(F)
I/?............
The ratio RJR0 is sometimes designated as the resistivity index, 1~; accordingly, S, =(ZR) -I”. The relation between formation resistivity and water saturation is more complex when the formations contain some shale or clay because of the additional conductance resulting from the interstitial shale. sv9 Ranges of Resistivity-Formation Classifications. Clays and shales are porous, practically impervious formations and are often very uniform throughout their mass. Their resistivity is comparatively low and practically constant over wide intervals. Compact and impervious rocks, such as gypsum, anhydrite, dense calcareous formations, or certain kinds of coal, are highly resistive because of their very small interstitial water content. Resistivities of porous and permeable formations, such as sands, vary widely, depending on their lithology and fluid content. In electrical logging it is convenient to classify reservoir rocks as follows. SoftForma&ions. These formations are chiefly poorly consolidated sand/shale series. The porosity of the sands is intergranular and exceeds 20%. Resistivities range from 0.3 !2*m for saltwater-bearing sands to several fl. m for oil-saturated sands. Intermediate Formations. These are chiefly moderately consolidated sandstones but frequently limestones and/or dolomites. Reservoir porosity is generally intergranular, ranging from about 15 to 20 % . The reservoir formations are interbedded with shales and very often with tight rocks. Resistivities range from 1 to about 100 Q-m. Hard Formations. These are chiefly limestones andior dolomites, and also consolidated sandstones. They consist mostly of tight rocks containing porous and permeable zones, and shale streaks. The porosity of reservoirs is less than 15 % . Most often, the porous and
permeable zones contain fissures and vugs. Resistivity range is from 2 to 3 Q. m to several hundred. For the completely tight formations, such as salt and anhydrite, the resistivity may be practically infinite. Anisotropy. In many sedimentary strata, the mineral grains have a flat or plate-like shape with an orientation parallel to the sedimentation. Current travels with great facility along the water-filled interstices, which are mostly parallel to the stratification. These strata, therefore, do not possess the same resistivity in all directions. Such microscopic anisotropy is observed mostly in shales. Moreover, in electrical logging, the distance between electrodes or coils on the measuring devices is great enough that the volume of formation involved in the measurements very often includes sequences of interbedded resistive and conductive streaks. Since current flows more easily along the beds than perpendicular to them, anisotropy. the formation has macroscopic Both kinds of anisotropy may add their respective effects to influence the apparent resistivity. The longitudinal, or horizontal, resistivity , RH, measured along the bedding planes is always less than the transversal, or vertical (perpendicular) resistivity, Rv. Resistivity-measuring devices whose readings are not appreciably affected by the borehole [the deep induction log (IM), and under certain conditions, the laterolog (LL), and the long lateral when the ratio RHIR, is low or moderate] will read RH. Because of the borehole effect, the short-spacing-electrode devices usually read values greater than RH. lo Distribution of Fluids and Resistivities in Permeable Formations Invaded by Mud Filtrate. Inasmuch as the hydrostatic pressure of the mud is usually maintained greater than the natural pressure of the formations, mud filtrate (forced into the permeable beds) displaces the original formation fluids in the region close to the borehole. Solid materials from the mud deposited on the wall of the hole form a mudcake, which tends to impede and reduce further infiltration. The thickness and the nature of the mudcake depend on the kind of mud and on the drilling conditions rather than on the formations. The thickness, h,,,,, is usually between ‘/s and 1 in. For water-based muds the mudcake resistivity, R,,,is about equal to one or two times the mud resistivity, R,. In some oil-emulsion muds, R,, may be somewhat greater. Fig. 49.4a represents a schematic cross section of an oil-bearing permeable bed penetrated by a borehole. Fig. 49.4b and 49.4~ show the corresponding radial distribution of fluids in formation and resistivities. As indicated in Fig. 49.4a, the zones of different resistivity may be divided into the drilling mud within the borehole (of resistivity R,);the mudcake R,,,the flushed zone R,,;a transition zone; in some cases an “annulus.” R, (present only in certain oil- or gasbearing formations); and the uncontaminated zone (of resistivity R,). The invaded zone (of “average” resistivity, Ri)includes the flushed zone and the transition zone. Invaded Zone. This zone is behind and close to the wall of the hole; it is believed that most of the original interstitial fluids have been flushed out by the mud
PETROLEUM ENGINEERING
49-6
rANNULU5
(Ran)
MUD CAKE
t
Fig. 49.4-a.
k--HOLE
(Rnxl
WALL
Horizontal section through a permeable oil-bearing bed (S, < 60%); b. radial distribution of fluids in formation (qualitative); c. radial distribution of resistivities.
filtrate. This flushed zone, of resistivity R,,, is considered to extend, under usual conditions of invasion, at least 3 in. from the wall. Exceptions to this rule can occur. If the bed is water bearing, the pores in the flushed zone are completely filled with the mud filtrate, and for clean formations R,,is nearly equal to F,R,f;FR being the formation factor and R mf the mud-filtrate resistivity If the bed is oil bearing, the flushed zone contains some residual oil saturation, S,, . From Eq. 5, S,, , the water saturation in the flushed zone is
% or
FRRtnf ............................ R,,=T, s x0 ‘
where S,=l-S,,. Beyond the region of maximum flushing, R,,, there is a more or less extended transition region, the nature of which depends on the characteristics of the formation, the speed of invasion, and the hydrocarbon content. The invaded zone includes the flushed zone and the part of the transition zone invaded by filtrate. In the case of water-bearing sands and oil-bearing sands of high water saturation, the invaded zone extends up to the uncontaminated zone, R,. There can be no exact definition of the depth of the invaded zone, but it is convenient to introduce a factor di, called the “electrically equivalent diameter of invasion,” corresponding to an average invaded zone of resistivity Ri, which has the same effect as the actual in-
HANDBOOK
vaded zone on measurements made in the borehole. The depth of invasion is variable. It depends on the plastering properties of the mud, pressure differences between the mud column and the formation, time elapsed since the formation was drilled, porosity of the formation, proportion and nature of the fluids (water, oil, gas) present in the pores, reaction of any interstitial clays with the mud filtrate, etc. All other conditions being the same, the greater the porosity, the smaller the depth of invasion. With usual muds, di seldom exceeds 2dh (dh =hole diameter) in high-porosity sands, but it may exceed 5dh and even 1Odh in low-porosity formations such as consolidated sandstones or limestones. In some cases, invasion can be extremely shallow in very permeable formations and in gas-bearing formations. In very permeable beds, when there is an appreciable difference between the specific gravities of the mud filtrate and the salt-laden interstitial water, gravitysegregation effects may occur, with the fresher filtrate tending to accumulate at the top boundary of the bed, resulting in a decrease in the depth of invasion in the lower part of the bed. I’ In fissured formations, the permeability is quite often enormous because of the fissures-much greater than the permeability of the matrix material surrounding them. Suppose that a formation is composed of a porous but relatively impermeable material, broken by networks of roughly parallel fissures. Mud filtrate penetrates the fissures easily and deeply, driving out much of the original fluids (oil and formation water). On the other hand, the matrix itself may be penetrated hardly at all by the filtrate. Since the l%.sures constitute a small part of the total PV, only a vety small portion of the total original fluids is displaced. As a result, R, is little different from R,, and the ratio R,IR,,fis no longer representative of the formation factor. Annulus. When the formation contains hydrocarbons, the process of invasion is complex. The distribution of fluids is then affected by the two-phase permeabilities, relative densities (gravities) and viscosities of the fluids, capillary forces, etc. When the initial water saturation is low (less than about 50%), one important feature is the existence of an annular region just inside the uncontaminated zone, containing mainly formation water and some residual oil. This annulus is explained as follows. The mud filtrate penetrates the formation radially, sweeping the removable oil and formation water ahead of it. For large oil saturation, the relative permeability to oil is appreciably greater than that to water. Therefore, the oil moves faster, leaving a zone (the annulus) enriched in formation water behind it. It seems likely that, because of the effects of diffusion, capillary pressure, gravity, etc., the existence of a welldefined annulus is a transitory phenomenon. Field log experience nevertheless seems to show that the annulus does very often exist at the time the logs are run. Computations have shown that the presence of the annulus has a practically negligible effect on the response of the devices with electrodes (normals, laterals, and laterolog) It may have an effect on the induction log, but this can be taken care of for practical purposes by means of appropriate interpretation charts. 2
ELECTRICAL LOGGING
Uncontaminated
49-7
Zone. For clean formations,
from
Eq.5, R,=
FRR, s,2.
.
.
.
. . . . .
.
. . . I .
.
In the usual case, R,,,f is 10 to 25 times as large as R w. Thus, comparing Eqs. 6 and 7 with usual values of S, and S,, , R,, even in oil-bearing formations, is often less than R,, as represented in Fig. 49.4~. Apparent Resistivity. Since any resistivity measurement is affected in some degree by the resistivities of all the media in the immediate vicinity of the sonde (i.e., mud, different parts of the formation that vary in resistivity, adjacent formations if the bed measured is thin), any given device records an apparent resistivity. Each resistivity device is calibrated so that when the sonde is in a homogeneous medium (or in some other condition appropriate to practice, specified for the particular device) the apparent resistivity reading is equal to the actual resistivity. Requirements for and Types of Resistivity Devices. Inspection of basic relations in Eqs. 1, 2, 5, and 6 shows that a determination of S, and 4 requires a knowledge of R, and R,, (or R i, in certain cases where R,, is not easily determined). Thus, for the reservoir-evaluation problem, it is necessary to have resistivity-measuring devices with different depths of investigation to obtain values indicative of the resistivities of the invaded zone and the uncontaminated zone. The readings of the deep- and shallow-investigation curves may often be used to correct each other, through correction charts or departure curves, to obtain better values of R, and Ri Another function of resistivity recording is to provide an accurate definition of bed boundaries, particularly of permeable beds. Finally, it is desirable that the readings not be influenced by the effect of the mud column or, in case of thin beds, by the adjacent formations. These requirements are only partly satisfied with the “conventional” resistivity devices. The introduction of microdevices and focused devices has brought about an appreciable improvement. Currently used resistivity devices may be classified in two categories. 1. Macrodevices, which derive their reading from about 10 to 100 cu ft of material around the sonde (useful for R, and Ri evaluation), and include unfocusedelectrode devices, focused-electrode devices, and induction logging devices. 2. Microdevices (also called wall-resistivity devices), which derive their readings from a few cubic inches of material behind or close to the wall of the hole. Since the electrodes are mounted on an insulating rubber pad pressed against the wall of the hole, measurements are affected only marginally by the mud column. Microdevices arc of unfocused and focused types. Resistivity devices that have electrodes may be used in holes filled with water or water-based drilling mud, which provides the electrical contact necessary between electrodes and formation. The induction log can also be used in empty holes or in holes filled with nonconductive oil-based mud. The various resistivity devices are described later.
Spontaneous Potential (SP) Log The SP log is a record of the naturally occurring potentials in the mud at different depths in a borehole. The measurement is made in uncased holes containing waterbased or oil-emulsion muds between an exploratory electrode on the sonde in the borehole and a stationary reference electrode at the surface. Usually the SP curve (Fig. 49.2) consists of a more or less straight baseline (corresponding to the shales) having excursions or peaks to the left (opposite the permeable strata). The shapes and the amplitudes of the excursions may be different, according to the formations, but there is no definite correspondence between the magnitudes of the excursions and the values of permeability or porosity of the formation. The principal uses of the SP curve are to (1) detect the permeable beds, (2) locate their boundaries (except when the formations are too resistive), (3) correlate such beds, and (4) obtain good values for R,, the formation-water resistivity. Origin of the SP. The character of the potentials measured in the mud results from ohmic drops produced by the flow of SP currents through the mud resistance. If the mud is extremely conductive, these ohmic drops may be insignificant, and the variations in the SP curve may be too small to be useful.* The SP currents flow as a result of electromotive forces (EMF’s) existing within the formations or at the boundaries between formations and mud. One phenomenon that could cause an EMF to appear across the mudcake opposite a permeable bed is electrofiltrahon.The mud filtrate, in being forced through the mudcake, would tend to produce an EMF, positive in the direction of flow. According to experiments, I2 the EMF across the mudcake may be quite sizable, but there is also an electrotiltration EMF generated across the adjacent shales. Thus, the net effect of electrotiltration in causing variations of SP is small and in most cases negligible for all practical purposes-a conclusion verified by field experience.** Most important ate the EMF’s of electrochemical origin, which occur at the contacts between the drilling mud (or its filtrate) and the formation water, in the pores of the permeable beds, and across the adjacent shales. I6 In a clean sand lying between shale beds, all penetrated by a borehole containing conductive (water-based) mud, the total electrochemical EMF, E,, is produced in the chain (Fig. 49.5): Mud/mud filtrate/formation water/ shale/mud. The EMF of the junction, mud/mud filtrate, is taken to be practically nil because, although the resistivities of the mud and its filtrate may differ, their electrochemical activities should be the same. The part of the chain consisting of “formation water/shale/mud” gives rise to the shale-membrane EMF, Em. The part “mud ftltrateiformation water” gives rise to the liquid-junction EMF, EJ. For NaCl (monovalent-ion) solutions, at 75”F,
E,=59log,+ amf *In such acase the gamma ray log. which distinguishesshales from nonshale beds, IS sometimes recorded as a subslltute for the SP “Further information on the electrof~ltralion EMF, or streaming potential, may be found in Refs. 13 through 15.
PETROLEUM ENGINEERING
49-8
HANDBOOK
MUD
I-t Fig. 49.5--Schematic
INVADED ZONE
representation
of
electrochemical chain and SP current path at boundary between permeable bed and adjacent shale.
and
0
where a, and a,f are the chemical activities of the formation water and mud filtrate, respectively (at 75 “F), and EM and EJ are in millivolts. The total E, is the sum of E,+, and E,:
E,=K,
........ ,..........
log,,%
STATIC
SP (mvl
Fig. 49.6--R, determination from the SP. The inset chart of true applies to formation waters of average R, vs. R, composition.
. (8)
Umf where K, is the electrochemical coefficient and is equal to 71 at 75°F. Eq. 8 is general, provided that both formation water and mud filtrate are essentially NaCl solutions of any concentration. The values of K, are directly proportional to the absolute temperature. Thus, at 150°F the coefficient K, in Eq. 8 becomes 81 instead of 71, and at 300°F it becomes 101 (see Fig. 49.6). From Eq. 8, in the usual case of a, greater than a,,f, E, is positive. However, if a,f is greater than a,, corresponding to mud mom saline than formation water, then E, is negative and the SP deflections corresponding to permeable beds are then reversed on the log. Effect of Invasion on Generation of the EMF. In the explanation of the electrochemical potential, it has been assumed that no shale-type potential is created by the mudcake. In the normal case, mud filtrate bathes both sides of the mudcake and no shale-type potential can arise. In some formations, there is only a little filtrate behind the mudcake. Such small amount of filtrate will be contaminated easily by the formation water. In this case, one face of the mudcake is wetted by the filtrate in the hole, the other face by contaminated filtrate of different activity. This will give rise to a shale-type potential of the same polarity as the main shale potential, and the SP curve will be decreased. This explains the decreasing of the SP curve with time in very highly permeable beds. I7 The filtrate is evacuated by gravity
segregating forces and the formation fluids tend to come back toward the hole with time. Conversely, an increase in SP with time is observed often in low-permeability water-bearing formations. Very little filtrate invades the formation in a freshly drilled hole and the filtrate is contaminated by the forma-. tion water. As the invasion proceeds, more and more filtrate goes into the formation and the mudcake is wetted on both faces by the mud filtrate. When the mudcake does not contribute any shale-type potential, the SP curve, recorded on the front of a thick permeable sand, is said to be fully developed. Effect of Interstitial Shales on the SP. Increasing amounts of shale or clay in a permeable bed effectively result in a reduction of the SP curve. At the limit, for 100% shaliness, E, becomes zero; that is, the “sand” is then all shale and indistinguishable from the surrounding shales. The presence of oil in a shaly sand tends to enhance the effect of the shale. All other conditions being the same, the total E, of a shaly sand will be smaller if oil bearing than if water bearing. The effect of interstitial shale is also greater in lowporosity formations. In these cases, only a small amount of shale reduces the SP deflection appreciably. Conversely, the E, of shaly water-bearing sands of high porosity remains practically equal to the E, of a clean sand, as long as the shale content is reasonably low-i.e., does not exceed a few percent.
ELECTRICAL LOGGING
49-9
Geometric Effect Influencing the SP Curve Circulation of the SP Current, The various EMF’s add their effects to generate the SP currents, which follow the paths represented schematically in Fig. 49.7 (right) by solid lines. Each current line encircles the junction of mud, invaded zone, and uncontaminated zone. In the usual case where the formation waters are saltier than the mud, E, is positive and the current circulates in the direction of the arrows. The potential of a point in the mud column opposite the sand is negative with respect to one opposite the shale. Along its path, the SP current forces its way through a series of resistances, both in the ground and in the mud. Along a closed line of current flow, the total of the ohmic-potential drops is necessarily equal to the algebraic sum of the EMF’s encountered. Moreover, the total potential drop is divided between the different formations and the mud in proportion to the resistance of the path through each respective medium. Static SP (Clean Formations) and Pseudostatic SP (Shaly Formations). It is convenient to use an idealized representation in which the SP current is prevented from flowing by means of insulating plugs placed across hole and invaded zones, as shown in Fig. 49.7a (right). Under these conditions, a plot of the potential in the mud column would appear as the dashed cross-hatched curve on the left of Fig. 49.7a, with a maximum negative deflection opposite the permeable bed equal to the algebraic sum of all the EMF’s of various origins. This is the maximum SP that could be measured. It is therefore convenient to use this theoretical value as a reference. In the case of a clean sand, it is called the static SP, ESp. If the sand is shaly, it is called the pseudostatic SP. Epsp. For given values of the activities of mud and formation water, the pseudostatic SP of a shaly sand is smaller than the static SP of a clean sand. The ratio E,rplEsp is called the reduction factor or ratio and is designated by the symbol (Ysp. The SP log records only that portion of the potential drop occurring in the mud. When the bed is sufficiently thick the amplitude of the SP deflection approaches the static SP (or EpsP in case of shaly formations), hccause then the resistance offered to the current by the bed itself is negligible compared with the resistance of the path through the mud in the borehole. Factors Influencing the Shape and Amplitude of SP Deflections. As seen in Fig. 49.7b, the current circulates in the hole not only opposite the permeable formation but also a short distance beyond its boundaries. As a result, although on the static SP diagram the boundaries of a permeable bed are indicated by sharp breaks, those on the actual SP curve show a more gradual change in potential. An analysis of the circulation of the current” shows that, for uniform resistivity in the formations, the bed boundaries are located at the inflection points on the SP log. This fact provides a means of determining the thickness of a bed from the SP log. Both the shape of the SP deflection and its relative amplitude (in fractional parts of the Essp or EpsP) are influenced by four factors, which determine the conditions for the circulation of SP currents: (1) bed thickness, (2) resistivities of the bed, the adjacent formations, and the
------
STATIC WHEN FROM
SP DIAGRAM--POTENTIAL SP CURRENTS ARE FLOWING.
:SP LOG-POTENTIAL CURRENTS ARE
Fig. 49.7-a.
IN MUD PREVENTED
IN MUD FLOWING.
WHEN
SP
Static SP diagram (left) that would be observed in hole when current IS prevented from flowing by means of insulating plugs (right); b. actual SP diagram (solid curve, left) and schematic representation of SP current distribution in and around permeable bed (right).
mud, (3) borehole diameter, and (4) depth of invasion. All other factors remaining the same, a change of the total EMF’s affects the amplitude but does not modify the general shape of the SP log. Influence of Mud Resistivity and Hole Diameter. The mud resistivity has a predominant influence on the SP curve. If the mud is of about the same degree of salinity as the formation water, electrochemical EMF’s are small. If the mud is more saline than the formation water, the SP may be reversed (sand deflections toward the positive side of the log). Moreover, the lower the mud resistivity (compared with the formation resistivity) the broader the deflection above and below the permeable bed and, because the ohmic drops in the mud are decreased, the smaller the amplitude of the deflection. An increase in hole diameter acts approximately like an increase in the ratio of formation resistivity to mud resistivity. It tends to round off the deflections on the SP log and reduce the amplitude of the deflections opposite thin beds. A decrease in hole diameter has the same effect as a decrease in the ratio of formation resistivity to mud resistivity. The SP log would also be influenced by a lack of homogeneity of the mud-a change in salinity of the mud
PETROLEUM ENGINEERING
49-10
SCHEMATIC REPRESENTATION OF FORMATIONS AND SPLOG (IMPERVIOUS CONDUCTIVE
AND 1
SCHEMATIC DISTRIBUTION OF SP CURRENTS
m
SHALE
COMPARATIVELY
fzl
COMPACT FORMATON (VERY HIGH RESISTIVITY)
m
PERMEABLE (COMPARATIVELY
CONOUCTIVE
1
Fig. 49.8-SP phenomena in highly resistive formations (schematic).
at a certain level would result in an SP baseline shift at that level. However, it has been found in practice that such changes in salinity are rare. Effect of Invasion. Permeable beds in general arc invaded by mud filtrate. Because the boundary between mud filtrate and interstitial water is somewhere inside the formation, a fraction of the SP current flows directly from the shale into the invaded zone, without penetrating the mud column. As a result, the presence of the invaded zone has an effect on the SP log similar to that of an increase in hole diameter. SP in Soft Formations. Theory and field experience have shown that the amplitude of the SP deflection is practically equal to the static SP (of a clean sand) or to the pseudostatic SP (of a shaly sand) when the permeable beds are thick and the resistivities of the formations are not too great compared with that of the mud. Moreover, the SP curves define the boundaries of the bed with great accuracy. The amplitude of the deflection is less than the static SP or pseudostatic SP for thin beds, and the thinner the bed, the smaller the deflection. On the other hand, when the resistivity of the formation, R,, is considerably greater than that of the mud, R,, the SP curves are rounded off, the boundaries are marked less accurately, and all other conditions being the same, the amplitude of the peak is less than when the ratio R,IR, is close to unity. For the case of shaly sands, the SP curve may also be affected by the presence of oil. A change in the magnitude of the SP deflection occurs very often when passing an oil/water contact in a shaly sand. This change is not a positive criterion for the detection of oil because the same effect would be obtained if the salinity of the interstitial water were reduced or if the percentage of shale were increased. SP in Hard Formations. Hard formations are highly resistive except for permeable beds, whether oil- or water-bearing, and shales, which are impervious. The SP currents generated by the different EMF’s flow into the hole out of the shale sections and out of the hole into
HANDBOOK
the permeable sections. In between, they flow through the mud rather than through resistive sections close to the borehole, because of the large resistances the latter paths offer. However, within the formation at a distance from the borehole, where the paths through the resistive beds have larger cross sections and hence lower resistances, the SP currents can complete their circuits from permeable beds to shale. They cannot return to the mud through adjacent permeable beds because there they encounter EMF’s opposing them. Opposite a given resistive bed, the SP current in the mud column remains essentially constant along the borehole. This means that the potential drop per unit length of hole is also constant,-thus giving g constant slope on the SP log as shown by the straight-line portions of the SP in Fig. 49.8. At the level of each conductive bed, some SP current will enter or leave the mud column, thus modifying the slope of the SP log. For instance, the slope of the SP log changes at the level of the permeable bed, P2, because part of the current leaves the hole and flows into the bed. ‘* As a general rule, in hard formations the permeable beds are characterized on the SP log by slope changes or curvatures that are convex toward the negative side of the log. Shales are characterized by curvatures that are convex toward the positive side of the log. Highly resistive beds correspond to essentially straight parts of the SP log. Determination of Static SP (SSP). The SP deflection is measured with respect to the shale baseline, a reference line which can generally be traced along the extreme positive edges of the SP curve. Usually the shale line is straight and vertical. * In any given well, since the mud salinity is constant and the interstitial waters may tend to be constant, there is often a definite tendency for the maximum SP deflections to be the same for the same types of permeable formations at comparable depths. Thus, it is usually possible to draw, parallel to the shale line, a sand line on the log along the maximum negative deflections of the clean sands of sufficient thickness. It is very likely that, for all the beds where the SP peaks reach the sand line, (1) the formation-water resistivity is practically the same, (2) the beds are virtually free from shaly material, and (3) the amplitude of the deflection is equal to the SSP. For thin beds in cases where the SSP cannot be determined as above (or for a thin shaly sand), the SP reading from the log must be corrected by means of appropriate charts in order to obtain the Essp or Epsp. 2 Determination of R, from SSP Since the variations of electrotiltration potential from sand to shale can generally be neglected, the SSP is taken in practice as equal to the corresponding value of -EC as long as the SP is “fully developed.” It is convenient to replace Eq. 8 by R Essp = -Kc log+ R we
...
....... .
. (9)
‘field experience has shown that in certa#n regions there may be shifts of the shale line. Sometimes rhese shifts are found systemattcatty at the ?.ame places in the geologlcal column and can be used as markers.
49-l 1
ELECTRICAL LOGGING
where R, is an equivalent formation-water resistivity . The computation of R, is given in the chart of Fig. 49.6, and R, is derived from R, by means of the auxiliary chart at the lower right of Fig. 49.6. The solid curves on this auxiliary chart correspond to highly saline formation waters, where the presence of salts different from NaCl is negligible in practice. They are derived from the known activity/resistivity relationships for pure NaCl solutions. The dashed curves correspond to formation waters of low salinity, where the presence of other salts (calcium and magnesium chlorides, sulfates, and bicarbonates) have an important bearing on the activity values. These curves are derived from empirical observations and cover formation waters of average composition. I9 Note that, for intermediate salinities (0.08< R, ~0.3 at 75”F), the value of R,, is practically equal to R,. The mud filtrate is taken here as an NaCl solution, and this is generally done in practice, except for muds containing gypsum, CaC12, or NaOH. In such cases, the determination of R, from the SP curve requires the measurement of the activity of the mud. A field instrument is provided for this purpose.
Resistivity Logging Devices* A general classification of the types of rcsistivity logging devices was given previously.
l I
1 2
Bed 3456
.2F-----
Thxkncrr, 6
Feel IO
20
I 1 4050
1
------+
2
3
Electrical Survey (ES). During the first 25 years of logFig. 49.9-Shoulder-bed (bottom). ging practice, the standard ES (Fig. 49.2) usually included, in addition to the SP, three conventional (unfocused) resistivity curves; namely, a short normal curve (distance between electrodes A and M is 16 in.), a long (distance benormal(AM=64 in.) or a shortlateral tween electrodes and A and 0 is 6 to 9 ft), and a standardlateral (AO= 18 ft, 8 in. in general), all recorded simultaneously. In some regions, such as the Permian basin (west Texas and New Mexico), the short-normal spacing was reduced to 10 in., and the limestone sonde was recorded instead of the long normal. The ES log is rarely run today, but it was the standard log for many decades.
4
Bed 56
Thdner!, Feet 6 IO
corrections,
LLS
1 20
(top)
Focused Electrode Devices. In wells drilled with very saline mud, or in high resistivity formations, a laterolog or dual laterolog is used with a gamma ray tool. Fullest benefit of these combinations usually is derived if a microresistivity survey is also run. Microresistivity surveys generally include a microcaliper curve (holediameter recording) (see Figs. 49.9 and 49.10). To avoid multiple runs, many of the above devices are combined with porosity logs-acoustic, density, and neutron logs. These porosity logs are discussed in other chapters. Flg. 49.10-Principle
M
4050
and
LATLROLOG
Induction-Electrical Surveys (IES) (Figs. 49.9 and 49.10). The simultaneous recording of induction (conductivity and resistivity) curves, 16-in. normal, and SP curve, is a good combination for the logging of fonnations of low to moderate resistivities in fresh muds. Of late, the 16-in. normal has been replaced by a focused electrode system, and two induction logs of different investigations may also replace the single induction.
‘See Table 46.6 for the names of the various service companies’ 1ools.
1 30
of Delaware effect.
LLD
PETROLEUM ENGINEERING
49-12
METER
GENERATOR
Conventional
-
A
Fig. 49.11 -Normal device (schematic).
GENERATOR
AMX
METER
GENERATOR
LATERAL (01
METER
BAM
Fig. 49.12-Lateral
LATERAL (b)
device (schematic).
R.0
2
4
6
8
Resistivity Devices
During the first quarter century of well logging, the only electrical surveys available were the conventional resistivity logs plus the SP. Thousands of them were run each year in holes drilled all over the world. Since then, new logging methods have been developed to measure values much closer to R, and R,,which are the values sought. Nevertheless, the conventional ES (consisting of SP, 16-in. normal, 64-m. normal, and 18-ft 8-in. lateral) still is being run in some parts of the world. For this reason, and also because new information can often be obtained by reinterpreting old ES logs, this chapter includes discussion on the principles and responses of the ES measurements.
POINT T--
HANDBOOK
IO
Fig. 49.13-Laboratory curves for normal sonde of spacing AM =2d through uninvaded beds more resistive than adjacent formations.
Principles: Normal and Lateral Devices. In conventional resistivity logging a current of known intensity is sent between two electrodes, A and B (A on the sonde, B on the sonde or at the surface), and the resulting potential difference is measured between other electrodes M and N. The apparent resistivity is proportional to the measured potential difference. For normal devices, the distance AM is small (1 to 6 ft) compared with MN, MB, and BN. In practice N or B may be placed in the hole at a large distance above A and M (Fig. 49.11). The voltage measured is practically the potential of M (because of current from A), referred to an infinitely distant Point. The distance AM of a normal device is its spacing. The point of measurement is midway between A and M. For lateral devices, measuring electrodes M and N are close to each other and located several feet below current electrode A. Current-return electrode B is at a great distance above A or at the surface. The voltage measured is approximately equal to the potential gradient at the point of measurement 0, midway between M and N. The distance A0 is the spacing of the lateral device. The two arrangements shown in Fig. 49.12 (in which current and measuring electrodes are interchanged) are equivalent as regards measured potentials (and resistivities), Curve Shapes-Laboratory Results. Fig. 49.13 shows laboratory curves from a normal device for homogeneous resistive layers between adjacent beds of low resistivity. The curves are symmetrical with respect to the center planes of the layers. The same curves are recorded if M is above A instead of, as in the figure, A above M. The upper part of Fig. 49.13 shows a resistive bed thicker than the spacing (bed thickness, h, is 6dh ; spacing AM is 2dh; where dh is the hole diameter). At the boundaries of the bed the curve tends to be rounded off owing to the influence of the borehole. Moreover, the indicated bed thickness (distance between the inflection points P and P’) is less than the actual thickness. Normal curves tend to show resistive beds thinner than they actually are (and conductive beds thicker than they actually are) by an amount equal to the spacing AM. The error in picking the boundaries of thick resistive beds is small for short-spacing normals, which is one reason for the recording of a short normal. As shown in the lower part of Fig. 49.13, for a resistive layer thinner than the spacing, the curve shows
49-13
ELECTRICAL LOGGING
R.-
01
5
I U-\REFLECTIOIN
io
15
20
PEAK
’
Fig. 49.14-Laboratory curves for lateral sonde of spacing A0 = 1Id through uninvaded beds more resistive than adjacent formations.
Fig. 49.15--Responses of normals and laterals in hard formations (qualitative).
a depression opposite the layer with two symmetrical small peaks, c and d, on either side. The main disadvantage of the normal device is that beds thinner than the spacing, no matter how resistive they may be, appear on the log as being conductive. Fig. 49.14 shows similar curves for a lateral. The lateral curves are markedly dissymmetrical, and their features are more complex. Again the transitions in the curves at the boundaries have been rounded off by the effect of the borehole. When the bed is thicker than the spacing, the upper boundary of the bed is not well defined on the lateral curve, and, as a whole, the bed appears as being displaced downward by a distance equal to the spacing AO. In the lower part of Fig. 49.14 the lateral indicates a resistive layer thinner than the spacing by a sharp peak of relatively low apparent resistivity. Below the layer is a low-resistivity “blind zone,” followed by a “reflection peak” at a distance A0 below the bottom boundary of the layer. The blind zone is recorded when the resistive streak is located between the current electrode and the measuring electrodes. The lateral is useful for the location of thin, highly resistive streaks, although interpretation may be difficult if several resistive streaks are close together. A lower streak located in the blind zone of an upper resistive streak may be missed, and the reflection peaks may be mistaken for actual resistive streaks in the formation. For a resistive layer of thickness approximately equal to the spacing (cn’ticul rhickness), the lateral is almost completely flattened. Similar generalizations are possible for lateral curves recorded for beds more conductive than the surrounding formations. Whether the layer is thick or thin, the shape of the curve is dissymmetrical and the anomalies are spread downward, outside the bottom boundaries. The apparent increase of bed thickness is roughly equal to AO. Normals
and Laterals
in Hard Formations.
Fig.
49.15 shows schematically the behavior of the normals and laterals in thick, highly resistive formations containing porous or shaly (that is, more conductive) zones. In a highly resistive formation most of the current from electrode A flows up or down the borehole, dividing in inverse proportion to the resistances of the two paths, which are determined mostly by the resistance of the mud column in the hole between the current electrode and the nearest conductive beds. At the conductive beds, depending on their thickness and conductivity, the current has low-resistance paths from the hole. The lopsided appearance of the normal and lateral curves is explainable in terms of the unequal division of current flowing up and down the hole. The normal, for example, has M and N above the current electrode. The voltage measured is the ohmic potential drop in the hole resulting fmm current flowing in the mud between M and N. When the device is near the bottom of a resistive bed, most of the current flows down to the conductive bed just below, and there is little potential drop between M and N because the current up is small. When the device has moved farther up in the bed, the current down decreases because the resistance of that path has increased. Also, since the resistance of the upward path has decreased, the current up increases. Therefore, the potential drop between M and N increases as the device moves upward until electrode N reaches the next conductive bed, where the upward current is diverted from the hole. Above that level the normal reading decreases. The explanation of the shape of the lateral curve is similar. The direction of the lopsidedness for either device depends on whether the measuring electrodes are above or below the current electrode. The depressions read on the curves opposite the conductive beds are smooth and, in the case of the lateral, much broadened and displaced downward. Accurate determinations of bed boundaries from the curves are practically impossible.
PETROLEUM ENGINEERING
49-14
GENERATOR
HANDBOOK
METER
Fig. 49.16-Limestone
sonde (schematic).
Limestone Sonde. Four current electrodes (A, A’, B, and B’), connected as shown in Fig. 49.16 by insulated wires of negligible resistance, are symmetrically arranged so that AB=A’B’. A measuring electrode, M, is placed in the middle of the device. Depths are measured from electrode M. In practice AM = A’M =30 or 3.5 in., and AB =A’B’ =4 or 5 in. The device is therefore a symmetrical double lateral. Opposite a thick, highly resistive layer (upper part of Fig. 49.17) practically all the flow of current is confined to the spaces between A and B and between A’ and B’. No current flows from B or B’, up or down the hole away from the device. Hence, from Ohm’s law, B and B’ are at zero potential. Similarly M is at the same potential as A and A’. The potential of M is, therefore, equal to the potential drop in the mud, because of the flow of current, between A and B (or A’ or B’). As long as all the electrodes of the devices are opposite the resistive formation this potential difference is dependent only on hole size and mud resistivity; if these are constant, a constant apparent resistivity is recorded. If the device is located just above a conductive streak (as in the lower part of Fig. 49.17), the streak is effectively a low resistance connecting adjacent portions of the device to points at zem potential. Part of the current now flows in the paths indicated by the arrows, and the potential of electrode M is correspondingly decreased. The conductive streak is indicated on the log by a relatively sharp, symmetrical depression. The limestone sonde gives clearer and simpler logs in hard formations, but measurements with the limestone sonde arc strongly affected by the mud column. When the formations are much more resistive than the mud, the readings are appreciably lower than the formation resistivities. Application of Conventional Resistivity Logs. The three devices that are generally recorded in the conventional electrical log (16-in. normal, 64in. normal, and 18-ft, 8-in. lateral) were designed to provide the most complete information with a system of nonfocused macmdevices.
Fig. 49.17-Principle of limestone sonde (schematic). The short normal is well adapted for bed definition, boundary determination, and correlation of formations of low or moderate resistivities (sand-shale series). The lateral generally shows sharp peaks at the level of thin resistive beds, but the definition of these beds is often obscured by blind zones and spurious peaks. The precision of the normal and lateral curves for bed definition is limited in hard formations and is quite poor when salty muds are used. Somewhat better resolution is obtained with the limestone sonde. In all cases, formation delineation is more detailed and accurate with the IL and focused devices (LL) and with the microdevices. In hard formations the 16-in. normal and the limestone sonde can provide an approximation to the value of Ri and hence an approach for formation factor evaluation. The capabilities of the conventional tools for the determination of R, are discussed later in this chapter.
Induction Logging The IL was first developed to measure formation rcsistivity in boreholes containing oil-based muds. ‘O Electrode devices do not work in these nonconductive muds, and attempts to use wall-scratcher electrodes proved unsatisfactory. Experience soon demonstrated that the induction tools had many advantages over the conventional ES for logging wells drilled with waterbased muds _2’ Induction logging devices are focused to minimize the influence of the borehole and of the surrounding formations. They are designed for deep investigation and reduction of the influence of the invaded zone. Principle Practical induction sondes include a system of several transmitter and receiver coils. However, the principle can be understood by considering a sonde with only one transmitter coil and one receiver coil (Fig. 49.18). High-frequency AC of constant intensity is sent through the transmitter coil. The alternating magnetic field thus created induces secondary currents in the formations. These currents flow in circular ground-loop paths coaxial with the transmitter coil. These groundloop currents, in turn, create magnetic fields that induce
ELECTRICAL LOGGING
signals in the receiver coil. The induced receiver signals are essentially proportional to the conductivity of the formations. Any signal produced by direct coupling of transmitter and receiver coils is balanced out by the measuring circuits. The IL operates to advantage when the borehole fluid is an insulator-even air or gas. But when properly designed the tool also will work very well when the borehole contains conductive mud, provided that the mud is not too salty, the formations are not too resistive, and the borehole diameter is not too large. Equipment Four types of induction equipment are now in use. 1. The 6FF40 IES tool includes a six-coil induction device of 40-in. normal spacing, a 16-in. normal, and an SP electrode. The induction array provides the greatest lateral depth of investigation presently available with induction tools. 2. The 6FF28 IES is a small-diameter (2% in.) tool for use in slim holes. It is a scaled-down version of the 6FF40, having a 28-in. coil spacing, and incorporates a standard 16-in. normal and an SP. 3. The Dual Induction-Laterolog 8 (DILTM) or Spherically Focused Log (SFL) system uses a deepreading induction device (ID, similar to the 6FF40), a medium induction device (IM), an LL8 (or an SFL), and an SP electrode. The IM device has vertical resolution similar to that of the 6FF40 tool but about half the depth of investigation. It is much more affected by large hole diameters and/or salty muds. The DIL log, with its three focused resistivity readings of different depths of investigation, is superior to the IES log for determination of R, and R, in extreme ranges of invasion depths and in cases of annulus. 4. The ISF/Sonic combination incorporates an ID measurement similar to that from the 6FF40 tool, the new ISF log, an SP curve that may be electronically corrected for noise, a borehole compensated (BHC) sonic log, and an optional gamma ray curve. Of late, the BHC sonic tool can be replaced in this tool string by a combination neutron/density device.
Fig. 49.18-Induction-logging (schematic).
SPONTANEOUS POlENlIAl mllllvoltr I
-- ?*
equipment
RtSlSIlVlrY ohm, m'm
$ :
CONDUClIVIlY m,ll,mhos m .$&
.
--
Log Presentation and Scales The SP and/or gamma my curve are recorded in Track 1 for all tools; they can be recorded simultaneously with ISFisonic equipment. A gamma ray curve may also be run with 6FF40 or DIL equipment. Fig. 49.19 illustrates the standard IES presentation. The induction conductivity curve is sometimes recorded over both Tracks 2 and 3. The linear scale is in millimhos per meter (mu/m), increasing to the left. In Track 2 both the 16-in. normal and the reciprocated induction curves are recorded on the conventional linear rcsistivity scale. The DIL introduced the logarithmic grid for resistivity presentations. The current form is the “log-linear” grid shown in Fig. 49.20. In this, the resistivity curves on the detail log (5 in. I100 ft) have a split 4-decade logarithmic scale. On the correlation log (1 or 2 in./100 fi), the scale is linear. This presentation offers several advantages over the other alternatives. The detail log has good readability in low resistivities, a wide range without backup traces, and the ease of reading resistivity ratios
Fig. 49.19-Induction-electrical
log presentation.
PETROLEUM ENGINEERING
49-16
HANDBOOK
SPOHlANtOUIPOItNllAl millivolts
: ::::,: .-.- __-*. i lid : L!-8 _: * :.;..: j-r. .:. v; ‘1, + :.. )>+.h i __::.. ~~ 3-N -!
: : : t-. ,:. : :‘: : ::I j y;* : :: +:..:: : 7’: I.. :: 77 ,,.I :1..: ,:: : +:.:: ~ :. ‘:
Fig. 49.20-Dual
Fig. 49.21~ISFkonic
presentation.
Induction Laterolog 8 presentation.
directly from the logarithmic scale. The linear scale is more easily correlated with earlier logs. This format has gained acceptance as the standard for resistivity logs. The ISF log in combination with the sonic log requires a modification of this grid usage because Track 3 is needed for the sonic At curve. The grid selected is shown in Fig. 49.21. Skin Effect In very conductive formations the induced secondary currents are large, and their magnetic fields are important. The magnetic fields of their ground loops induce additional EMF’s in other ground loops. This interaction between the loops causes a reduction of the conductivity signal recorded by the induction log. This signal reduction is known as “skin effect.” Induction logs usually are automatically corrected for skin effect during recording. The correction is based on the magnitude of the uncorrected tool response treated as
if it were from a homogeneous medium. A secondary skin-effect correction may be required when the media surrounding the sonde are not of uniform conductivity. Such corrections are incorporated in various interpretation charts. Geometrical Factor When conductivities are not high, skin effect may be neglected, and the response of induction logs can be described in terms of conductivities and “geometrical factors” of the volumes surrounding the tool. The geometrical factor, G, of a volume having a specific geometrical orientation with the sonde is simply the fraction of the total signal that would originate with that volume in an infinite homogeneous medium. For computation of geometrical factor to be practical, it is necessary to assume that the volumes conform to symmetry of revolution about the sonde. The magnitude of the signal in conductivity units is the product of the geometrical factor and the conductivity of the material, and the total signal sensed by the tool is the
49-17
ELECTRICAL LOGGING
INTEGRATED
RADIAL
GEOMETRICAL
FACTOR
0.6
-No I 0
----Skin
W 0
-0
40
00
120
160
Skin
Effect
Effect
200
Included:
Case
280
320
240
of
360
DIAMETER OF INVADED ZONE di (in.) Fig. 49.22-Geometrical ILd device.
factor. Dashed curve includes skin effect under conditions shown, for the
sum of these products for all volumes within range (which extends to infinity, but can be circumscribed to practical limits). Since the G’s add up to unity by definition, this can be stated: CtL=CtG,
+C2G2+C3G3...+CNGN,
...
(10)
C,=C,G,,+W,,
=(C,/4) =0.85
(0.2)+C,(O.S), C,.
In the same conditions,
but using salty mud so that
R,,=R,i4,the response is where C and G refer to the zones of differing conductivity and N is the total number of such zones. The chief significance of this concept is the fact that a volume of space defined only by its geometry relative to the sonde has a fixed and computable geometrical factor. This permits the construction of mathematically sound correction charts to account for the effects of borehole mud, the invaded zone, and adjacent beds on the R, measurement, providing symmetry of revolution exists. 2 These charts incorporate the secondary skin effect correction mentioned above.
=1.6
C,,
which illustrates the “conductivity-seeking” characteristic of the induction devices, and shows why they must be used with discretion in salt-mud environments. As a rule of thumb, R, should be less than about 2.5 R,,and di (diameter of invaded zone) no greater than 100 in. for satisfactory R, determination from 6FF40-type induction logs. Annulus
Invasion Effects Fig. 49.4 illustrates an invaded formation. It includes volumes having several conductivities, C,, C,, Ci, and C, (corresponding to R,, R,,,Ri,and R,).The total conductivity signal, CT, received from this zone by the induction tool is C,=C,G,+C,G,+CiGi+C,G,.
GIL =4 C,(O.2) + C, (0.8),
. . . . . .(ll)
If the zone were infinitely thick, this would be the only signal received, and CT = C,L. If the tool is a 6FF40, the hole size moderate, and the mud relatively fresh, the borehole signal is negligible, and the C,, and Ci zones can be merged into one for this example. If a moderate diameter of invasion, say 65 in., is assumed, Fig. 49.22 reveals that the geometrical factor of all material within the 65in. diameter is 0.2. If R,r, is taken equal to 4 R,,then C,, =C,/4, and the induction tool response is
In oil-bearing formations of low S, and high permeability, an annulus of low resistivity , R, , may exist between the flushed zone, R,,,and the virgin formation. When R, is greater than R,,R,, is less than R,,and the effects of the two on the induction log tend to cancel. However, the high conductivity of the annulus has more effect in medium invasion ranges (2dh < di < 4 or 5dh), and it may cause a single ID to read resistivities lower than either R,,or R,. The DIL 8 tool is often capable of detecting the presence of annuli, since in these circumstances the IM measurement reads lower than either the LL8 or the ID values, Thin Bed Corrections The skin-effect correction accomplished automatically in the induction tools assumes infinitely thick beds. Skin effect in thin beds may require additional corrections, and these are provided in Ref. 2.
49-1 a
PETROLEUM ENGINEERING
Fig. 49.23-Schematic
of focusing-electrode
Borehole Corrections Conductivity signals from the mud can be evaluated using geometrical factors. Chart Rcor-4 (Ref. 2) gives corrections for the various induction tools and standoffs. On the basis of bit size the nominal borehole signal is sometimes removed from the recorded log. When the hole signal is significant, log headings should always be consulted to ascertain whether this was done. This precaution applies most frequently to the IM measurement of the DIL tool. For hole diameters in the range of 7 to 13 in. there is an uncertainty of about f0.0003 on the geometrical factor of the borehole for the 6FF40 sonde. This results from several factors, including diameter and shape of the borehole, mudcake thickness, standoff, and sonde tilt. To preclude the possibility of cumulative errors exceeding 20% of the 6FF40 reading, the tool should not be used where the resistivity to be measured is greater than about 500 R,. Very Resistive Formations There is an uncertainty of about 52 mO/m on the zero of the present induction sondes (6FF40, ID, and IM), and consequently the resistivity error may be great as conductivity approaches zero. To preclude an error of more than 20%, the formation conductivity should be greater than 10 mu/m (i.e., the resistivity less than 100 Q.m). This error can sometimes be practically eliminated by downhole calibration techniques if suitable formations are present. Calibration Primary calibration is performed by placing a test loop around the sonde. The conductive loop has a resistance, which has been adjusted to produce a certain conductivity signal in the sonde. An additional calibration procedure has a signal produced internally in the sonde to adjust the control-panel sensitivity for proper galvanometer deflections. The “zero errors” of the electronics in the equipment arc also checked and balanced out. “Calibrate tails,” usually attached to the log, serve as a record of the calibration tests made before and after the logging run. In some regions it is possible to check the calibration of the IL by observing that the conductivity reading op-
HANDBOOK
devices.
posite an impervious formation of exceedir,gly high resistivity (such as anhydrite) represents the sum of all spurious signals. If the hole diameter is known, it is then possible to correct the IL reading so that the range of uncertainty is reduced and greater accuracy is obtained in formations of practical interest. Summary 1. The IL can be used most effectively in holes filled with moderately conductive drilling muds, nonconductive muds, and in empty holes. 2. Vertical focusing is good, making possible reliable evaluation of beds down to about 5 ft thick with 6FF40, ID, and IM devices, and down to about 3% ft thick with 6FF28 tools. 3. The deep induction logs (ILd) are only moderately affected by invasion in relatively fresh muds, and good R, determinations are possible where R, is less than about 2.5 R, and di is less than 100 in. 4. The three curves of the DIL give more precise knowledge of invasion profiles and hence better R, values in the cases of deep invasion or annulus. 5. The log-linear presentation of the DIL and other IL’s meets most log requirements better than alternative displays.
Focused-Electrode Logs The responses of conventional ES can be greatly affected by the borehole and adjacent formations. These influences are minimized by a family of resistivity tools that use focusing currents to control the path taken by the measure current. These currents are supplied from special electrodes on the sondes. Equipment The focused-electrode tools include the Latero!ogs (LL) and SFL’s. These tools are much superior to the ES devices for large R&R, values (salt muds and/or highly resistive formations) and for large resistivity contrasts with adjacent beds (RJR,or R,IR,). They are much better for resolution of thin to moderately thick beds. Focusing-electrode systems are available wit! deep, medium, and shallow depths of investigation. Devices using this principle have as quantitative applications the determination of R, and of R,. The R, tools are Laterolog 7 (LL7), Laterolog 3 (LL3), and
ELECTRICAL LOGGING
49-19
RESISTIVITY
LATERLOG
-
0,0,=32”=4d,A,A,=80”=10d,l
AC,= 18%” = 28d
Fig. 49.24--Response of Laterolog 7 and ES opposite a thin, resistive, noninvaded bed, with very-Salty mud (laboratory determination).
LLD of the deep dual laterolog. shallow-reading devices, all integral tools, are Laterolog 8 (LL8) of the shallow dual laterolog, and the SFL combination.
The medium-towith combination DIL, LLS of the of the ISFisonic
Laterolog 7. This deviceI comprises a center electrode Ao, and three pairs of electrodes: M 1 and Mz; M’ 1 and M’z; and Al and A2 (Fig. 49.23). The electrodes of each pair are symmetrically located with respect to A0 and are connected to each other by a short-circuiting wire. A constant current 1, is sent through electrode Ao. Through bucking electrodes A, and AZ, an adjustable current is developed; the bucking current intensity is adjusted automatically so that the two pairs of monitoring electrodes, M , and Mz and M’ , and M’2, are brought to the same potential. The potential drop is measured between one of the monitoring electrodes and an electrode at the surface (i.e., at infinity). With a constant IO current, this potential varies directly with formation resistivity. Since the potential difference between the M 1-Mz pair and the M’ I -M’ 2 pair is maintained at zero, no current from A0 is flowing in the hole between M I and M’ 1 or between M2 and M’2. Therefore, the current from A0 must penetrate horizontally into the formations. Fig. 49.23 shows the distribution of current lines when the sonde is in a homogeneous medium; the “sheet” of 10 current, indicated by the hatched area, retains a fairly constant thickness up to a distance from the borehole somewhat greater than the total length A, A2 of the sonde. Experiments have shown that the sheet of IO current retains substantially the same shape opposite thin resistive beds. The thickness of the IO current sheet is 32 in. (distance 0 I 02 on Fig. 49.23), and the length A I A2 of the sonde is 80 in. Fig. 49.24 compares the curves obtained experimen-
tally opposite a thin resistive bed using the conventional devices (16 and 64-in. normals and 18-ft, g-in. lateral) with the corresponding LL7 recording. The conventional devices give poor results; the LL7, in spite of difficult conditions (RJR,,, is 5,000), shows the bed very clearly and reads close to R,. An SP curve may be recorded on depth simultaneously with the LL7.
Laterolog 3 Like LL7, LL3 also uses currents from bucking electrodes to focus the measuring current into a horizontal sheet penetrating into the formation. However, as seen in Fig. 49.23, large electrodes are used. Symmetrically placed, on either side of the central A0 electrode, are two very long (about 5-ft) electrodes, Al and AZ, which are shorted to each other. A current, 10, flows from the A0 electrode whose potential is fixed. From Al and A2 flows a bucking current, which is automatically adjusted to maintain A, and A2 at the potential of A0 All electrodes of the sonde are thus held at the same constant potential. The magnitude of the IO current is then proportional to formation conductivity. The IO current sheet is constrained to the shaded, approximately disk-shaped area in Fig. 49.23. The thickness, 0, 02, of the IO current sheet is usually about 12 in., much thinner than for LL7. As a result, LL3 has a better vertical resolution and shows more detail than LL7. Furthermore, the influences of the borehole and of the invaded zone are slightly less. The simultaneous recording of an SP curve is possible, but the SP has to be displaced in depth, usually by about 25 ft, because of the large mass of metal in the sonde. a gamma ray curve is normally run However, simultaneously with the LL3 for lithology definition, since the SP has very little character in the salt muds where the LL is used. There is also available a simultaneous LL3-neutron/gamma ray combination tool.
PETROLEUM ENGINEERING
49-20
HANDBOOK
LLD m
Thick
Beds
8” Ho
a--
-:T---Flh’
Fig.
49.25-Schemalic of the dual laterolog.
8
Guard-Electrode Device. In the guard-electrode system, the surveying current flows into the adjacent formations from a measuring electrode disposed between relatively long upper and lower guard electrodes from which current also flows. The guard electrodes tend to confine the current from the measuring electrode to a generally horizontal path. The measuring and guard electrodes are connected through a very low impedance, as necessary to measure the surveying current supplied to the measuring electrode. A resistivity value is obtained by recording the ratio of the voltage of an electrode in the assembly (referred to a distant point) to the current emitted from the measuring electrode. The guard-electrode device is used mostly in hard-rock territories for detailed bed definition, correlation, and as a help in reservoir evaluation. For the determination of R, it is preferable that R,fIR, be small (less than 4), as in the case of salty muds. Laterolog 8. The shallow-investigation LL8 device is recorded with small electrodes on the DIL sonde. It is similar in principle to LL7 device except for its shorter spacings. The thickness of the 10 current sheet is 14 in., and the distance between the two bucking electrodes is somewhat less than 40 in. The current-return electrode is located a relatively short distance from Ao. With this configuration, the LL8 tool gives sharp vertical detail, and the readings are more influenced by the borehole and the invaded zone* than arc those for LL7 and LL3. The LL8 data are recorded with the DIL on a split 4-decade logarithmic scale. Dual Laterolog. Since the measure current of an LL has to traverse mud and invaded zone to reach the undisturbed formation, the measurement is necessarily a combination of effects. With only one resistivity measurement, the invasion profile and R,, had to be known or
20
Diameter
---
RX,= 0.1 Rt
-
Rx0 ’ Rt
40
80
60
d i 1 inches)
Fig. 49.26-Radial pseudogeometrical factors, (solid) and salty muds (dashed).
fresh
muds
estimated in order to calculate R, . The need for a second measurement at a different depth of investigation resulted in the dual laterolog/gamma ray tools (Fig. 49.25). One version of the tool records the two laterologs sequentially; another does it simultaneously and has added a shallow MICROSFL(MSFL) for R,, information. Both can record a gamma ray curve on depth, simultaneously with the resistivity curves. An SP can also be run. By use of effectively longer bucking electrodes and a longer spacing, the LLD (deep latemlog) has been given a deeper investigation than either LL7 or LL3 devices. The LLS (shallow laterolog) uses the same electrodes in a different manner (Fig. 49.25 right) to achieve a current beam equal in thickness to that of LLD, 24 in., but having a much shallower penetration. The LLS depth of investigation lies between those of the LL7 and LL8 devices (Fig. 49.26). Spherically Focused Log. The SFL log is part of the ISF/sonic combination, and it was developed as an improvement over both the 16-in. normal and the LL8 as a short-spacing companion to the deep induction log. Normal resistivity devices rely on the concept of equal intensity of current radiation in all directions, as would happen in a homogeneous isotropic medium. When the current distribution is distorted from the spherical model, as by the presence of a borehole, the readings must be corrected by departure curves. The SFL device uses focusing currents to enforce an approximately spherical
ELECTRICAL LOGGING
49-21
10
Ii --I : : . I I : r---
‘J
L
I<-
:
I -L:
:::::: ::.:I
:
.:
:: ::: ,:..: ii:L/ T I ‘:-j
: : ;
.:
1’-
i
-1.
._: i : : : i I
.
”
::‘I ._.~ --.:. ::;f : : 11 z’; ;r;i ._._ fT ::Y . . : 1
T....._ -: I. : :1:::1: T r..... f : : ‘:::: :
7 i:::: j:.ii ;: y< .~_ :: +k
Fig. 49.27-Laterolog
recorded on hybrid scale.
L.... : _:.. /
!
.
‘. I..!
Fig. 49.29-Laterolog over same interval as Fig. 49.22, recorded on logarithmic scale.
shape on the equipotential surfaces over a wide range of wellbore variables. The borehole effect is virtually eliminated where dh 5 10 in., yet most of the response is from the invaded zone in all but extreme conditions. Scales. The linear resistivity scales originally used for LL data were poorly adapted to record the wide range of measurements characteristic of these tools. Although linear scales are still used occasionally, compressed scales of either the hybrid or logarithmic type have supplanted the linear for quantitative work. The hybrid scale, first used on the LL3 log, presented linear resistivity on the first half of the grid track and linear conductivity on the last half. Thus, one galvanometer could record all resistivities from zero to infinity. (See Fig. 49.27.) The logarithmic scale was used first with the dual induction tool, and it has also been adapted for the LL and the SFL devices (Fig. 49.28). It combines readability and detail in low msistivities with a wide range of values, and it also offers the advantage of graphic (quick-look) interpretations. Influence of Wellbore Variables These logging devices can be significantly affected by the borehole mud, the invaded zone, and adjacent beds. Charts Rcor-1 and Rcor-2 of Ref. 2 provide needed corrections. Where only one measurement is available, some knowledge or assumption of depth of invasion must be used for deriving R,. Readings must be corrected for borehole effect before the shoulder-bed charts are entered. (See Figs. 49.29 and 49.9.) These figures
Fig. 49.29--Shoulder-bed (bottom).
corrections,
LL3
(top) and
LL7
PETROLEUM ENGINEERING
49-22
HANDBOOK
give R, /R, as a function of bed thickness, R, being the corrected resistivity and R, the apparent resistivity corrected for borehole effect.
formation waters-and (2) to provide correlation and R,, determinations in conjunction with deeper-reading R, devices.
Pseudogeometrical
Microresistivity Devices
Factors
Geometrical factor may be defined as that fraction of the total signal that would originate from a volume having a specific geometrical orientation with the sonde in an infinite homogeneous medium. The only well-logging devices for which this concept is sound are the induction tools, because only with these is the measuring geometry independent of variations in RJR,. However, it is useful to construct charts based on “pseudogeometrical factors” for other resistivity devices, for purposes of comparative evaluation. Such a chart is shown in Fig. 49.26 in which the integrated pseudogeometrical factors of progressively larger cylinders are plotted vs. the diameters of the cylinders. The apparent resistivity, R,, measured in a thick bed is given approximately by R,=R,,G,i+R,(l-G,;),
.. .
.
(12)
where G,; is the pseudogeometrical factor. It must be emphasized that a pseudogeometrical factor relating to an electrode-type resistivity device is applicable in only one set of conditions, and therefore charts of this type are not valid as general-purpose invaded-zone correction charts. The most useful feature of the Fig. 49.26 chart is its graphic comparison of the relative contribution of invaded zones to the responses of the various tools. The Delaware
Effect
If both B and N electrodes are placed downhole as in Fig. 49.10, LL data may exhibit “Delaware effect”* (or “gradient”) in sections located just below thick nonconductive beds such as anhydrite. It appears as abnormally high resistivity for 80 ft or so below the resistive bed. The LL3 is the only field tool now using this arrangement. Fig. 49.10 illustrates the effect and its causes. As B enters the thick anhydrite, the current flow is confined to the borehole, and if the bed is thick enough (several hundred feet) practically all the current will flow in that part of the hole below B. Then when N enters the bed, it can no longer remain near zem potential as intended. It is exposed to an increasing negative potential as it rises farther from the bed boundary. This potential appears at the surface as an increase in the resistivity measurement. LL7 and LLD devices normally use surface electrodes for current return. so they are not subject to Delaware effeet. However, a small anti-Delaware effect has been observed, which produces resistivities that are too low just below the resistive beds. Conclusions Resistivity devices with the focusing electrode principle meet certain logging requirements bettebetter +hon than n+hpr other +l~noc types now available. These requirements are (1) to take measurements leading to determination of R, in conditool are not well tions for which the induction tools suited-i.e., R, values in excess of 100 Q-m and/or mud resistivities of the same order or lower than those of the ‘So-called because 1 was ilrst observed ,n Ihe Delaware saw ,,,r Y sand v, of the Delaware basin (west Texas) This sand underltes a very thick anhydrite bed
Microresistivity devices are used to measure R,, (resistivity of the flushed zone) and to delineate permeable beds by detecting the presence of mudcake. In the discussion that follows, the micmlog (ML) will be treated in considerable detail, not because of its relative importance-the micmlaterolog (MLL), the proximity log (PL), and the MSFL are superior tools for obtaining R,,-but because its principle is fundamental, and it is still the best of the three microresistivity devices for delineating permeable-bed boundaries, hence for making “sand counts.” Measurements of R,, are important for several reasons. When invasion is moderate to deep, knowledge of the R, value makes possible more accurate determinations of true resistivity and hence of saturation. Also, some methods for computing saturation are entered with the ratio RJR,. Also, in clean formations, a value of F may be computed from R,, and R,,f, if S,r, is known or estimated. From F, a value for porosity may be found. a shallow-investigation tool is To measure R, desirable, since the R,, zone may sometimes extend only a few inches beyond the hole wall. Also, the reading should preferably not be affected by the borehole. A sidewall-pad tool is indicated. The pad, carrying short-spacing electrode devices, is pressed against the mudcake, thus reducing the short-circuiting effect of the mud. Currents from the electrodes on the pad must pass through the mudcake to reach the R,, zone. Microresistivity readings are more or less affected by mudcake, depending on its resistivity, R,,, and thickness, h,, Moreover, mudcakes can be anisotmpic, with mudcake resistivity parallel to the borehole wall less than that across the mudcake. Mudcake anisotropy increases the mudcake effect on micmresistivity readings, so that the effective, or electrical, mudcake thickness is greater than that indicated by a caliper. The micmresistivity tools incorporate two-arm calipers, which show the size and condition of the borehole. Equipment Present equipment includes a combination tool with two pads mounted on opposite sides. One is the ML pad, and the other may be for either the MLL or the PL, as required by mudcake conditions. The measurements are recorded simultaneously. The MSFL is a combination tool, which can be run with either formation density or dual latemlog equipment. Log Presentation The lnuc nn- a-sled, The mirrnr&rtivitv microresistivity logs are scaled, of of course, course, in in itself, the ML data resistivity units. When recorded by ‘~ are usually recorded over Tracks 2 and 3 on a linear resistivity scale. The microcaliper data are in Track 1. The MML or PL is recorded on a four-decade logarithmic scale on the right of the depth track (Fig. 49.30). The caliper is recorded in Track 1. When the ML data are also recorded, they are in Track 1 on a linear scale. The MSFL data are also recorded on the
ELECTRICAL LOGGING
logarithmic grid. When run with the dual laterolog, it is presented on the same film as the LL curves. With the Compensated Formation Density (FD?) log, it must be presented on a separate film, since the FDC log uses a linear grid; the two logs arc normally recorded simultaneously.
49-23
I
RESISTIVITY yll, II -
RESISTIVITY hrn, - r
: ,I
3
‘?
‘70
Microlog With the microlog too1,23 two short-spacing devices with different depths of investigation provide resistivity measurements of a very small volume of mudcake and formation immediately adjoining the borehole. They readily detect the presence of any mudcake, indicating invaded (hence permeable) formations. Principle. Arms and springs press a rubber pad against the hole wall. In the face of the pad are inserted three small electrodes in line, spaced 1 in. apart. With these electrodes a 1-X l-in. micminverse, R, Xl, and a 2-in. micronormal, R2, are recorded simultaneously. As drilling mud filters into the permeable formations, mud solids accumulate on the hole wall, forming a mudcake. The resistivity of the mudcake is about equal to, or slightly greater than, the resistivity of the mud. Mudcake resistivity is usually considerably smaller than the resistivity of the invaded zone near the borehole. The 2-in. micronormal has a greater depth of investigation than the 1-x l-in. micminverse. It is therefore less influenced by the mudcake and reads a higher resistivity, producing “positive” curve separation. In the presence of the low-resistivity mudcake, both devices will measure moderate resistivities, usually ranging from about 2 to 10 times R, Interpretation. Positive separation in a permeable zone is illustrated in Fig. 49.30, at Level A. The caliper shows evidence of mudcake. However, quantitative inferences of permeability are not possible from the ML data. When no mudcake exists, for whatever reason, the ML data may yield useful information as to borehole condition or lithology , but the log is not quantitatively interpretable. Under favorable circumstances, R, values can be derived from the ML by use of Fig. 49.31. R,, values for this purpose can be measured directly or estimated fmm Ref. 2, and h,, is obtained from the caliper. Limitations of the method are (1) the ratio R,,lR,, must be lower than about 15 (porosity more than 15%), (2) h ,,,=must be no greater than ‘/2in., and (3) depth of invasion has to be over about 4 in., otherwise the ML readings are affected by R,. Eqs. 6 or 14 permit the porosity derivation from the ML measurements. For this, the value of S,, must be reasonably well known. Mud Log The ML sonde is lowered into the hole with arms closed. Except in holes smaller than 8 in., the measuring pad will randomly face away from the wall part of the time, and its reading then will be determined mostly by the mud. A recording of these readings, conveniently made going down, serves as a “mud log,” on which the lowest resistivities correspond to the upper limit of the in-situ value of R,. This log has several potential applications, including crosschecking the surface R, measurement, detecting mud-system changes, and identifying downhole water flows.
Fig. 49.30-Presentation
of proximity log-microlog
Ftg. 49.31-Interpretation chart for 8-in.-hole series C microlog for which adjacent electrodes are 1 in. apart. R, in designates reading of 2-in. micronormal (AM, =2 in.) and RIx, ,“, is I- by I-in. microinverse (AM, = 1 in., M, M, = 1 in.). Type I hydraulic pad, noninsulated sonde.
803”moo
PETROLEUM
49.24
ENGINEERING
HANDBOOK
Mud
Mud
Fig. 49.32-Microlaterolog pad showing electrodes (left) and schematic current lines (right).
Mlcrolog
Microloterolog Fig. 49.33-Comparative distribution of Microlaterolog and Microlog.
Microlaterolog
Coke
current
lines
of
(MLL)
On ML (Fig. 49.31) for values of RIO/R,, greater than about 15, the curves for constant values of R,,lR,, arc crowded; as a result, the accuracy of the determination of R, from the ML is poor in this region. With the MLL method, it is possible to determine R,, accurately for higher values of R,,lR,,, provided, however, that the mudcake thickness does not exceed X in. Principle. The MLL pad is shown in Fig. 49.32.24 A small electrode, Ao, and three concentric circular electrodes are embedded in a rubber pad applied against the hole wall. A constant current, I,, is emitted through electrode AO. Through the outer electrode, A I , is sent a current automatically adjusted so that the potential difference between the two monitoring electrodes is maintained essentially equal to zero. The 10 current flowing past the M 1 electrode cannot reach M2 and is forced to flow in a beam into the formations. The current lines are shown on the figure. The IO current near the pad forms a narrow beam, which opens up rapidly at a few inches from the face of the pad. The MLL reading is influenced mostly by the formation within this narrow beam. Fig. 49.33 compares qualitatively the current-line distributions of the MLL and the ML when the corresponding pad is applied against a permeable formation. The greater the value of R,,lR,, the greater the tendency for the microlog 10 current to escape through the mudcake to reach the mud in the borehole. Consequently, for high R,IR,, values, the readings of the ML respond very little to variations of R,. On the contrary, all the MLL I0 current flows into the formation and the MLL reading will depend mostly on the value of R,,. Response. Laboratory tests have shown that the virgin formation has practically no influence on the MLL readings if the invasion depth is more than 3 or 4 in. The influence of mudcake is negligible up to h mr = % in. but increases rapidly with greater thicknesses. Chart Rxo-2 in Ref. 2 gives appropriate corrections; however, if mudcakes thicker than % in. arc anticipated, the PL is prcferred for R,, determination.
Proximity Log (PL) Principle. The proximity tool is similar in principle to the MLL tool. The electrodes are mounted on a somewhat wider pad, which is applied to the wall of the borehole; the system is automatically focused by monitoring electrodes. Response. Pad and electrode design arc such that isotropic mudcakes up to % in. have very little effect on the measurements (see Chart Rxo-2 in Ref. 2). If the invasion is shallow, the reading of the proximity device is influenced by R,. The resistivity measured can be expressed as RfL=GpiRxo+(l-Gpi)R,,
...
where G,i is the pseudogeometrical factor of the invaded zone. The value of G,i as a function of invasion diameter di is given in Fig. 49.34; this chart gives only an approximate value of G,; , which in fact also depends to some extent on the diameter of the borehole and on the ratio R,, lR, . If di is greater than 40 in., GpI is very close to 1 and, accordingly, RPL will differ little from R,, . If di is less than 40 in., R, is somewhere between R,, and R,, usually much closer to R,, than to R, . RPL can be fairly close to R, only if the invasion is very shallow (of course when R,, and R, are nearly equal, the value of RPL will depend very little on d,). MICROSFL
(MSFL)
This is a pad-mounted SFL device. It embodies two distinct advantages over other microresistivity devices: (1) it is compatible with other logging tools, specifically the FDC and the simultaneous dual laterology (SDL), which eliminates the need for a separate logging run to obtain R, information, and (2) it responds to shallow R, zones in the presence of mudcake. The MSFL gives good R.w resolution in thick-mudcake conditions, but
ELECTRICAL LOGGING
does not require as great an invasion depth as does the PL. This characteristic makes it useful in a wider range of conditions than either the PL or the MLL. The effect of mudcake on the MSFL data is shown in Ref. 2. Principle. Spherical focusing is the shaping of the equipotential surfaces produced by the resistivity device to approximately spherical form. The focusing is accomplished by auxiliary electrodes, as in the MLL and PL; but, instead of being forced into a narrow beam, the measure current is merely prevented from following the borehole mud or mudcake paths. A careful selection of electrode spacings achieves an optimal compromise between too much and too little depth of investigation.
I I \ f7 I I I
/ /
Conclusions The ML permits a very accurate delineation of permeable beds in all types of formations. It can also provide satisfactory R,, and porosity determinations under favorable conditions, which are (1) R,,IR,, < 15, (2) h,, c % in., and (3) depth of invasion greater than about 4 in. The focused microresistivity tools can provide good R,, values under a much wider range of conditions. The MLL is limited chiefly by mudcake thickness, but is well adapted to salt-base muds. When h,, exceeds % in., the PL or the MSFL log is preferable.
RIO’R, f
--
Depth of Invasion,
R X,,= 0 I I,
in
Uses and Interpretation of Well Logs Bed Detection and Definition Formations encountered in uncased boreholes may be detected and their boundaries defined by a number of different logs. The SP and short-investigation curves are most commonly used. For great detail, the microdevices are superior-ML in fresh muds and MLL in very salty muds. A substitute for the SP in salt muds is the gamma ray log, which distinguishes shales from nonshale beds. Also, the sonic and density logs could be used in all types of formations, with any type of mud. In holes filled with nonconductive muds, or in empty holes, the induction, radiation, temperature, sonic (not applicable in empty holes), and perhaps section-gauge logs can provide useful information. Sometimes conventional devices with wall scratchers, for contact with the formation, may be run. Porous and Permeable Beds-Sand Count. Porous and permeable beds are of primary interest since they are the potential oil and gas reservoirs. A sand-count determination of the total effective thickness of a permeable section, excluding shale streaks and other impermeable zones, can be derived from electrical logs. Fresh Muds. The SP and microresistivity devices are the principle curves for locating and defining permeable beds. The SP has a good resolving power in formations of low and moderate resistivity. In very resistive formations it can still detect shales and permeable beds, but it cannot define their boundaries accurately. In most types of formations the ML is best for establishing the detailed location of the boundaries of permeable beds. The microcaliper helps in the location of permeable beds because it can usually detect the mudcakes. particularly if the adjacent formations are approximately at bit size. Shales, on the other hand, generally tend to cave
Fig. 49.34-Pseudogeometrical
factors, MLL and PL.
or erode more than the permeable or hard impervious beds. Very often, and mostly in sand-shale series, the difference between the readings of a short-investigation and a long-investigation device is a clear indication of the presence of a permeable bed. Salt Muds. The combination of very salty mud with moderate-to-high formation resistivity adversely affects the conventional (nonfocused) devices and the SP curve. Also, mudcakes are thin; as a consequence, the microcaliper (or also the section gauge) is not of great help for the detection of permeable sections but detects clearly the caved shales. In conjunction with the LL and MLL the gamma ray log distinguishes between shales and nonshales, and the neutron, sonic log, and density log provide indications of porosity. Correlation The process of correlating two (or more) logs in different
wells depends essentially on the similarity in shapes or outlines of the curves (Fig. 49.35). In some regions such correlations may be easily made for wells miles apart; in other cases (where serious faulting, lenticular deposits, or unconformities are present) it may be difficult to correlate logs from wells only a few hundred feet apart. The knowledge of formation dip from dipmeter determinations assists in correlation. Correlations are facilitated when the curves show characteristic “markers” such as a well-known chalk or shale section. Thin resistive beds such as lignites or evaporites frequently furnish valuable correlation points. For long-range correlation, the devices that investigate large volumes of formation are best. However, when the
49-26
PETROLEUM ENGINEERING
HANDBOOK
characteristics are approximately constant, which is not always the case, however. Still another approach often used in hard formations is based on the value of Ri, the average resistivity of the invaded zone estimated from the readings of the limestone sonde or the short normal.25,26 This procedure has proved valuable in many cases. Other Tools for Obtaining Porosity. The sonic log, the neutron log, and the density log are increasing in importance as auxiliaries to the electrical logs for improved porosity determination.* In addition, with the present sample taker, reliable determination of formation factor and porosity are often possible from sidewall cores. Investigation of Fluid Content Fig. 49.35-Example
of long-distance correlation.
pay zones are known in a field, they can be correlated in great detail from well to well by comparing the ML or MLL; thus, the geometry of the reservoir can be obtained. Investigation of Porosity Evaluation of formation porosity from electrical logs is based on determination of the formation factor, FR, which is related to porosity, 4, by Eq. 2. FR can be found from the value of R,, as determined from the ML or MLL with Eq. 6 rewritten as R FR=- Rx* (S,)2, mf
..
....
(14)
where S,, = 1 -S,, . from microresistivity measurcTo determine R, merits, it is necessary that invasion be deep enough that the measurements are not affected by the formation resistivities beyond the flushed zone. An exceedingly great mudcake thickness may also limit the accuracy of the R, determination. For reliable porosity interpretation from ML data the porosity should be greater than about 12 to 15%. In an oil-bearing sand, the residual oil saturation (ROS) must be surmised for use in Eq. 14. Taking a value of 20% for the ROS would not usually entail too great an error in most cases, at least in formations with granular porosity and containing light oils. Greater ROS’s are frequent, however, chiefly in the cases of highly viscous oil. Gas-bearing formations also seem to display high residual gas saturations in the flushed zone if the permeability is high. This is because of segregation effects resulting from a combination of gravity and capillary forces. Because of these residual saturations, the ML may show water contacts. To check the results of the microresistivity devices, or to replace them in case they are not available, FR may be determined as equal to RoIR,, R. being the true resistivity of the formation at a level where it is 100% water bearing. Extrapolation of a value of FR determined at a water-bearing level to the oil-bearing section within the same formation implies that the lithological
Quite often good qualitative judgments about a formation as a potential producing zone can be had by direct visual inspection of the log. Basically such judgments usually depend on (1) identification of a permeable formation by means of the SP, mudcake indications on microcaliper, positive separation on ML, indication of invasion by separation between shallow- and deepinvestigation macmresistivity curves, etc., and (2) indication by the deep-investigation resistivity devices that R, in the permeable formation is appreciably larger than the resistivity, Ro, that the formation would be expected to have if water bearing. When it can be assumed that there is no abrupt change in the salinity of the formation waters, the radius of invasion, etc., qualitative evaluations of saturation may be made by comparing a porosity log with a resistivity log over a large enough section of formations. Such a method, in which the neutron log was the source of the porosity data, was proposed several years ago.27 Also, the possibility of accurate measurements of porosity with the sonic and density logs has mmpted similar qualitative interpretation procedures. 29 When invasion is not too deep, so that the deepinvestigation resistivity devices read fairly close to R,, the following procedures are applicable. 1. Sonic** transit time may be plotted vs. a deep IL resistivity (in case of fresh muds) or vs. the LLD resistivity (in case of salty muds). 29 By a proper choice of scales, lines of constant resistivity index, I,, become straight lines on the chart, as in Fig. 49.36. The line of 100% water saturation (ZR= 1) is constructed as the line bounding the leftmost plotted points and passing through the point corresponding to infinite resistivity and zero sonic log porosity. Lines for other values of iR may then be constructed. It is possible to distinguish between oilor gas-bearing and water-bearing zones by the relative positions of the plotted points. For a zone to be oil- or gas-productive the plotted point should fall appreciably to the right of and below the line of 100% saturation. This method is useful even if the formation-water resistivity is not initially well known. 2. By use of porosity derived from the sonic or neutron log and the resistivity from the deep-investigation log, apparent values of the formation-water resistivity ‘The shon-interval sonic velocity log (Sony neutron lag IS dlscusssd ln Chap. 51. “With some precautons. den%ty or newon data in a similar crossplot technique
log) IS discussed
data may be employed
I” Chap.
50. The
I” place 01 90~
49-27
ELECTRICAL LOGGING
R, =R,IFR may be computed (using Eqs. 2 or 3 to obtain FR). When tabulated in terms of depth, those apparent values that stand definitely above the average trend indicate the presence of hydrocarbon saturation. This procedure is rapid and applicable in shaly sands. It is also applicable when formation-water salinity varies appreciably with depth, provided that the variation is gradual and continuous. 3. The readings of a short-investigation resistivity log should give indications of the variations in the formation factor (and porosity). Accordingly, hydrocarbon satumtion can also be qualitatively determined by examining the ratios of the readings of a short-investigation device (such as a short normal, LLS, or PL) to those of the deep induction log (IM) or LLD. The two sets of readings may be used to locate points on a graphic plot, as described previously, or to construct a continuous curve of the ratio vs. depth. In either case the comparison is facilitated if the logs have been recorded on a logarithmic sensitivity scale. The following procedure is helpful when, because of deep invasion, the value of the true resistivity is in doubt. The porosity from the sonic log is compared with the porosity computed from a shallow-investigation resistivity log (such as short normal, limestone sonde, LLS or PL). The latter porosity is affected by any residual oil saturation, whereas the sonic log porosity is not. Zones where the two porosities differ should accordingly indicate potentially productive formations. Also, in hard formations (where permeability is generally low) a resistivity gradient (corresponding to a saturation gradient) is observed on the logs between the zone of lowest water saturation and the level of 100% water saturation. The existence of this gradient is the basis of a method for the delineation of intervals saturated with hydrocarbons. 3o Quantitative Interpretation* Quantitative determinations of the hydrocarbgn saturation from electrical logs are essentially determinations of the water saturation, S,, in the uncontaminated zone. Recalling Eq. 5
The evaluation of R, is a major step in the determination. Evaluation of FR is equivalent to an evaluation of porosity, as already discussed. R. may be determined in a 100% water-saturated section of the same sand or in a lithologically similar sand. Some interpretation procedures do not require explicit evaluation of R, and FR . Along with a knowledge of the SSP, or equivalently the ratio R&R,, they are based on the ratios of readings taken with deep- and shallowinvestigation devices [e.g., R,,IR, method, inductionelectrical log (IEL) interpretation, Rocky Mountain method]. A special approach is applied in case of shaly formations. ‘Only ~omp~tatmns that can be made by hand wll be studled here Latest ~nterpretaban techniques ate made by computers and are explalned under The Digital Age.
SONIC
LOG TRANSIT
SONC LOG (TAKING YM*,R,X’
TIME. u SECFT POROSITY 21.000 FT/SEC)
-37k-+F,(FOR
rn: 2 1
Fig. 49.36--Qualitative method for differentiating water-bearing and oil- or gas-bearing zones by plotting deepinvestigation resistivity values against sonic-log transit times. The ordinate scale is proportional to (l/R)“.
Determination of Rt. Conventional resistivity logs can provide for the value of R, only for thick beds, since the readings in general cannot be reasonably corrected for the effect of adjacent formations. The long lateral, because of its large radius of investigation, is practically unaffected by the mud column and the invaded zone and gives a good approximation of R, when the beds are reasonably uniform over a thickness of at least 30 ft. Such favorable conditions are seldom met in practice. The long-normal reading usually requires a correction for the borehole effect. This correction is sufficiently accurate in fresh mud. The reading is close to R, when the bed thickness is at least 10 to 15 ft and invasion is shallow. The effect of deep invasion can be accounted for, to some extent, by means of departure curves. 31,32 Correction for invasion requires the help of other devices with shorter radii of investigation (ML and/or short normal), which provide values of the invaded-zone resistivity. The advantage of the ILD and the LLD is that under usual conditions of application their readings are practically unaffected by the mud column or by the adjacent formations for bed thicknesses greater than about 5 to 6 ft. The ILd, with the present technique, is appropriate for logging in fresh mud. Its accuracy is excellent for formations reading up to 50 0-m and reasonable up to 200 n-m. Above that figure the accuracy is not so good. The ILd gives R, when the invasion diameter does not exceed 25 to 40 in. and can be corrected for deep invasion. The auxiliary readings are the ML and/or the short normal, or better, the LL8 or SFL, particularly in case of consolidated formations.
PETROLEUM ENGINEERING
49-28
The LL is the essential tool for the logging of hard formations in salty mud. It gives R, for shallow invasion (d; less than 15 to 25 in.). Correction for invasion is made with the help of the MLL or MSFL. The most efficient way to correct for invasion and thus obtain R, is the use of a three-log combination: (1) DIL or dual induction/SFL in fresh muds and in soft and intermediate formations and (2) dual laterolog/R, in hard formations or salty muds. The so-called “butterfly or tornado charts” in Ref. 2 provide a simple procedure to obtain R,.
HANDBOOK
SATURATION DETERMINATION
Rwc
Maximum Producible Oil Index If the porosity, 4, of a formation is uniform and intergranular, the quantities S,4 and S,$ represent the amounts of water per unit of bulk volume present in the pores of the flushed and uncontaminated zones, respectively. The difference Y=(S,, -S,)+ is the amount of oil per bulk volume displaced by the mud filtrate. Y is called “maximum producible oil index” because it approximates the maximum amount of oil per bulk volume producible with water drive. Y is given approximately by the equation 29
Y=@ lh-(-+) %..
.......(15)
Evaluation of Y by this equation does not require a direct knowledge of porosity, 4, formation saturation, S,, or flushed-zone saturation, S,, (or ROS). Ratio Methods It is impossible, in the space available, to present all loginterpretation techniques or to present all charts and tabulations made up thereof. For the practicing log interpreter most of the charts needed are included in Ref. 2. The R,IR, Method. For clean formations, saturations can be computed from the empirical relationship found by combinations Eqs. 5 and 6,
Fig. 49.37-Interpretation chart for RJR, and shaly-sand methods. (Working lines illustrate example of Fig. 49.38).
treme cases shaly oil sands are hardly differentiated from the adjacent shales on the logs. Furthermore, the ML does not show much separation between the curves. Interpretations in shaly sands, therefore, are generally made under comparatively unfavorable conditions. The practical method of interpretation described hereafter is quite approximate and is applicable only when the amount of shaliness is not too great.* The practical method of interpretation in shaly formations33 is based on the observations made on field logs that in 100% water-saturated shaly sands the PSP (pseudostatic SP) is given by Epsp=-Kc
sw=sxo(~.~) ‘A. ...
.. . .. (16)
Any method which gives correct values for R,, , R,, R mfi and R, may be used to determine S,, provided S,, is known or can be reasonably surmised. The chart of Fig. 49.37 provides a convenient way for solving Eq. 16. The ratio R&R,* is entered in abscissas (upper scale) and the ratio RIO/R, in ordinates. From the point so plotted, an oblique line is extended up to its intersection with the edge of the chart; from this intersection, a horizontal line is drawn which gives the values of S, for different values of S,, . The value of S, found directly by interpolation between the two nearby oblique lines is based on the assumption that S,, , on the average, is related to 5, through the empirical equation S,, = a,. Within the limits where R ,+ = R,, (i.e., R, between 0.08 and 0.3 O-m at 75”F), the Essp can be entered, instead of R&R,, using the lower grid. Microlog Shaly-Sand Method. The amplitudes of both the SP deflection and the resistivities are reduced by the presence of interstitial shale in a formation. In some ex-
R log?, Ro
_.
(17)
For an interlaminated sand-shale formation containing oil and/or gas, the PSP can be expressed by the equation E PSP=-Kr.
R logf-201srK,. ,
lo+,
. 1,
where asp is the SP reduction factor and is defined as Epp/E~p. For clean sands, asp = 1 and Eq. 18 reduces to Eq. 17 as a special case. According to Eq. 18 the determination of S,,, in a shaly sand requires the knowledge of R,, , S,, , R,, E,, and ESSP. The Essp can be determined from clean sands reasonably close to the shaly formations considered. The Epsp is given by the deflection of the SP curve at the level of the bed, after correction for bed thickness, if necessary. The value of S,,, =l -S,,, again must be surmised. The solution of the equation for S,,. is given by Fig. 49.37, which applies to both clean and shaly formations. For a shaly sand, the PSP and R,,/R, are first entered in abscissa and ordinate, respectively. This gives us the ap‘Sane
other shaly-sand
references are Refs. 8 and 9.
ELECTRICAL LOGGING
49-29
__- .___L__._.._
Fig. 49.38-Shaly-sand example: induction-electrical survey and microlog-microcaliper survey in well on Louisiana Gulf Coast. I?, = 1.45, R,, = 1.2, and R,, = 1.3 at BHT (14OOF). d= 83/i in.
parent saturation. To find the true saturation, a line is drawn through the origin (circled), and the point representing the apparent saturation; and this line is extended until it intercepts the Essp or the corresponding value of R,fIR,. The saturation at this point is treated in the same manner as in the R,,IR, method above. If the Essp is not known and R,%,is unobtainable, it is not possible to determine the water saturation, S,,.. Nevertheless, plotting the ratio R,,IR, vs. PSP on Fig. 49.37 will show whether or not the sand falls on the 100% water-saturation line. If it falls some distance below this line, there is a chance for production. Note that in sand-shale laminations the value of S,,, is the water saturation of the sand itself. In sands containing disseminated shale, it is the water bound by the quartz grains and does not include the water held by the colloids. Example Problem 1. Fig. 49.38 shows the IEL and the ML over a portion of a well in Jefferson Davis Parish, LA. The shaly sand from 8,046 to 8,054 ft will
be interpreted. The mud resistivity at formation temperature of 140°F is 1.45 Q-m, R,, = 1.3 Q-m, and R,,,,= 1.2 9-m at 140°F. Bit size is 8% in. From the IEL, the Epsp is -55 mV. The Essp (sand at 7,830 to 7,850 ft) is - 130 mV. Thus cusp is 0.42. The short-normal resistivity R 16 is 2.2 n-m, and the induction-log resistivity R,L is 1.9 B-m. Invasion is known to be quite shallow, as further substantiated by the readings of the microlog. Therefore R,L may be taken as equal to R,. As shown by the positive separation on the ML, three distinct porous intervals, A, B, and C, appear between 8,046 and 8,054 ft. The values of R,, and h,, for each interval are found by use of Fig. 49.31. Thus, for Interval A R,, is 4.0, for Interval B it is 5.6, and for Interval C it is 6.8. The average R,, is 5.5, and for all three intervals the mudcake thickness is % in. Note that the microcaliper indicates a hole diameter of 7 3/4in., exactly 1 in. smaller than bit size, corresponding to a %-in. mudcake, thus verifying the h,, values from Fig. 49.3 1.
49-30
PETROLEUM ENGINEERING
HANDBOOK
!jFF 40” INDUCTlOrJ - 16”NORMAL SATURATION DETERMINATION THICK BEDS OF LOW AND MEDIUM RESISTI , I 3 4 5 6jBYlO
I 2
I IO’
9 _ INTERPRET ONLY B ~. SHOWN PERMEAbu BY MICROLOG 7 _ 6 BO NOT -. USE ~~~ WHEN R,,/R,<~ FOR d, = 3d, -4 \
-
q
* SCALES
~APPROXIMAT
3
K,= 70 80 90 100
NOTE NON lN;ADED WATER SANDS OF LOW RESISTIVITY WILL GIVE THEY ARE USUALLY RECOGNIZED BY NEGATIVE SEPARATION ON MICROLOG. IN ANY CASE NO OIL HAS BEEN FOUND BELOW 0 7 OHM Fig. 49.39-40-in.
induction log, l&in.
normal interpretation chart. (Working lines il-
lustrate example of Fig. 49.40.)
All necessary data are now at hand: R x0 R,(=R,L) E PSP E SSP asp K, R,r,IR, R.,,,lR,,,f
= 5.5 D-m = 1.9 n-m -55 mV = - 130 mV = = 0.42 = (for the SP) at 140°F is close to 79 = 2.9, and = 4.6
Fig. 49.37 is entered with R,,IR, =2.9 and PSP= -55 at K, =79, locating a point on the chart. Then a line is drawn through this point from the origin and extended until it intersects the vertical line erected at Essp = - 130 mV for K, =79. This intersection gives a value of S, equal to 43 %, assuming that S,, is 15%, which is reasonable. The sand was perforated from 8,046 to 8,050 ft and made 75 BOPD and 280,000 cu ft/D gas through a 7/64-in. choke. IEL Interpretation Method. A chart for practical interpretation of fluid saturation from the readings of the IEL combination is shown in Fig. 49.39, Ref. 2. The conditions limiting valid use of the chart are: (1) the invasion diameter di must be between 2dh and 1Odh (dh is the hole diameter), (2) R,, must be greater than R,, which is generally fulfilled if R,,fIR, is greater than three to live, as for fresh muds and saline formation waters, and (3) the beds must be fairly homogeneous-i.e., the short-
normal reading must not be perturbed by the presence of resistive streaks. The chart incorporates approximate compensation for the presence of an annulus, assuming equal viscosities for the oil and water and an S,, in the flushed zone of 15 to 30%. To use the chart the value of the ratio R~~IRIL (resistivity fmm 16-in. normal divided by the IL resistivity), corrected, if necessary, for effect of borehole and adjacent formations, is plotted either vs. the SSP (lower grid) entered opposite the appropriate formation temperature or vs. R,fIR, (upper scale). Points falling within the shaded area correspond to water-bearing sands. Points falling below the shaded area correspond to oil saturation. Approximate saturation scales are provided for dj values of 3dh and 5dh. The dashed lines represent lines of equal saturation on the chart. The critical saturation corresponds to S,U=60% in soft formations and 50% in consolidated sandstones. These may not be the correct critical saturations for many limestones. For shaly formations a construction like that used in the shaly-sand method can be used in Fig. 49.39. Although not rigorously correct, this procedure should give acceptable results if the shaliness is not too great. Since it is not always known beforehand whether the interpretation chart (Fig. 49.39) is within its limits of applicability, it is useful to employ the value of porosity or formation factor, when known from independent sources, to check the results by means of Eq. 5. Details of this “porosity balance” check are given in Ref. 34.
49-31
ELECTRICAL LOGGING
Fig. 49.40-Induction-electrical log and microlog-microcaliper log on a well in Young County, TX. I?,,, = 0.95 and R ,,,, = 0.61 at BHT (117OF). d= 7% in.
Example Problem 2. Fig. 49.40 shows part of the induction-electrical log and ML on a well in Young County, TX. The sand at the bottom of the figure is divided into two parts, A and B, by a thin, hard streak, as shown on the ML. A and B will be interpreted separately. Necessary well data are R, =0.95 and R,,lf=0.61, at BHT of 117°F; hole diameter, d,, , is 7% in. log, Interval A. From the induction-electrical RIL=17.5 R-m, R16=32.5 R-m, SP=-95 mV, and BHT is 117°F. Applying Fig. 49.39, the ratio R,6IR1~=32.5/17.5=1.85. The SP is -95 mV, so the point is fixed on the chart, giving an average S, of about 30 % . Interval B. Here the RIL=26.0 R-m and R16=37.0 n-m. R161RIL=37.0/26.0=1.42. The SP is -90 mV at 117°F. This fixes a point on Fig. 49.39, which gives a value of S, of about 25 % . Drillstem tests on the two intervals showed that the sand contained gas and distillate, with a higher flowing pressure over Interval B. Rocky Mountain Method. The Rocky Mountain method*’ was developed for the interpretation of conventional electrical logs to yield values of S, and 4 in invaded, clean, hard formations when they are sufficiently thick and homogeneous. It is necessary that the invasion be such that the average resistivities recorded by the short normal and the lateral (when corrected for borehole effect) approximate the average values of Rj ami R,, respectively. For this to be true, the short-
normal readings should be at least 10 times the mud resistivity. Only average values, over thick intervals, can be obtained with this method.
FRRwi
Ri= F,
. . . . . . . . . . . . . . . . . . . . . . . . . . . (19)
where: 1. R,i is the resistivity of the water found in the invaded zone. It is usually made up of filtrate and interstitial (connate) water mixed in such proportion that
(1-fw) . . . . . . . . . . . . . . . . . . 1 fw -, -=-+ Rwi Rw Rnzf
(20)
wheref, is the fraction of interstitial (connate) water in the total mixture (usually 5 to 10%). 2. Si is the water saturation in the invaded zone. It has been found by experience that Si * =S,; so Ri=FR,ISw. Inasmuch as R,=FR~IS,*, we obtain S,=(RiIR,)t(RwiIR,). Since R,IRwi =f,+(l -f,)R,/R,,,f, it follows that R,iIR, is a function of the SP value. The upper part of Fig. 49.41 gives a graphical solution of the equation for S,. The SP is entered in ordinate and the ratio RiIR, on oblique lines. The intersection gives the abscissa S,. The lower part of the chart is used to obtain the porosity by using the water saturation, S,, just found, with the
PETROLEUM ENGINEERING
49-32
HANDBOOK
dipole moment is made up of one or more effects: electronic, ionic, interfacial, and dipolar. Since each of these dominates over a certain range of the electromagnetic spectrum, they can be separated experimentally. * The electronic contribution results from the displacement of electron clouds, and is the only one that operates at optical frequencies. The ionic and interfacial contributions come from displacement and movement of ions, hence arc confined to low frequencies. The dipolar contribution is from permanent electric dipoles, which orient themselves in the direction of an applied electric field. With the exception of water, there are very few materials abundantly found in nature that have permanent electric dipoles. A borehole dielectric measurement in the 109-Hz frequency region, where the dipole polarization of water dominates, should lead to a measurement of water content that is independent of salinity. Table 49.3 gives laboratory-measured values of propagation time and dielectric permittivity (relative to air) of typical reservoir materials.
Fig. 49.41-Interpretation chart for Rocky Mountain method.
value of R,IR,. The intersection falls on or between oblique lines that are graduated into porosity values, according to the Humble formula, Eq. 2. This method should not be used in salt muds. Electromagnetic
Propagation Tool
Principle. The EPT’” (electromagnetic propagation too13’) measures the travel time and attenuation rate of an electromagnetic wave through the formation near the borehole. In addition, a caliper and a ML can also be recorded. The tool can be combined with the gamma ray, neutron, or density instruments. The propagation time of water differs sharply from those of gas, oil, or matrix rock and is, moreover, little affected by the salinity of the water. This tool permits the evaluation of water saturation that is relatively independent of water resistivity (salinity) and, in fact, is most accurate in the fresher waters. Dielectric permittivity is one of the main factors determining electromagnetic propagation in a material. Dielectric permittivity of any medium is proportional to the electric dipole moment per unit volume. The electric TABLE 49.3-ELECTROMAGNETIC PROPAGATION VALUES
Gas or air Oil Water Quartz Limestone Dolomite Anhydrite
Relative Dielectric Permittivity,
Loss-Free Propagation Time, t,,
1.o
3.3 4.9 25-30 7.2 9.1 6.7 6.4
2.2 56-60 4.7
7.5 6.9
6.5
Tool. The tools now in the field carry two transmitters and two receivers on a wall-contact pad, configured as shown in Figs. 49.42 and 49.43. These transmitters and receivers must be antennas to operate as they do in the microwave frequency range. The tool uses a differential measurement based on the signals detected by near and far receivers, similar in principle to the widely used method of measuring At with a two-receiver sonic tool. In a similar manner, the two receivers produce cancellation of any effects caused by mudcake or variations in signal coupling (so long as both receivers are affected equally). To reduce any error caused by sonde tilt, the EPT uses an antenna configuration similar to the transducer array used in a borehole-compensated sonic tool. Transmitting antennas are placed above and below the receiver pair and are pulsed alternately. Simple geometric considerations show that if these two transmission modes arc averaged, the first-order effects of pad tilt will be eliminated. The basic principle of the tool involves a surface or lateral electromagnetic wave launched along the surface of a conducting pad. In the absence of mudcake, the electromagnetic wave would move along the pad face past two receiving antennas, but in the normal borehole case with mudcake present, propagation takes place on the surface between mudcake and formation. The phase shift and attenuation per unit distance along the surface of the pad are proportional to E and C (as shown in theory) for a plane wave. It has been demonstrated both theoretically and experimentally that for mud cakes up to % in. the travel time measured by the EPT is essentially the same as the travel time in the invaded zone without any mud cake. Above such thickness the measurement deteriorates rapidly until the tool responds only to the mud. Limited experience with air- and oil-based mud-filled tools indicates that even very thin layers of these fluids between the pad and the formation cause the tool to respond only to the fluid and not the formation. This is because of the short travel time of these fluids. The tool contains a 1 .l-GHz microwave transceiver. The transmitter is capable of generating more than 2 W of output power
ELECTRICAL LOGGING
49-33
while the receiver can process a 0.3 pico watt (pW) signal. This allows accurate measurements in formations when R, approaches 0.3 a-m. Theory. Assuming a plane wave varying sinusoidally in time, the electric field, E, at the second receiver is given by E=E,,e -‘YL+bJt>
..........................
(21)
where E, is the electric field at the first receiver; L is the distance between the two receivers; j is the vectorial operator fi ; o is the angular frequency; t is the time of travel of the waves over a distance L in the formation; and y is the complex propagation factor given by y=cY+jp,
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..(22)
where CY is the attenuation factor (coefficient) in neper/m, and /3 is the phase factor in rad/m. For a “lossless” formation,* or=O. From Eq. 21, the phase velocity vPO is given by L
Cd 1 -=Vpo=t= Yo tPo
. . . . . . . . . . . . . . . . . . . . . (23)
where the subscript o indicates loss-free conditions and tpo is the loss-free propagation time of a given medium in ns/m. From Maxwell’s equations, it can be shown that y. =jw& =jwtpo, . . . . . . . . . . . . . . . . . (24) where µ is the magnetic permeability (H/m). Since most formations of interest are nonmagnetic, µ of the formation is the same as that of free space (µO =47rX 10-7 H/m), and E is the dielectric permittivity (F/m). When the formation is lossy, y and E are complex. *Formation with no electromagnetic energy losses
Fig. 49.42—Schematic of EPT antenna pad, showing principle of 2-receiver measurement of transit time.
Fig. 49.43—The EPT antenna pad.
49-34
PETROLEUM ENGINEERING
Squaring Eq. 22 and Eq. 24 and equating the real and imaginary terms, we have w2/.Loc=p2 -a?,
.....
. . .. ..
. (25)
....
(26)
and wp,C=2aUp,
...
where C is the equivalent conductivity (a/m) of the losses in the formation. Dividing Eq. 25 by w2, p2 Poe=--- w2
From Eq. 24, 40~=tpo2. Since filw=t,l time in the lossy medium, a2 2I?--* w2 . tpo - tp1
.. . ..... ...
is the travel
..
. (28)
Interpretation. The range of travel time encountered in the borehole in common reservoir rock varies from 6.3 ns/m for a 40-pu sandstone filled with hydrocarbons to 17.2 ns/m for a 40-pu water-filled limestone. In terms of phase shift, this corresponds to angles between 100 and 270” when computed over a 4-cm receiver spacing. The EPT log responds primarily to the bulk volume of water in the formation. Since the tool has a relatively shallow depth of investigation-about 1 to 6 in. depending on the conductivity-it normally responds to the flushed zone of an invaded section. Eq. 28 can be transformed into
lh .
.... ....
. . . . (29)
The apparent water-filled porosity (dEPT) can be derived in a way similar to the derivation of the porosity from sonic At. Thus 4 EPT
tpo- tpm =
.
. . . . . . . . . . . . . . . . . . . . .
.
tpo -tpm
+d’(tpm
-tph)
4(tp,, _ tph)
, ...
. . . . (32)
where tph is the propagation time for hydrocarbon and 4 is the porosity of the formation. Since tpm and tph are fairly close, we can estimate S,, roughly as
S,= !-.
where T is the temperature. “F. Knowledge of water salinity is not required to obtain r,,,,.,,. Smce 3 neper = 6.666 dB, A ,og =6.66&t
. . .
. .... .... ..
.(33)
4 Example Problem 3. Fig. 49.44 is an example of the log presentation currently in use. Track 1 contains a conventional caliper curve, taken from the motion of the backup pad, and the attenuation curve, scaled in dB/m. Tracks 2 and 3 are given to the principal measurement, travel time (tp/), in ns/m. Track 3 also presents the signal levels from the two receivers. The chief use of these curves is to monitor the primary signal detection at the receivers, which provides an indication of the relative reliability of the log parameters at any level. A self-evident and very real advantage may be inferred from the 4-cm spacing between receivers; the tool has excellent vertical resolution. The log of Fig. 49.44 actually looks overactive in spots, but its repeatability testifies that the recording is valid. In fact, the data recorded by the tool are too detailed for direct merging with other logs by means of computer. Averaging (smoothing) subroutines are thus required preliminaries for programs using EPT data. Example Problem 4. Fig. 49.45 shows an ISF log and the porosity computed from density. neutron, and EPT logs. Zone A is obviously gas bearing, as evidenced by the neutron porosity reading much less than the density. The EPT porosity is a little higher than the neutron porosity and much less than the density porosity, confirming the presence of hydrocarbons. Zone B exhibits a different porosity profile. Once again the neutron porosity is less than the density porosity, indicating the presence of some light hydrocarbons, but now the EPT porosity is less than both neutron and density pomsities. Since the total porosity from neutron and density logs is roughly $N+~D 4=-,
tpwo, the loss-free propagation time of water, varies with the temperature and slightly with pressure and can be obtained as
and A ,~~ IS dWm
or
(30)
tpwo - tpm
*a I” neperlm
. . (31)
+(l -Sxo)4tph f(1 -+p,, tpo= Sxo4tpwo
.
Remembering that 01is the attenuation factor, Eq. 28 implies that the actual propagation time in a conductive formation is longer than that of a corresponding loss-free formation. If the propagation wave is not a plane wave, suitable spreading-loss corrections to the measured attenuation (A,,,) are made before Eq. 28 is applied. Thus the corrected attenuation A,. =Aiog -G,Y (dB/m) where G,, is the geometrical spreading loss and AI,,~ the recorded attenuation in dB/m. G,? is about 50 dB/m in air or G,f =45.0+ 1.3r,/ +O. 18r,/. Here tp/ is the recorded travel time in ns/m.
tpo= (tJ-&)
The loss-free propagation time of matrix, tpm, is indicated on Table 49.2. The nature of the matrix can be determined by the knowledge of the apparent matrix density and interpolating between lithology density values. The water saturation S,, is given by
s.w =
a2 ,2 . . . . . . . I.. . . . . . .
HANDBOOK
2
and the hydrocarbon volume is
the volume of hydrocarbons affecting the three porosity tools is about the same for Zones A and B as determined from the EPT data. However, there is a much stronger light hydrocarbon effect on the neutron and density logs in Zone A. Thus, it would be expected that Zone B contains more condensate or oil than Zone A.
49-35
ELECTRICAL LOGGING
3
Attenuation, dB/m
5n Caliper -----------w---.
Travel
Time,Jt,l
1, nsec/m
5oc l5l
c-
-
e3 -
i
-
-
-
Fig. 49.44-An unaveraged EPT log shows fine detail. Repeat sections (faint curves) of the attenuation and t,, curves show excellent repeatability.
49-36
PETROLEUM
GAMMA RAY
I
CALIPER ________
+40
1 ~1~0
t
!F:
“6--w----------cb EPT
HANDBOOK
Zone C appears to contain some residual hydrocarbons, since the EPT porosity is often slightly less than the neutron and density porosities. There is a little more hydrocarbon in the shalier bottom part of Zone C than in the cleaner top portion. The very top of Zone D contains oil since the EPT measurement is much lower than the neutron and density porosities, which read about the same. Water-bearing zones are identified when the EPT porosity is about the same or higher than the neutron and density porosity. Thus, Zone E is clearly water bearing, as is the bottom of Zones B and D. Machine programs are available to give complete quantitative interpretation of all these logs. This is especially important in the study of tar sands or crude oils where the hydrocarbon is not flushed by the mud filtrate and where S,, is very near S, . These studies arc also of great interest to provide values of residual oil saturations.
0
60 _----
ENGINEERING
SAND
0
The Digital Age Before 1960, all logs were recorded in analog form on film or paper. Magnetic tape recording was introduced in 1960 to record dipmeter. Shortly thereafter, various other logs were also recorded on tape, thus permitting the use of computers for various purposes. Before long, computers were made an intrinsic part of the recording systems on the logging trucks. This has revolutionized the capacity for data acquisition at the wellsite. At the same time, many computer-processed products have become available in real time or only a short time after logging is completed at the wellsite.
I---
Fig. 49.45-ISF
and EPTICNLIFDC
logs.
TABLE 49.4-WELLSITE Generic Name R...”
Derivation Assumes all formations contain 100% water. Computes apparent R w, R wa = R ,/F
Uses deep resistivity and shallow focused resistivity to estimate RJR, ratio.
ANALYSIS
Log Input Required
AVAILABLE
IN REAL TIME
Presentation
Sinale curve in Simultaneous Track 1 on resistivity and logarithmic porosity. Usually sonic and scale. inductlon Simultaneous deep Single curve in resistivity and Track 1 shallow focused compatibly n=sistivity scaled as a pseudo SP
Schlumberger
Gearhart
Deep resistivity and porostty
Compatible porosity scales
Any combination of porosity logs with same lithology assumptions to compute porosity.
Simultaneous porosity logs
Hole volume
Uses caliper logs to compute hole volume for cement calculation.
Caliper curvepreferably 2 curves at 90° such as 4.arm dipmeter
Fracture locating log
Uses differences in adjacent pad readings from 4-arm dipmeter to infer fractures.
&arm dipmeter
Single dashed curve in Tracks 2 and 3 on logarithmic scale. Coded curves in Tracks 2 and 3 with gamma ray and caliper in Track 1. Pips or tic marks in depth column at every 10 cu ftand 1OOcu ft Adjacent pad readings are superimposed and any separation is coded.
Welex
R wa
R *a
R,
Ro
“F” curve
“F”
Compatible porosity scales
Compatible porosity scales
Compatible porosity scales
Compatible porosity scales
Borehole volume
Borehole volume
Borehole volume
Borehole volume
Fracture identification 109
Fracture detector log
Fracture locahon @I
Dipmeter fracture 109
R,IRt
curve. overlay or Derives F from a porosity curve that IS played onto logarithmic resistivity as R,. “Ro ” overlay
“F”
Dresser ______
R wa
R,,, .._
Curve
ELECTRICAL
49-37
LOGGING
TABLE 49.5-WELLSITE Derivation
Generic Name Merged and depth shifted data
ANALYSIS
AVAILABLE
Log Input Requrred
Replays all logs, shifts depths and makes sample calculattans such as R,,, R xo, R,/Rr, compatible porosity scales or cross plot porosities.
Any logs run on tape.
Wellsite Uses all logs to provide a first order evaluation log computer analysis.
Resistivity and porosity
Formation dip computations
Computes formatron dtp from 4-arm dipmeter
4-arm dipmeter
True vertical depth log
Computes lVD of any point from dipmeter orientation data
Contmuous dipmeter plus any log to be converted lo TVD
IN REPLAY”
Presentation Usually 3 to 5 tracks. Varies by service company, diplays only log data. Usually 3 or 4 tracks. Has reservoir data derived from log data. Formation dip, hole deviation, calipers. Replay of any log on TVD scale
TIME
Schlumberger
Gearhart
Dresser
Welex
Cyberlook Pass 1
cross-plot (x-plot)
Prolog
Computer Van
Cyberlook
Well evaluation log
Prolog
CAL
Cyberdip
FED DDL
Pro-Dip
TVD
TVD
TVD
‘All logs available in real time are also avarIable in replay time If recorded on magnetic tape
Without any doubt, the digital age is responsible for the creation of new equipment deemed impossible before. Many interpretation techniques and studies today could not be made without the use of computers. Finally, electronic transmission of log data is a present reality, facilitating exchange between wells and offices, towns and continents. An overview of this vast field is necessary. Magnetic Tapes API-recommended standard format permits logging service company tapes to be read by most computers. More exhaustive treatment of the subject is available directly from the service companies. Quality control of the magnetic tape is ensured in real time in integrated logging systems having on-board computers. Computed Log Products Log analysis performed by a computer is available to the log user at three different levels.
TABLE 49.6-LOG Generic Name
ANALYSIS
Derivation
AVAILABLE
1. Real-time “quick-look” products, summarized in Table 49.4, run at the same time the log is being run. Many of these curves, such as R, and F curves, are recorded on the standard logs and are often placed in the SP or resistivity tracks. 2. Wellsite log analysis products, summarized in Table 49.5, are generally available at the wellsite in replay time. Wellsite analysis is made after the logging is completed. The process involves playing back taped logs and using an appropriate log analysis program, such as a shaly-sand analysis or a dipmeter computation. 3. Computing center products am provided well after the logging is finished (days or weeks later) and are generally more comprehensive than either of the wellsite products. In general, these computations fall into three categories: shaly-sand analysis, complex lithology study, and dipmeter processing. The most-used products are summarized in Table 49.6. Other, less frequently used products such as tar sand analysis or mechanical properties are not included; details on these may be obtained directly from the service company.
FROM COMPANY COMPUTING CENTERS
Log Input Required
Advanced sandstone analysis
Uses most sophisticated analytical and statistical methods to correct and compute logs in sandstones and shaly sandstones.
Rssistivhy, density, neutron, gamma ray with sonic desirable
Advanced carbonate analysis
Uses most sophisticated analytical and statistical methods to correct and compute logs in carbonate and lithologically complex reservoirs
Advance dipmeter computations
Uses most advanced correlation logic to compute dips followed by a statistical sorting to retain the most reliable data.
Resistivity, density, neutron, gamma ray with sonic and microresistivity desirable *-arm dipmeter
Presentation
Schlumberger
Usually 4 tracks SARABAND presentation YOUN of lithology, saturation, porosity and bulk volume. Usually 4 tracks COAIBAND presentation of lithology, GLOBAl. saturation, porosity, and bulk volume. Arrow plot with CLUSTER caliper, (structural) and correlation GEODlP curve and (stratigraphic) hole deviation. Also available: azimuth frequency, modified Schmidt plots, histograms, and listings.
Gearhart
Dresser
Comsand
EPILOG
“F” Pairs
Sandstone Analysis
Comlith
EPILOG
Frax
Complex Reservoir Analysis
NEXUS
Dresser computed dipmeter
Welex CAL
CA,
Diplog analysis
PETROLEUM
49-38
ENGINEERING
HANDBOOK
PASS ONE
CO#fNSAlED DENTaT
fUHATlCW4 mrom
COM?ENSATED NElJmoN
Fig. 49.46-CYBERLOOK
An
example
of
wellsite log analysis is the 36 which requires as a minimum suite of logs a deep investigation resistivity, CNL”-FDC” (compensated neutron/density logs), a gamma ray, or SP curve. The CYBERLOOK computation is based on the dual-water model and is normally made in two passes. On the Pass One log (Fig. 49.46), the SP curve is on Track 1 with the gamma ray. On Track 2, in four cycles, are found the R, curve, the R, (computed fmm R,), and the porosity given by the CNL. Track 3 shows the porosity given by the density, 40, the porosity given by the neutron, fpN, and a cmssplot porosity computed from CvBERLOOK"pmgram,
‘#‘D ami ‘#‘N.
On Pass Two log (Fig. 49.47), the Track 1 gives the shale index, which is the minimum shale index of several shale indicators obtained from the SP curve, the gamma ray, and the maximum and minimum neutron readings. Track 2 shows R, as a dashed curve and Ro as a solid
roIosm
Pass One log.
curve. The left half of Track 3 has the water saturation and the right half has the porosity and bulk volume free water. A differential caliper is presented as a dotted curve with bit size in the middle of Track 3. A gas flag appears in the depth track when a large hydrocarbon correction was necessary to obtain the porosity from neutron/density logs. VOLAP is an example of a complex analysis program (Fig. 49.48). It is based on the dual-water model, as is the CYBERLOOK program mentioned previously, but the computations are far more refined and the results more accurate. For a detailed study of the dual-water model, see Refs. 37 and 38. The dual water model simply says that in a shaly sand, its equivalent formation water conductivity is dependent on the relative amount of “bound” water and “free” water. The conductivity of the bound water is found by the use of the nearby shale resistivity and the total porosity given by the average of CNL. In a like manner, the free
ELECTRICAL
LOGGING
49-39
CYBERLOOK WIT RESISTWIlY owIu Y* Y GRAIN DtWTY --------
v (*
DEEP RENTIVITY
WATER ,oQ) ,JANRAllON 1
(AUPoI
POROWY ANALYSJS (-) M SIZE
----
640
Fig. 4%47-CYBERLOOK
water conductivity is found by use of the resistivity of the clean water sand and its total porosity. In a shaly water sand, the equivalent water conductivity is found in the same way by using the resistivity of the shaly water sand and its total porosity. Knowing the bound and free water conductivities, it is easy to compute their fractions of the total porosity that are necessary to obtain the same equivalent water conductivity of the shaly water sand. The fractions of bound and free water can be related to the relative deflections of the gamma ray or SP curve, etc., thus permitting the use of such calibrations when analyzing hydrocarbon saturated zones. The analysis is done by using a dispersed-clay-type equation.
Nomenclature a,,f = chemical activity of mud filtrate a,. = chemical activity of formation water
Pass Two log.
A,. = corrected attenuation of a formation A log = recorded attenuation of a formation C = equivalent conductivity of losses in the formation C,t = conductivity as given by induction log CT = total conductivity signal Ci = conductivity of invaded zone C, = conductivity of mud C, = true conductivity of formation c x0 = conductivity of flushed zone E = electric field E,. = total electrochemical EMF EJ = liquid-junction EMF EM = shale-membrane EMF Epsp = pseudostatic SP Esp = static SP
PETROLEUM
49-40
tllOli POROSITY
PRESENTATION
+
-
~ i
l
+++
1 Fig. 49.48-High-porosity
presentation.
K,. = m = n = R, = R = i: = RIL = RpL = R, = R,,. = R4 = R, = R, = R = RI = R i:
= =
RI,1 R2 R 16 Si S,, S, S x0
= = =
= = = = = ‘ph tP/ = = tPm = tPo tpwo = Y= “SP = y = t = p = 4~ = WEPT = $HC = 4~ = w =
ENGINEERING
HANDBOOK
electrochemical coefficient cementation exponent or factor saturation exponent apparent resistivity annulus resistivity corrected resistivity induction-log resistivity proximity-log resistivity resistivity of invaded zone resistivity of mudcake resistivity of mud filtrate true formation resistivity formation-water resistivity equivalent formation-water resistivity resistivity of the water found in the invaded zone resistivity of flushed zone resistivity of a clean (nonshaly) formation saturated with 100% water resistivity of 1- X 1-in. microinverse resistivity of 2-in. micronormal short-normal resistivity water saturation in the invaded zone residual oil saturation formation water saturation water saturation in the flushed zone propagation time for hydrocarbon travel time in the lossy medium loss-free propagation time of matrix loss-free propagation time loss-free propagation time of water maximum producible oil index SP reduction factor complex propagation factor relative dielectric permittivity magnetic permeability density porosity electromagnetic propagation tool porosity hydrocarbon porosity neutron porosity angular frequency
Abbreviations En = electric field at the first receiver FR = formation resistivity factor FR,\ = resistivity factor of formation water FR,,, = resistivity factor of water in invaded zone f,,. = fraction of interstitial (connate) water in the total mixture Gi = geometrical factor of invaded zone G,, = geometrical factor of mud G,j = pseudogeometrical factor of the invaded zone G,! = geometrical spreading loss G, = geometrical factor, true formation G,,, = geometrical factor of flushed zone iR = resistivity index j = vectorial operator J-l
CNLTM = DIL = EPT = ES = FDC ‘rM= ID = IEL = IES = IL = ILd = IM = ISF = LL = LLD = LLS = ML =
compensated neutron log dual induction-laterolog 8 electromagnetic propagation tool electrical survey compensated density log deep-reading induction device induction-electrical log induction-electrical survey induction log deep induction log medium-reading induction device induction spherically-focused log laterolog deep laterolog shallow laterolog microlog
ELECTRICAL
MLL MSFL PL SDL SFL SSP
= = = = = =
microlaterolog shallow MICROSFL proximity log simultaneous dual laterolog spherically focused log static SP
References I. Dunlap,
49-41
LOGGING
H.F. and Hawthorne. H.R.: “Calculation of Water Resistivities from Chemical Analysis,” J. Per. Tech. (July 1957) 202-17; Trans., AIME, 192. 2. a. “Log Interpretation Charts,” Schlumberger Well Services (1979). b. “Log Interpretation Charts,” Dresser-Atlas (1981). c. “Charts for the Interpretation of Well Logs,” Welex (1979) EL-1002. d. “Chart Book.” Gearhart (1982). 3. Lamont. N.: “Relationships Between the Mud Resistivity, Mud Filtrate Resistivity, and the Mud Cake Resistivity of Oil Emulsion Mud Systems,” J. Pet. Tech. (Aug. 1957) 51-52; Trans., AIME. 210. 4. Mounce, W.D. and Rust, W.M. Jr.: “Natural Potentials in Well Logging,” Per. Tech. (Sept. 1943); Trans., AIME. 6. 5. Winsauer, W.O., er al.: “Resistivity of Brine-satured Sands in Relation to Pore Geometry,” Bull., AAPG (Feb. 1952) 253-77. 6. patnode, H.W. and Wyllie, M.R.J.: “Presence of Conductive Solids in Reservoir Rocks as a Factor in Electric Log Interpretation,” J. Pet. Tech. (Feb. 1950) 47-52; Trans., AIME, 189. 7. Archie. G.E.: ‘Classification of Carbonate Resetvotr Rocks and Petrophysical Considerations,” Bull., AAPG (Feb. 1952) 36, 218-98. 8. Waxman, M.H. and Thomas, E.C.: “Electrical Conductivittes m Shaly Sands-I. The Relation Between Hydrocarbon Saturation and Resistivity Index; II. The Temperature Coefficient of Electrical Conductivity,” J. Pet. Tech. (Feb. 1974) 213-23; Trans., AIME, 257. 9. Waxman, M.H. and Smits, L.J.M.: “Electrical Conductivities in Otl-Bearing Shaly Sands,” Sue. Pet. Eng. J. (June 1968) 107-22; Trans., AIME, 243, 10. Kunz, K. and Moran, J.: “Some Effects of Anisotropy on Resistivity Measurements in Boreholes,” Geophpics (Oct. 1958) 23, 770-94. II. Doll, H.G.: “Filtrate Invasion in Highly Permeable Sands,” Pet. Engr. (Jan. 1955) 27, BJ3-66. 12. Gondouin, M. and Scala, C.: “Streaming Potential and the SP Log.” J. Pet. Tech. (Aug. 1958) 170-79; Trans., AIME, 213. 13 Hill, H.J. and Anderson, A.E.: “Streaming Potential Phenomena in SP Log Interpretation,” J. Pet. Tech. (Aug. 1959) 203-08; Truns., AIME, 216. 14. Wyllie, M.R.J.: “Investigatron of Electrokmetic Component of the Self-Potential Curve,“J. Pet. Tech. (Jan. 1951) l-18; Truns., AIME, 192. 15. Wyllie, M.R.J., de Witte, A.J.. and Warren. J.E.: “On the Streaming Potential Problem in Well Logging,” Trans., AIME (1958) 213, 409-17. 16. Wyllie, M.R.J.: “Quantitative Analysis of the Electrochemical Component of the SP Curve.” J. Per. Tech. (Jan. 1949) 17-26: Trans., AIME, 186. 17. Segesman, F. and Tixier, M.P.: “Some Effects of Invasion on the SP Curve,” /. Pet. Tech. (June 1959) 138-46; Trans., AIME. 216. 18. Doll, H.G.: “SP Log: Theoretical Analysis and Principles of lntetpretation,” J. Pet. Tech. (Sept. 1948) 146-85; Truns., AIME, 179. 19. Goudouin, M., Tixier. M.P., and Simard. G.L.: “Experimental Study on Influence of Chemical Composition of Electrolytes on SP Curve,” J. Pet. Tech. (Feb. 1957) 58-72: Trans., AIME. 210. 20. Doll, H.G.: “Introduction to Induction Logging and Application to Logging of Wells Drilled with Oil-base Mud.” J. Pet. Te&. (June 1949) 148-62; Truns.. AIME, 186. 21. Dumanoir, J.L., Tixier. M.P.. and Martin, M.: “Interpretation of the Inductton-Electrical Log in Fresh Mud,” J. Pet. Tech. (July 1957) 202-17: Trans., AIME. 210.
22. Doll, H.G.: “Laterolog-A New Resistivity Loggmg Method with Electrodes Using an Automatic Focusing System,” J. Pet. Tech. (Nov. 1951) 305-16; Trans., AIME, 192. 23. Doll, H.G.: “Micro Log-A New Electrical Logging Method for Detailed Determinations of Permeable Beds,” J. Pet. Tech. (June 1950) 155-64; Trans., AIME, 189. 24. Doll, H.G.: “The MicroLaterolog,” J. Per. Tech. (Jan. 1953) 17-32; Trans., AIME, 198. 25. Tixier, M.P.: “Electrical Log Analysis in the Rocky Mountains.” Oil and Gas J. (June 1949) 48, 143-48. 26. Tixier, M.P.: “Porosity Index in Ltmestone from Electrical Logs,‘, Oil and Gas J. (Nov. 1951) 140-42, 169-73. 27. Wyllie, M.R.J.: “Procedures for the Direct Employment of Neutron Log Data in Electnc Log Interpretation,” Geophysics (Oct. 1952) 17, 790-805. 28. Tixier, M.P., Alger, R.P., and Tanguy, D.R.: “New Development in Induction and Sonic Logging,” J. Per. Tech. (May 1960) 79; Trans., AIME, 219. 29. Doll, H.G. and Martin, M.: “How to Use Electric Log Data to Determine Maximum Producible 011 Index in a Formatton.” Oil ad Gas J. (July 1954) 53, 120-26. 30. Tixier, M.P.: “Evaluation of Permeability from Electric Log Resistivity Gradient,” Oil and Gas J. (June 1949) 48, 11323. 31. a. “Resistivity Depanure Curves,” Bull., Schlumberger Well Surveying Corp. (1949). b. “Interpretation Charts for Electric Logs and Contact Logs,” Bull, Welex Inc., A-101. 32. a. “Resistivity Depanure Curves (Beds of infinite Thickness).” Bull., Schlumberger Well Surveying Corp. (1955). b. “Fundamentals of Quantitative Analysis of Electric Logs.” Ed., Welex Inc., A-132. 33. Poupon, A., Loy, M.E., and Tixier, M.P.: “A Contribution to Electrical Log Interpretation in Shaly Sands,” J. Per. Tech. (June 1954) 138-45; Trans., AIME, 201. 34. Tixier, M.P.: “Porosity Balance Verifies Water Saturation Determined From Logs,” .I. Pet. Tech. (July 1958) 161-69; Truns., AIME, 213. Propagation Logging: 35. Wharton, R.P., er al.: “Electromagnetic Advances in Technique and Interpretation,” paper SPE 9267 presented at the 1980 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 21-24. 36. Best, D.L., Gardner, J.S., and Dumanoir, J.L.: “A ComputerProcessed Wellsite Log Computation,” paper presented at the 1978 SPWLA Annual Logging Symposium, June 13-16. 37. Coates, G.R., Schulze, R.P., and Throop. W.H.: “Volan*-An Advanced Computational Log Analysis.” paper presented at the 1982 SPWLA Annual Logging Symposium, July 669. 3x. Clavier. C.. Coates. G.R., dnd Dumannir. J “Thcorcticai and Expertmental Bases tar the Dual-W&r Model for lntcrpretation 01 Shaly Sands,” Sw. Prr. E,tg. J. (April 1984) I S3-6X.
General References Alger, R.P.: “Interpretation of Electrical Logs in Fresh Water Wells in Unconsolidated Formations,” paper presented at the 1966 SPWLA Annual Logging Symposium, Tulsa, OK, May 8-l I. “Departure Curves for Laterolog,” mg Corp. (Aug. 1952).
Bull., Schlumberger Well Suney-
DeWttte. L.: “A Study of Electric Log Interpretation Methods in Shaly Formations,” J. Per. Tech. (July 1955) 103-10; Trans., AIME, 204. Doll. H.G.: “SP Log in Shaly Sands.” 205514; Trun.~. I AIME, 189. Guyed, H.: “Electric (1955) 615-29.
Tech.
Analog of Resistivity Logging,”
Guyed. H.: “Electric Log Interpretation,” “Guyed’s
J. Per.
Electrical Well Logging,”
(July 1950)
Grophwics
Oil Week/~ (Dec. 1955).
Bull., Wellex Inc.. A-132.
“Interpretation Handbook for Resistivity Logs,” Bull., Schlumberger Well Surveying Corp. (1949).
PETROLEUM
49-42
Johnson, H.M.: 507-27.
“A History of Well Logging,”
Jorden, J.R. and Campbell, F.L.: Well Logging Borehole Environmenr,
Mud and Temperature
Geophysics
I-Rock Logging,
(1962)
Properties,
Monograph
Series, SPE, Dallas (1984). Keller, G.V.: “Modified Mono-Electrodes for Improved Resistivity Logging,” Prod. Monthly (July 1950) 14, 13-16. Kewer, J.K. and Pmkop, C.L.: “Effect of the Presence of Hydmcarbons on Well Logging Potential,” Oil and Gas J. (Dec. 1955) 102-06.
ENGINEERING
HANDBOOK
Mayer, C. and Sibbit, A.: “Global, A New Approach to Computer Processed Log Interpretation,” paper SPE 9341 presented at the 1980 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 21-24. Millican, M.L., Raymer, L.L., and Alger, R.P.: “Wellsite Recordings of the Movable Oil Plot,” paper presented at the 1964 SPWLA Annual Logging Symposium, Midland, TX, May 13-15. Morris, R.L. and Biggs, W.P.: “Using Log-Derived Values of Water Saturation and Permeability,” paper presented at the 1967 SPWLA Annual Logging Symposium. Pitson, S.J.: “Formation Evaluation by Log Interpretation,” Oil (May 1957) 170-83.
World
Lipson, L.B. and Overton, H.L.: “The Effect of Treating Agents on the Electrochemical Activities of Drilling Mud Filtrates,” paper SPE 867G presented at the 1957 SPE Annual Meeting, Dallas, Oct. 7-10.
Tixier, M.P., Morris, R.L., and Connell, J.G.: “Log Evaluation of Low Resistivity Pay Sands in the Gulf Coast,” Log Analyst (Nov./Dee. 1968).
“Log Interpretation, Vol. I-Principles, Vol. II-Applications,” Bull., Schlumberger Well Services (1974).
Wyllie, M.R.J.: The Fundamentals of Electric Log Interpretation. ond edition, Academic Press Inc., New York City (1957).
sec-
Chapter 50
Nuclear Logging Techniques Darwin V. Ellis, Schlumberger-Doll Research*
Introduction In this chapter, the use of nuclear radiation in wireline logging will be presented. To avoid repetition, the reader is referred to Chap. 49 for a basic introduction to the principles of wireline logging in terms of the operation and genera1 types of devices used in the area of electrical logging; Chap. 51 discusses the third major areaacoustic well logging. To introduce the general subject of nuclear logging, it is appropriate to provide a motivation for the use of nuclear measurement techniques in well logging. This can be done best by constructing a list of petrophysical parameters of interest in the evaluation of hydrocarbonbearing formations. In the most straightforward application, the purpose of well logging is to provide measurements that can be related to the volume fraction and type of hydrocarbon present in porous formations. In the case of openhole logging (as distinguished from measurements made in a production well with steel casing), there are four principal parameters of interest: (I) presence of hydrocarbons, (2) porosity, 4, (3) water saturation, S,, and (4) permeability, k. To this list, additional parameters or descriptors can be added: (5) lithology, (6) clay identification, and (7) pore fluid identification. For cased-hole logging the same list of petrophysical parameters of interest may hold, but with perhaps more emphasis on fluid identification.
Relationship of Petrophysical Physical Parameters
Parameters and
These petrophysical parameters of interest are derived normally from a number of measurements provided by logging services. For the moment, we will concentrate on some bulk physical parameters associated with them that may be amenable to measurement through the use of nuclear techniques. ‘Aulhcf of the original chapter on this toptc in the 1962 edition was John L.P. Campbell.
Presence of Hydrocarbons. An obvious method for the detection of hydrocarbons is based on their chemical compositions. Since there is no oxygen in most hydrocarbons, the ratio of the atomic concentration of carbon to oxygen for a hydrocarbon is significantly different from the ratio for most sedimentary rocks and formation fluids. Thus, a measurement of the ratio of the number of carbon atoms to oxygen atoms (C/O) contained in a formation would indicate directly the presence of hydrocarbons when no carbon is present in the matrix. This is to be contrasted with the method of electrical measurements, where detection of hydrocarbons is based on the contrast of conductivities between saline water and hydrocarbon in a porous medium. Porosity. The porosity
or nonmatrix portion of a rock sample can be determined from a measurement of its bulk density. The fundamental equation that relates the bulk density, Pb, to the solid matrix, which has a density pmrr, and the porosity or volume fraction, $, which contains a fluid of density pf, is Pb=&f+(l-~)Pma.
___.
. ...(l)
From this relationship, the porosity, 4, can be determined from a measurement of bulk density, assuming that the matrix density and fluid density are known. These will be known with any precision only if the fluid type and properties and the lithology are known. In practical terms, the density range of fluids is between 0.8 and 1.2 g/cm3 (although calcium chloride solutions may reach 1.4 g/cm3), and most matrix densities are between 2.60 and 2.96 g/cm3. Another means of detection and quantification of porosity is based on the fact that the formation porosity is filled with liquid or gas, all of which contain disproportionate amounts of hydrogen. This hydrogen may be
50-2
PETROLEUM ENGINEERING
associated with the brackish formation water or with the hydrocarbons. Thus, detection of hydrogen is a means of inferring porosity in an otherwise solid rock matrix.
Hydrocarbon Saturation. The determination of hydrocarbon saturation can proceed once the porosity of a formation has been determined. It can be done (1) by the direct measurement of C/O and comparison to the value expected for fully oil- and water-saturated cases, or (2) by a more indirect measurement of the effective salinity of the formation in question. Permeability.
There is no clear-cut physical parameter amenable to nuclear measurements that will predict formation permeability accurately. However, there is one measurement technique-nuclear magnetic resonancethat can be related to permeability; it is discussed in Chap. 53.
Lithology,
Clay Types,
and Fluid
Identification.
These parameters have been grouped together because of a common approach for their determination, which is basically some aspect of their chemical composition. There are two principal interests in identifying the lithology. One is for a reasonable matrix density to be assigned to a formation so that porosity can be extracted from the density measurement. The other is to provide identification of formations for use in well-to-well correlation. Since the neutron properties of rocks are somewhat dependent on the type of lithology, it is possible to determine the three principal lithological matrices by comparison of the gamma ray attenuation and neutron-slowing-down properties of the medium. Wellto-well correlation often is done most simply by comparison of the natural radioactivity of the formations. However, a more direct approach for the identification of the lithology (i.e., sandstone, limestone, or dolomite) is not based on the density but rather on the unique chemical composition of each of these matrices. One method of identifying the lithology would be to make a chemical identification of the various elements associated with the matrix. Another slightly more refined approach to the determination of the lithology depends on another bulk property of the material: its average atomic number. The average atomic number of the formation, which reflects to some extent the lithological composition, can be obtained by measuring the lowenergy gamma ray absorption properties of the material. Identification and quantification of clays are much more difficult, since the chemical compositions of clays are so varied. Hence, the chemical composition of clays is a key to their detection. A measurement of the presence of elements such as Al, Si, Fe, and K must be counted as a means to their identification. An earlier technique, which measured the total natural gamma ray activity of earth formations, was based on the fact that the naturally occurring radioactive daughter products (subsequent products of radioactive decay of an element) of uranium, thorium, and potassium were associated with clay minerals. Sometimes, however, one or more of these elements (U, Th, K) is present in a formation containing no clay. Examples of this include the case of potassium feldspar in the rock matrix or uranium dissolved in the formation water.
HANDBOOK
A third property of clays is the great abundance of hydrogen associated with the clay mineral structure. Thus, detection of the presence of hydrogen is another means of clay identification. Pore fluid identification is based on indirect measurements and inferences. The presence of gas in the formation pores will have a significant impact on the bulk density for reasonable porosities as well as on the neutron-slowing-down properties. The distinction between oil and water again is measured most directly by the atomic C/O density ratio or based on the thermal neutron absorption properties of the water phase, which generally contains chlorides Fig. 50.1 summarizes the relationships between petrophysical descriptors and physical parameters, which can be determined quantitatively through the use of nuclear radiation and measurement techniques. A third column has been added to indicate the additional information necessary to interpret the suggested bulk property measured to obtain the desired petrophysical descriptor.
Physical Parameters and Nuclear Radiation Before presenting the basic nuclear phenomena necessary to describe the operation of most of the common nuclear logging devices, we need to link, in general terms, the physical parameters discussed previously to the types of general nuclear techniques that will be described later in mote detail. To be specific, it should be pointed out that the types of nuclear radiation used in well logging are gamma radiation and neutrons. These two types of penetrating radiation are the only ones that are able to traverse the pressure housings of the logging tools and the formation of interest and still return a measurable signal. It is for this reason that (Yand fi radiation are of no particular interest for exploring formation characteristics; their penetration ranges are much too small to be of any practical use. In the preceding section, it is clear that many of the proposed parameters to be measured are. in fact, no mom than the chemical composition of the earth formation. Instead of the obvious but time-consuming and expensive chemical analysis of formation samples, a technique of gamma ray spectroscopy can be used. This is based on the fact that the nucleus of any atom, after having been put into an excited state by a previous nuclear reaction, can emit gamma rays of characteristic energies, which uniquely identify the atom in question. Gamma ray spectroscopy refers to the detection and identification of these characteristic gamma rays. Another use of gamma rays is in conjunction with the measurement of bulk density. The bulk density of a material has a significant influence on the scattering and transmission of gamma rays through it. At very low energies, the transmission of gamma rays is influenced additionally by the chemical composition. This additional absorption is related to the atomic number, Z, of the absorber. The interest in using neutrons in well logging techniques comes from several properties of their interaction with matter. First, the transmission and moderation of neutrons are influenced by the bulk properties of the medium and, in particular, by the amount of hydrogen present. The scattering of neutrons by hydrogen is very
50-3
NUCLEAR LOGGING TECHNIQUES
Petroph ysical Descriptors
Necessary Additional Information
Physical Parameter
I Lithology
Cl0 Ratio I
Bulk Densitv
w
Lithology
t
Porosity
Hydrogen Content
Apparent Salinity Bulk Density
I
/
Hydrogen Content Average Atomic
Lithology
Number, Clay Identification
Th, U, K Ca, Si, S, Fe Al,
Fig. 5&l--Relationship
.
between petrophysical descriptors and measurable physical parameters
efficient in reducing the neutron energy. Second, interaction of high-energy neutrons with certain nuclei can excite characteristic gamma rays for subsequent elemental identification by gamma ray spectroscopy. At very low energies, neutrons can be absorbed, thereby reducing the flux, and as a byproduct, another set of characteristic gamma rays may be emitted. Some of these capture gamma rays are emitted after some delay and are referred to as activation gamma rays. So there are two types of measurements that can be based on the use of neutrons: the scattering or slowing-down properties of formations and neutron production of gamma rays (either by absorption or inelastic high-energy reactions with elements) of characteristic energies for use in spectroscopic identification. Fig. 50.2 illustrates the types of nuclear measurement techniques that can be used to measure physical parameters related to the relevant petrophysical descriptors sought.
Nuclear Physics for Logging Applications Nuclear Radiation Nuclear radiation refers to the transport of energy by a nuclear particle. In the earliest investigation of radioactive materials, three types of radiation were identified
and named, quite unimaginatively, CY,/3, and y radiation. It subsequently was discovered that (Yradiation consisted of fast-moving He particles stripped of their electrons and that /3 radiation consisted of energetic electrons. The gamma rays were found to be packets of electromagnetic radiation, also referred to as photons. The discovery of this radiation then provoked its quantification, namely the measurement of the amount of energy transported. The unit chosen is known as the electron-volt (eV), which is equal to the kinetic energy acquired by an electron accelerated through an electric potential of 1 V. For the types of radiation discussed in the following sections, the range of energies is between fractions of an eV and millions of electrons volts (MeV). Another convenient multiple for discussing gamma ray energies is the kiloelectron volt (keV). Since a! and /3 radiation consist of energetic charged particles, their interaction with matter is primarily ionization. That is, they interact with the electrons of material by losing energy rapidly during their passage and transferring it to electrons. In most materials their range is rather limited and is a function of the material properties (2, the atomic charge or number of electrons per atom, and its density) and the energy of the particle. They consequently have not been of any practical impor-
PETROLEUM ENGINEERING
50-4
Nuclear Measurement Technique or Parameter
Physical Parameter
:
HANDBOOK
l Induced
,C/O Rati?:-
Inelastic
Gamma Ray Spect.
I @Gamma Ray Attenuation Neutron Slowing-Down Length Hydrogen Capture Gamma Ray Spect. *Induced Apparent
Salinity*
Bulk Density Average
Atomic
Th. U, KF
b Thermal
Neutron
Gamma Ray Spect. Absorption
X-Section
6 Gamma Ray Attenuation
;~;i. ” ..’
b Gamma Ray Photoelectric
Number “.““.
Inelastic
‘-.
Absorption
Natural Gamma Ray Spectroscopy )lnduced Activiation
Capture Gamma Ray Spect. & High Resolution
Spect.
w Gamma Ray Attenuation b Neutron
Diffusion
Length
*Thermal
Neutron
Absorption
Capture
Gamma
---+
Chlorine
X-Section
Ray Spect.
Fig. 50.2-Nuclear measurement techniques linked to measurable physical parameters of petrophysical interest.
tance for well logging applications. Gamma rays, on the other hand, are extremely penetrating radiation, which makes them of great importance for well logging applications. Radioactive decay of certain naturally occurring substances such as radium was responsible for the developments mentioned and needs further discussion. Radioactive decay is a time-varying pmperty of nuclei whereby a transition from one nuclear energy state to another
lower
one is made spontaneously.
The result
. ..
.
.
.
dN= - AdrN,, ,
For a collection of Np dN, is just
.... .........
resulting in the expression
for radioactive
.
...
(3)
decay, namely
is
that the excess energy is shed by the nucleus by one or more of the types of radiation previously mentioned. The basic experimental fact of radioactivity is that the probability of any one nucleus decaying, within an interval of time dt, is proportional to dt-i.e., it is independent of external influences, including the decay of another nucleus. This probability is proportional only to the time interval of observation. So for a single radioactive atom the probability P(dt) of decaying in the interval of time dr is expressed as P(dr)=Xdr,
where X is the decay constant. particles, the number decaying,
.(2)
where N,, now is the number of particles remaining at time r, of the initial number of particles Ni . The constant of proportionality, X, is related parameter, the half-life, t ,,z, by
0.693 tlh =-. h
to the better-known
. . . . . . . . . . . . . . . . . . . . . . . . . . (3
NUCLEAR LOGGING TECHNIQUES
No physical quantity can ever be measured exactly, but in the case of nuclear processes where the number of events observed is small, randomness is important. The practical complication of this statistical process of nuclear decay is that only the bulk or average properties can be predicted with any certainty. We can talk only about the measurement of a group of particles together and the distribution of the measured value about some mean. TO understand one important property of nuclear radiation, it is necessary to digress a moment for a quick review of the binomial distribution, which was discovered in the 18th century by Bernoulli. It describes the probability, P, , that an event that has a probability P of occurring will occur x times when the observation is repeated z times. The probability thus specified was identified with the binomial expansion of (P+q)i, where
q=l-P,
x a
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...(6) Number of Occurrences, x
so that the general term of the expansion
p,=
-P”( z! x!(z-n)!
1 -,)ZPX,
Fig. 50.3-The Poisson distribution for the case of mean value (CL)of 100. The probability, P,, is shown for values of x around the expected mean value.
is
..,......
. . . (7)
which gives the probability of x occurrences in z trials. This expression can be applied to radioactive decay, in which P, represents the probability of having x nuclei decay in time dt when there are z atoms present. For this case, generally the probability P is very small but the number of particles observed (z) is very large so that Eq. 7 simplifies to e-P P,=/L~--,
x.I
.. .
. . .
.(8)
which is known as the Poisson distribution. It gives the probability of observing x decays in a given time where an average of ji decays is to be expected. Fig. 50.3 shows the general form of the Poisson distribution with the maximum probability at the mean value, which was taken as 100 for this example. The curve resembles the usual bell-shaped distribution curve with a width specified by a parameter u, the standard deviation. The practical importance of this discussion is that the Poisson distribution that appropriate u for the characterizes the statistics of counting random nuclear events is not an independent parameter (as is the case for most measurements) but is related to the mean value ,% by
0=x$
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...(9)
This means that if N,. counts from a radiation detector are expected per time interval, then, in repeated observations, about 32% of the measurements will deviate beyond the value of N, + 6. This is a quantitative description of the statistics associated with all nuclear logging techniques.
There have been a number of clever techniques for dealing with the statistical fluctuations inherent in nuclear counting rates. Probably best known is the R-C circuit, which has a time constant associated with it and permits the recording of a continuous moving average. There are now more modem digital signal processing techniques (such as Kalman filtering) to provide more refined filtered counting rates or outputs derived from statistically varying counting rates. However, the only sure approach to reduce the fluctuations is to increase the average number measured, either by using higher-output sources, more efficient counters, or longer counting times per sample.
Particle Reactions. There are certain nuclear particle interactions of interest to well logging. To discuss these as necessary in the following sections, a few mathematical definitions are presented here to help the mechanisms of the reactions. As in radioactive decay, the process of nuclear reactions is also statistical in nature. The question of interest is how readily these reactions will take place. Fig. 50.4 shows the idealization of the nuclear reaction process. A beam of radiation (it may be gamma rays or neutrons) of an intensity pi is seen to enter the slab of material. The intensity of the radiation, 9 i , is called the flux and has units of numbers of particles per unit surface area per unit time. The slab of material is characterized by N,, the number of particles per unit volume with which the flux of radiation may interact. The experimental fact observed is that after passing through a slab of material of thickness 6/z, a certain fraction of the incident particles have undergone interactions, and that number is proportional to the thickness and the number of target nuclei and the incident flux. This is expressed mathematically as 6\k=a~Np6h,
..
..
..
. (10)
50-6
PETROLEUM ENGINEERING
N, nuclei cm3
Fig. 50.4-Idealized view of nuclear radlation interactlng with matter showing the reduction in flux traversing a thickness of material characterized by the number of interacting particles per cubic centimeter.
where the constant of proportionality, (T, is called the cross section of the interaction. The units of this microscopic cross section u are area/interacting target nucleus. Cross section is used because in a classical sense it is the apparent area each target nucleus presents to the incoming beam. In effect, it collects all the nuclear interaction details into one useful number. The practical unit is called the “barn” and is equal to lO-24 cm’. The macroscopic cross section, C, is the product of (Tand N, and has the dimension of area/particle times particles/volume or inverse length. In practical terms, C can be calculated easily because Ni, is related to Avogadro’s number, NA , and the material density, ph. by
N*=%P,, M
.
. ..___...____.__.
(11)
where M is the molecular weight of the target for a single particle per molecule. In general, the cross sections for most reactions must be determined experimentally and are often available in graphical or tabular form. The quantity &N,, in Eq. IO has dimensions of (cm” . set) - ’ and has the interpretation of the reaction rate per unit volume resulting from the incident flux.
Nuclear Reactions. To discuss the second type of radiation of great importance to well logging applications-neutrons. which are not the result of naturally occurring radioactive decay schemes-a brief discussion of artificial or induced radioactivity is given here. The classic reaction that inspired the discovery of the neutron was the bombardment of beryllium by alpha particles and can be written as
9Be+4He+
“C+n+5.76
MeV.
.(12)
HANDBOOK
This forms the basis for the cheapest, easiest, and most reliable method for neutron production. The physical explanations of this reaction are beyond the scope of interest of the present work and may be found in Refs. 1 and 2. The practical construction of a neutron source consists of finding a naturally occurring cr emitter and mixing it with an appropriate light element having a large (cy,n)* cross section. Some possibilities for (Yemitters are Pu, Ra, Am, and PO. Three target elements are Be, B, and Li. The actual spectrum (energy distribution) of emitted neutrons is quite complicated and depends somewhat on the geometric details of the cy emitter and target; but generally speaking, the peak of the neutron distribution is around 4 MeV. Another method of exploiting particle-induced reactions is by use of charged particle accelerators. In one realization currently used in well logging, deuterium and tritium ions are accelerated toward a target impregnated with the hydrogen isotopes deuterium (D) and tritium (T). The reaction is written as D+T-+4He+n+
17.6MeV.
.
. .(l3)
The cross section for this reaction has a maximum at about 100 keV of D projectile energy, which dictates the accelerating voltages in such a device. Despite the engineering difficulties of constructing such a device, the advantages for logging are many. One is the relative high energy of the produced neutrons. They are emitted at 14.1 MeV (nor 17.6 MeV, because some of the energy of this reaction is given up to the alpha particle). These high-energy neutrons are useful for producing other interesting nuclear reactions in the formation, as discussed later. The other advantage is that a source of this type can be controlled-i.e., switched off and on at will. This provides a degree of safety unparalleled for radioactive sources as well as opening the door to measurements involving timing as a means of determining some interesting nuclear properties of the formation. Now that we have covered the two types of nuclear radiations currently used in logging devices, let us examine how gamma rays and neutrons interact with matter and define some macroscopic properties of matter that can be used to characterize this behavior.
Fundamentals
of Gamma Ray Interactions
For the purposes of our discussion there are three types of gamma ray interactions that are of interest: the photoelectric effect, Compton scattering, and pair production. The type of interaction a gamma ray will undergo depends on the properties of the material and the energy of the gamma ray. The ordering of these three interactions reflects the transition of the dominant process as the gamma ray energy increases. The photoelectric effect concerns the interaction of a gamma ray with an atomic electron in the material. In this process the incident gamma ray disappears and transfers its energy to the bound electron. Depending on
‘This shorthand (a, n) tndlcates a reamon of an /a parWe wth an unspec,f,ed nucleus, n. resulttng I” the produclm of a neulron and anolher uns,,ec,f,ed nucleus.
NUCLEAR LOGGING TECHNIQUES
50-7
the energy of the incident gamma ray, generally the electron is freed from its nucleus and begins collisions with the adjacent material. Normally the ejected electron is replaced by another electron with the accompanying emission of a characteristic fluorescence X-ray with an energy dependent on the atomic number of the material and generally below 100 keV. The cross section for the photoelectric effect, P,,~~, varies strongly with energy. falling off as nearly the cube of the gamma ray energy (EGO). It is also highly dependent on the atomic number (Z) of the absorbing medium. In the energy range of 40 to 80 keV, the cross section per atom of atomic number Z is given by
0.1
.Ol
Fig. 50.5~Regions
cc0
N A =u&Ap~Z,
.
.
(15)
The final Z factor in this equation takes into account that there are Z electrons per atom. Consequently, the attenuation of gamma rays resulting from Compton scattering will be some function of the bulk density (ph) and the ratio of Z/A. The fact that Z/A = % for most elements of interest is the basis for the determination of bulk density from gamma ray scattering devices. The third and final gamma ray interaction is that of pair production. It, like the photoelectric process, is one of absorotion rather than scattering.” In this case the ceam1
Ray Energy
10
100
(MeV)
of dominance of the three major gamma ray
interactions in terms of the gamma ray energy, E,,. and the atomic number, 2, of the target material. The two lines separating the three regions indicate where the two adjacent interactlons occur with equal probability.
(14)
For most earth formations the photoelectric effect becomes the dominant process for gamma ray energies below about 100 keV. The photoelectric effect is an important process in understanding one of the conventional gamma ray detection devices and a well logging tool” that is sensitive to the lithology of the scattering formation. The tool in question makes a measurement of the photoelectric abto the sorption factor, F,, , which is proportional photoelectric cross section per electron. Since this quantity is very sensitive to the average atomic number of the medium, Z, it can be used to obtain a direct measurement of the lithology of the scattering medium. This is because the principal rock matrices (sandstone, limestone, and dolomite) have considerably different photoelectric absorption characteristics and the pore fluids play only a minor role because of their low Z’s, The Compton scattering process involves the interaction of a gamma ray and an electron. It is a process in which only part of the gamma ray energy is imparted to the electron and the energy of the gamma ray, consequently, is reduced. Unlike the photoelectric effect, the probability for Compton scattering changes relatively slowly with energy. To see the bulk effect of Compton scattering in a material consisting of nuclei of atomic mass A and atomic number Z, one can use the linear absorption coefficient, which is just the Compton cross section, gc(,, multiplied by the number of electrons per cubic centimeter:
1.0
Gamma
ma ray interacts with the electric field of the nucleus. and if the gamma ray energy is above the threshold energy of 1.022 MeV, it disappears and an electron/positron pair is formed. The subsequent annihilation of the positron (positively charged electron) results in the emission of two gamma rays of 5 1 I keV each. The cross section of this process is somewhat energy-dependent and is zero below the required threshold energy of 1.022 MeV. In addition, it also depends on the charge of the nucleus. To establish the regions of dominance of the three types of interactions, refer to Fig. 50.5. It shows, as a function of gamma ray energy and atomic number of the absorber, the regions in which the probabilities of the various processes are equal. The regions of dominance are quite clear. From the earlier definition of cross section, the fundamental law of gamma ray attenuation can be stated as
‘l’=‘P,e-““h,
_.
_.
_. .
_.
.(l6)
where *; is the flux incident on a scatterer of thickness h, n is the number of scatterers per unit volume, and u is the cross section for scattering per scatterer. In the case of gamma-gamma density devices, the source of gamma rays is chosen to have an energy for which the primary interaction is Compton scattering. In this case the scatterers are electrons and u refers to the Compton cross section per electron. This results in the following expression for the attenuation of the source energy gamma rays:
q~‘=q’,~-~&fW,~h
.
..
.
.
(17)
where h, in this case, is very nearly the source-todetector spacing. It is convenient to define the electron density index as Z pp=2--ph, * n
..
.
.
(18)
50-8
PETROLEUM
ENGINEERING
HANDBOOK
Neutron Speed km/psec)
Photoelectric
Compton
:.
Source
::
2.2-
0.22-
0.1
Gamma
10
1
Ray Energy,
O.il
0.1
t
10
102
103
104
1 keV
MeV
105
106
10'
Energy (eV)
1MeV
for gamma ray
Fig. 60.7-The relationship between neutron energy and speed for the three broad classifications of neutron energies.
so that the attenuation of the gamma rays is seen to be proportional to the spacing, h, between source and detector and the electron density index, which in turn can be related to the bulk density if the properties (specifically Z/A) of the scattering material are known. For most sedimentary rocks the ratio of Z/A is nearly r/z so that p r is very nearly equal to ph. Another unit for measuring the gamma ray attenuation properties of a material is the mass absorption coefficient, K, ,* which regroups the constants in Eq. 17-i.e.,
each one. The reactions of neutrons with matter are much more varied and complex than those of the gamma rays. For simplification we will confine ourselves to four principal types of interactions of neutrons with matter. Fig. 50.7 defines in broad terms the energy range of interest for neutrons. For logging applications it can be seen that the energy range of interest is over about 9 decades: from source neutrons of 5 to 15 MeV in the broad fast neutron range above 10 eV, to epithermal neutrons in the range of 0.2 to 10 eV and thermal neutrons, which are distributed around 0.025 eV at room temperature. To have an idea of the time scale for later discussions of the themralization process, it is useful to note the relationship between neutron energy and its associated velocity. To evaluate the velocity of a neutron, we can use (at low energies) the classical relationship between kinetic energy, Ek, velocity, v, and mass, m,
Fig. 50.6-The mass absorption coefficient interactions in aluminum.
K,=ZNAo, A
.....
.........
. ..I..
. . (19)
so that the gamma ray attenuation equation can be written as *=9$-K-.
.. ..
.. ..
. . . .(20)
The convenience of the mass absorption coefficient for Compton scattering is that it is remarkably similar for all materials since Z/A = % and the density dependence has been eliminated. Fig. 50.6 shows the mass attenuation coefficients (in cm*/& for aluminum. This element, with a density of 2.7 g/cm3 and atomic number of 13, is quite typical of earth formations. The average atomic number ranges from 11 to 16 between quartz and limestone, while the grain densities are between 2.65 and 2.71 g/cm3. Fundamentals
of Neutron Interactions
As in the case of gamma rays, the interaction of neutrons with materials can be categorized by the types of interactions with the appropriate cross sections that describe 'The symbol used in physicstormass absorption cOefflCienl IsP
. . . . . . . . . . . . . . . . . . . . . . . . . . . ..(21)
Ek=%mv2,
so that the velocity,
v= J
2Ek -.
v,
is given by
. .. .. . . ... . ... . . . ... .. . .. . . .
..(22)
m
If this expression for velocity is evaluated for thermal energies (0.025 eV), the result is 2200 m/s or 0.22 cm/ps. Thus, the velocity at any energy E (in eV) is given by
v=o.22
J
E ~o,025’
.. .. . .........
....
NUCLEAR LOGGING TECHNIQUES
where v is the velocity, cm/pLs. Therefore, the speed of an epithermal neutron of 2.5 eV is 2.2 cmips, and for a near-source energy neutron of 2.5 MeV the velocity is 2200 cmips. These velocities are also noted on Fig. 50.7. Of the four principal types of interactions, the first two generally are referred to as moderating interactions, or interactions in which the energy (or speed) of the neutron is reduced. One of these is known as elastic scattering and the other, inelastic scattering. Classical mechanics (elastic billiard ball analysis) can describe the moderating power of the struck nucleus. The energy of the neutron is reduced more efficiently as the mass of the struck nucleus approaches the mass of the neutron. Thus, hydrogen and other low-atomic-mass elements are quite efficient in reducing fast-neutron energy. Fig. 50.8 illustrates, for elastic neutron scattering with several elements, the range of reduction in neutron energy available for a single collision. It is seen that for the most common earth formation elements the maximum energy reduction per collision for the heavy elements is about 10 to 25 %, However, for the case of hydrogen it is seen that the entire neutronenergy can be lost in a single collision. In the case of inelastic scattering, a portion of the energy of the incident neutron goes into exciting the target nucleus. This reduces the energy of the incident neutron and, in addition, the target nucleus usually will produce a characteristic gamma ray upon de-excitation. This type of reaction always has a threshold energy (below which it will not happen) associated with it and is exploited in the measurement of the C/O ratio in earth formations. The second general category of neutron interactions is known as absorptive interactions. The two general types are radiative capture and reactions in general. In radiative capture, unlike the moderating interactions considered above, the neutron (usually near thermal energies) is absorbed by the target nucleus and then disappears, and subsequent characteristic gamma rays are produced. .The general category of neutron reactions is quite broad; it will be sufficient to say that the interaction of neutrons with other nuclei can provoke the emission of other particles such as alphas, protons, /3’s, or even several subsequent neutrons. All these reactions, although common, have a very small probability for happening relative to the other interactions of interest to us and usually occur over a restricted and high-energy range. To show the complexity of the cross sections for neutron interactions see Fig. 50.9, which schematically indicates the variations with energy. The top figure refers to the total cross section as a function of neutron energy, EN, and the four following figures indicate how this can be decomposed. The first line (n,n) refers to elastic scattering, which is shown to be rather constant with energy except for some resonances at low energies. The next line shows inelastic interactions (n,n’) showing some characteristic threshold below which this reaction is not possible; the fourth line is one of the many particle reactions possible (n,(y); and the final line (although there could be others) is the radiative capture (n,?), which is seen to increase in probability at low energies. Despite these complexities, there are some gross properties that can be assigned to materials on the basis of
50-9
0.8
0.6
E/E0 0.4
0
I 10
H
A, Atomic
Fig. 50.8-The
I 40
I 30
1 20
Mass
range of energy reduction possible for neutron
elastic scattering with several important elements for formation evaluation. E, is the energy before scattering, and E is the energy after scattering. Hydrogen is seen to provide the greatest possible energy reduction for a single collision.
Total Cross-Section
11
Elastic Scattering tn. n)
Inelastic Scattering (n, n’)
Reaction ,:“:,
( 1
Neutron Fig. 50.9-A
Energy,
EN
schematic illustration of the components involved for the total neutron cross sectlon as a function of energy. The characteristics of four specific cross sections are shown.
50-10
PETROLEUM ENGINEERING
HANDBOOK
H2O
/ /-,40
p*u. p,u,
,:::i:::-20 \
0 p.u.
0.1 ~ 0.1
1.0
Neutron Fig. 50.10-The
MeV
mean free path of fast neulrons in water and water-filled limestone at several porosities as a function of energy.
their neutron cross sections. The first is the macroscopic cross section, which is defined as the product of the cross section in question times the number of atoms per cubic centimeter, N,-i.e.,
Ei=NpUi=-
10
Energy,
NAPb
CTi. .
. .
. . ..
A The dimensions of the macroscopic cross section C; are inverse centimeters and the interpretation is that its reciprocal is the mean-free-path length in centimeters between interactions of Type i. Frequently in logging, use is made of the macroscopic absorption cross section at thermal energies. The units of this (so-called capture units, c.u.) are just 1,000 times the Cj defined previously, where Ui refers to the thermal absorption cross section, which is dominant at thermal energies for most elements. Fig. 50.10 shows the total mean free path in limestone of 0, 20, 40, and 100 porosity units (PU) as a function of energy for fast neutrons. At the energy of chemical source emission (2 to 4 MeV), it is seen that there is very little porosity dependence. It is only as the neutrons are slowed down that the mean free path becomes strongly porosity-dependent. As mentioned earlier, in the case of elastic scattering. low-mass nuclei are more efficient in reducing the energy of the ccattered neutron. As can be inferred from Fig. 50.8, the result of a collision can be considered. on average, as a percentage decrease of the neutron energy. This
usually is expressed as the average logarithmic energy decrement, [ : =I@;)--in(E)=
-ln(EIE;).
.
.
(25)
It can be shown from classic mechanics that the average log energy decrement is simply related to the atomic mass, A, of the struck nucleus by 2 Fz-.-.A+2/3’
. . . . . . . . . . . . . . . . . . . . . . . . . . . . (26)
for large values of atomic mass A. The average log energy decrement allows an estimation of the average number of collisions, n, to reduce the neutron from an initial energy Ei to some lower energy E from the following reasoning. If the sequence E 1, E2 . . E, represents the average energy after each collision, then we can write
ln(%)
=ln($$.
.F)
=ln($)
’ =n In($)
=nf.
..
. (27)
_.,
(28)
. . . . . . . . . . . . . . . . . . . . . . . . . ..(29)
NUCLEAR LOGGING TECHNIQUES
TABLE CO.l-NEUTRON SLOWINGDOWN PARAMETERS
Moderator H :
Ca Hz0 20-PU limestone 0-PU limestone
t 1.0 0.158 0.12 0.05 0.92 0.514
0.115
14.5
91.3 121 305 15.8 29.7 132
‘Average number of collwons from 4.2 MeV to 1 eV
.Sandstone
Thus, the average number of collisions is given by
. .........................
The constant .$can be computed for a mixture of elements by weighting the value of each 2:i for element i with the appropriate total scattering cross section u;. Table 50.1 shows some typical values for the average logarithmic energy decrement and the number of collisions necessary to reduce source energy neutrons (4.2 MeV) to 1 eV. There are two more parameters that help to characterize neutron interactions with bulk material. One parameter is known as the slowing-down length, L,Y, and the other as the diffusion length, Ld. L,s can be described as roughly proportional to the average distance a neutron (in an infinite homogeneous medium) travels from its emission at high energy until it arrives at the lower edge of the epithermal energy region. This distance can be calculated4 with a detailed knowledge of the cross sections of the constituent elements. Fig. 50.11 shows the variation of L, as a function of water-filled porosity for limestone, sandstone, and dolomite. Ld can be thought of as the distance a thermal energy neutron travels between the point at which it became thermal until its final capture. This distance is given by
Ld=v@E),
30
40
50
60
ID
80
90
Water-FilledPorosity.p.u.
Fig.
50.11-The calculated slowing-downlength, L,. as a function of water-filled porosity for three rock matrices: sandstone, limestone and dolomite.
. . . . . . . . . . . . . . . . . . . . . . . . . . ..(31)
where D is the thermal diffusion coefficient and c is the macroscopic thermal absorption cross section of the material. The diffusion coefficient, D, also can be calculated from the knowledge of the cross sections of the material and is shown in Fig. 50.12 as a function of porosity for the three principle matrices. Since thermal neutrons will be affected strongly by the presence of thermal absorbers, it is interesting to look at an abbreviated list of elements that frequently are found in formations that have large macroscopic thermal absorption cross sections, This is found in Table 50.2, where the units are capture cross section (c.u.) per gram of material. Of particular interest is chlorine, the implication being that salt water will have some measurable effect on the thermal neutron population as well as iron and boron, which frequently are associated with clays.
calculated thermal diffusion coefficient, D, as a function of water-filled porosity for three rock ma-
Fig. 50.12-The
trices: sandstone, limestone, and dolomite.
PETROLEUM ENGINEERING
50-12
Gamma Ray Trajectory
lnsulat& End Plate
Fig. 50.13-Components
I Avalanche Discharge
of a gas-discharge radiation detector.
Photo-Cathode /
Photo-
Nal(TI) Crystal Fig.
Multiplier
Tube
50.14-Schematic of the steps involved in gamma ray detection by the production of a measurable electrical signal in a photomultiplier coupled to an Nal crystal.
Another auxiliary parameter, (L,), has been defined as L; =L;+L~.
..
.
the migration
.
.
length
. . (32)
It can be viewed as a distance that represents the combination of the path traveled during the slowing-down phase (L,) and the distance traveled in the thermal phase before being captured (Ld). The use of this parameter provides a convenient way of predicting the response of a thermal neutron porosity device, which is discussed in more detail in a later section. Nuclear Radiation Detectors Gamma Ray Detectors. The devices for the detection of gamma rays involve the exploitation of one or more of the three processes of gamma ray interactions with matter described earlier. Three general types of gamma ray detectors in current use will be described next. The first variety, the ionized-gas counter, is a direct descendant of the earliest efforts in nuclear radiation detection. The second and most common present-day gamma ray detector used in well logging applications is the scintillation detector. The third type of device, the solid-state detector, is just beginning to be used in logging applications. The common form of the ionized-gas or gas-discharge counter consists of a metal cylinder with an axial wire passing through it (Fig. 50.13) and insulated from it. The cylinder is filled with a gas that is normally nonconduc-
HANDBOOK
tive, and some moderate (several hundreds of volts) electrical potential is maintained between the central wire and the cylinder. The detection process is initiated by the formation of some ionized gas molecules. These freed electrons are accelerated by the radial electric field and in successive collisions produce additional free electrons, which finally results in a measurable charge collection on the central wire. For gamma rays to be detected with such a device, the gas somehow must be ionized initially. Since the gas density is moderate, even at rather high pressure available in commercial tubes, and the atomic number of useful gases is relatively low, there is little possibility of the gamma rays interacting directly with the gas. The main detection mechanism is photoelectric absorption or recoil electron ejection from Compton scattering in the metal shield. For the gamma rays absorbed near the inner radius of the cylinder, there is some probability of the ejected electron escaping into the gas and providing the initial ionization. This also is illustrated in Fig. 50.13. It should be evident from the foregoing discussion that the detection efficiency of such detectors is not high. It can be improved somewhat by the incorporation of conductive high-atomic-number gamma absorbers, such as silver, as an inner lining of the cylinder. Although they can be operated in a proportional mode, the energy resolution of these detectors is not of great practical use. The most positive aspects of gas-discharge counters are their simplicity, ruggedness, and reliability for functioning in the hostile environment of well logging. Because of their poor efficiency and inapplicability to spectroscopic gamma ray detection, they are being replaced rapidly by a newer generation of scintillation detectors. A more common type of gamma ray detector uses a scintillation crystal. Once again, the active detector element is sensitive to ionizing radiation, such as energetic electrons. When these particles travel within the crystal lattice, they impart their energy to a cascade of secondary electrons, which finally are trapped by impurity atoms. As the electrons are trapped, visible or near-visible light is emitted. The light flashes are then detected by a photomultiplier tube optically coupled to the crystal and transformed into an electrical pulse. This is indicated schematically in Fig. 50.14. The output pulse height can be related to the total energy deposited in the crystal by the initial high-energy electron. The great advantage of such a detection scheme is the possibility of performing gamma ray spectroscopy--that is, to detect the actual energy of the incident gamma ray, which, in some cases, will identify uniquely the source of the emitted gamma ray, as in the case of induced gamma ray logging. However, a scintillation detector is a detector of gamma rays only to the extent that an electron is produced in the crystal through one or more of the three basic gam-
TABLE
50.2~-MACROSCOPIC THERMAL ABSORPTION CROSS SECTIONS {X[c.u./(g/cm3)]) Boron Chlorine Hydrogen Manganese Iron
42 300 564 198 146 27.5
NUCLEAR LOGGING TECHNIQUES
ma ray interaction mechanisms: photoelectric absorption, Compton scattering, and pair production. Thus, the gamma ray detection efficiency of a scintillator will depend on its size, density, and average atomic number (for photoelectric absorption). A scintillator in common use is a crystal of sodium iodide doped with a thallium impurity, NaI (Tl), which has good gamma ray absorption properties and a fairly rapid scintillation decay time (- 0.23 psec) to allow for high-counting-rate spectroscopy. The use of such a device for gamma ray spectroscopy implies that the output light pulse is proportional to the incident gamma ray energy; however, this is possible only for the case of total absorption of the gamma ray. Some of the difficulties that can complicate the detected spectrum are shown in Fig. 50.15, for the case of a tool designed to look for the unique gamma rays emitted by inelastic neutron reactions with carbon and oxygen. The figure illustrates what might happen to an inelastic carbon gamma ray that is produced at the site marked (IS) with an initial energy of 4.44 MeV. It first makes a Compton scattering in the borehole fluid (CS) and loses 90 keV of energy before traversing the tool housing and entering the NaI detector with an energy of 4.05 MeV. At the point marked (PP) it suffers a pair-production interaction, producing one electron and one positron with energies of 2.00 and 1.03 MeV, respectively, the missing 1.02 MeV having gone into the creation of the electron/positron pair. Both particles impart their energy to the scintillation process indicated by the dashed lines. When the positron has given up all its kinetic energy, it annihilates with an electron to produce two gamma rays, each of 0.51 MeV energy. One of the gamma rays undergoes Compton scattering at (CS), and the reduced-energy gamma ray (0.41 MeV) is finally absorbed photoelectrically within the crystal at point (Ph.A). The other 0.51-MeV gamma ray is shown escaping the crystal, to the right, and being absorbed in the tool housing without contributing to the total energy transferred to the crystal. The energy recorded by the crystal for the event depicted is 3.54 MeV (4.05 MeV - 1.02 MeV pair-production $0.511 MeV annihilation) instead of the 4.44 MeV that we would like to be measurin Thus, t%.e degradation of the structure of the incident gamma ray spectrum is seen to be inherent in the physics of the many processes involved in the detection. Only if the gamma ray is absorbed totally by the detector is the light output of the scintillator proportional to the incident gamma ray energy. This would be the case for the photoelectric absorption, for example. Fig. 50.16 shows the energy deposited in this case as the single line to the right marked E,. If only a Compton interaction occurs, then a fraction of the energy will be registered. The possible range of energy deposition in this case follows the distribution shown in Fig. 50.16 from zero to the Compton edge, which corresponds to the maximum energy being transferred from the gamma ray to the electron. Additionally, if the gamma ray is of sufficiently high energy there may be a pair-production reaction, and if one or more of the 5 1 1-keV photons escapes the detector without interaction, the so-called first and second escape peaks will be produced in the detected spectrum. Fig. 50.17 indicates the additional distortion introduced by this process. In addition to the distortions in the measured spectrum produced by the possible interactions within the detector,
50-13
Photo-Multiplier
Optical
Coupling
(4. (0.41)
Na(TI) Crystal Reflective
M
Coating
Fig. 50.15~Illustration of the possible sources of gamma ray energy degradation in an Nal detector system.
Light Flashes Produced by Compton Recoil Electrons
Energy Transferred to Crystal
Full Energy l’Photo-Electricll Peak
/
Compton Edge
Ey
Fig. 50.16~Idealized response from a scintillation detector to mono-energetic gamma rays of energy E, showing the photo-peak and the Compton tail.
50-14
PETROLEUM ENGINEERING
HANDBOOK
result is sharp energy resolution. Another result is that the detector must be operated at extremely low temperatures. This is because at room temperatures the electrons have sufficient energy to cross the 0.7.eV band gap and camouflage those freed by gamma ray interactions. Although the gamma ray spectra obtained with Gc detectors are superb, their overall counting rates are less than those obtained by NaI detectors. Application of solid-state detectors is limited to devices concerned with precise spectroscopic elemental definition or in-situ chemical analysis.
Energy
Transferred
to Crystal
Fig. X1.17-Idealized
spectrum distortion in a scintillator caused by pair-production. The highest energy peak corresponds to photoelectric absorption or the full energy of the incident monoenergetic gamma ray, and the two lower energy escape peaks correspond to escape from the crystal of one or two of the annihilation gamma rays of 511 keV.
a dominant perturbation to the measurement is the detector resolution. This refers to the broadening of the line spectra, as can be observed clearly in Fig. 50.17. The width of the observed gamma ray lines is, in the case of an NaI detector, primarily a function of the gamma ray energy, the size of the crystal, and the optical coupling between the crystal and photomultiplier, as well as the characteristics of the photomultiplier. One of the major drawbacks of the scintillation detectors is their poor energy resolution. The reason is that detection in this type of device requires a number of inefficient steps, the result being that the energy required to produce one information carrier (a photo-electron in the photo-multiplier) is about 1,000 eV. Thus, the number of carriers for a typical radiation detection is rather small; the statistical fluctuations on such a small number place an inherent limitation on the energy resolution. The use of semiconductor materials as radiation detectors can produce many more information carriers per detected event and, thus, can achieve a very-high-energy resolution. In a solid-state device such as the germanium detector, the semiconductor properties are used to transfer the charged-particle energy into a usable electrical pulse in a much more direct manner. When a gamma ray interacts with the detector, charged particles are produced. These, in turn, transfer energy to electrons bound (by only 0.7 eV for Ge) in the crystal lattice, enabling many of them to become free. Each free electron leaves a positive hole in the electron structure of the crystal. Under a strong electrical field applied to the detector crystal, the free electrons and holes migrate quickly to the electrodes and create an electrical impulse. The excellent resolution arises because the band gap is so small. About 3.5 x lo5 electrons are freed by the detection of a l-MeV gamma ray to contribute to the resulting pulse with no intervening inefficient steps. The
Neutron Detectors. Neutrons are detected through nuclear reactions in which energetic charged particles are produced. Thus, most neutron detectors consist of a target material for this conversion coupled with a conventional detector, such as a proportional counter or scintillator, to achieve the measurement. Since the cross section for neutron interactions in most materials is a strong function of neutron energy, different techniques have been developed for different energy regions. For well logging applications, at present, it is the detection of thermal and epithermal neutrons that is of interest. The de tection schemes considered in this section are appropriate for these low-energy neutrons. The determination of useful nuclear reactions for neutron detectors involves satisfying several criteria: the cross section for reaction must be very large, the target nuclide should be of high isotopic abundance. and the energy liberated in the reaction following the neutron capture should be high for subsequent ease of detection by conventional means. Three target nuclei have been found generally to satisfy these conditions: “B, ‘Li, and ‘He. In the case of the first two targets, the (n,ol) reaction is used, and for 3He it is the (n,p) reaction. The boron reaction is exploited widely in the form of BF3 in a proportional tube. In this case the boron trifluoride serves as the target and as the proportional tube gas. For this application the gas is enriched in “‘B, to attain a high detection efficiency. Another approach is to use boron as the inner coating of a proportional counter, which may use some other proportional gas more suitable than BFJ for applications involving fast timing, for example. Since a suitable lithium compound gas does not exist, the lithium reaction is not exploited in a proportional counter. However, lithium scintillators, similar to those of sodium iodide for gamma ray detection, are available. Because of the large amount of energy released by the (n,cr) reaction, neutrons are registered at an energy of about 4. I MeV, which provides a means of discriminating against the gamma rays, which also will be detected readily by the LiI crystal. The most common neutron detector in well logging, however, is based on the ‘He (n,p) reaction. In this case ‘He is used as the target and proportional gas in a counter. It is preferred to BF3 because it has a higher cross section than the boron reaction and the gas pressure can be made much higher without degradation of its proportional operation. The overall simplicity of a proportional tube is preferred to the additional complications associated with a scintillator. For the three reactions discussed, the cross sections vary inversely with the square root of the neutron energy 50 that the detection efficiency for neutrons will vary in the same manner. The detectors using these reactions, then,
NUCLEAR LOGGING TECHNIQUES
50-15
are basically thermal neutron detectors. For some logging applications, it is desirable to measure the cpithcrmal neutron flux while being insensitive to thermal neutrons. This can be achieved by making a minor modification to any of the three types of detectors previously mentioned. It consists of using an exterior thermal-neutron-absorbing material with a large cross section, such as cadmium. to shield the detector. Thermal neutrons will be absorbed in the shield, but the reaction particles. whose range is small (on the order of tenths of millimeters). will not reach the counter. The higher-energy neutrons that manage to penetrate the shield will be detected by the thermal neutron detector with somewhat reduced efficiency.
1.46
Nuclear Radiation Logging Devices The logging devices discussed in the following section fall under two general categories: those that measure natural radiation fields and those that produce radiation fields and measure some aspect of their interaction with the formation. The first group contains tools that measure the natural gamma ray activity of earth formations resulting from the spontaneous decay of radioactive materials. The second category can be broken down into the type of radiation used-gamma rays or neutrons. The latter may be subdivided further into the use of chemical or steady-state neutron sources or pulsed particle accelerator-based sources described earlier. Rather than trace the historical development, which has been well documented by Segesman,” only the most recent logging devices will be discussed. Both neutron porosity and gamma-gamma density devices have undergone substantial evolution since their respective introductions as commercial services. The earliest devices invariably used a single detector. As the use of these types of measurements grew, more emphasis was put on improving the quantitative nature of the measurements and a better appreciation of environmental effects was gained. This led to the development of borehole-compensated devices generally using a second detector at a lesser spating from the source that, because of its larger sensitivity to environmental effects, provides a correction to be applied to the principal detector. Gamma Ray Devices There are two series of naturally occurring radioactive isotopes that occur in significant quantities in sedimentary rocks: the uranium and thorium series. The only other significant naturally occurring radioisotope is that of potassium (40K). Clay minerals that are formed during the decomposition of igneous rocks in general have a very high cation exchange capacity. Because of this property they are able to retain trace amounts of radioactive minerals that originally may have been components of the feldspars and micas that go into the production of clay minerals. This process generally results in a higher concentration of radioactive elements in shales than in sandstones or carbonate rocks not produced by weathering. However, some radioactivity can be associated with carbonate rock and sandstones because of transport of radioactive minerals in solution in the formation waters. The principal use of the gamma ray log is to distinguish between the shales and the nonshales. Historically, the first gamma ray devices measured only the total gamma
0
0.5
1.5
2
2.5
3
Gamma Ray Energy, MeV Fig. 50.18-Theoretical gamma ray emission spectra from the three naturally occurring radioactive products.
ray flux emanating from the formation. However, it is now known that different types of shale have different total gamma ray activity because of the Th, U, and K concentrations. Fig. 50.18 shows the various gamma ray line emissions associated with each. This indicates that by determining the intensity of the particular gamma ray energies it is possible to identify the quantity of each radioactive emitter in the formation. With the development of improved spectroscopic-quality gamma ray detectors, it became natural to refine the gamma ray measurement into a measurement of the actual concentrations of the three components. The measurement element for recent gamma ray or spectral gamma ray logging devices is the NaI detector. The gamma ray devices measure the total number of gamma rays above some practical lower limit (on the order of 100 keV). This total counting rate will be (I) a function of the distribution and quantity of radioactive material in the formation and (2) influenced by the size and efficiency of the detector used. For this reason some calibration standards have been established by the API, and all total-intensity gamma ray logs are recorded in API units. The definition of the API unit of radioactivity comes from the artificially radioactive formation constructed at the U. of Houston facility. A formation containing approximately 4% K, 24 ppm Th, and 12 ppm U was constructed and defined to be 200 API units. The details of this calibration facility can be found in Ref. 6. Spectral gamma ray devices basically use the same type of detection system as the total gamma ray devices, but instead of one broad energy region for detection. the gamma rays are analyzed into several different energy bins.
PETROLEUM ENGINEERING
50-16
n emitters/cm3
To Emitters in Shell
Emitters in Shell 4nnr*dr Fig. 50.19-Geometry for the gamma ray flux al a point from uniformly distributed sources in an infinite medium.
This allows for the determination (after comparing to normalized standard formations where the concentrations of K, U, and Th are known) of the concentrations of these elements present in the measured formation. These log output quantities usually are expressed as a percent by weight of the total material. It is of interest to note that the gamma ray intensity from a uniformly distributed source (whose concentration is maintained at a constant value when expressed in weight percent of the medium in which it is embedded) is independent of the formation density, even though the attenuation is a direct function of the formation density. This can be seen from the following argument. Consider an infinite homogeneous medium containing n gamma ray emitters per cubic centimeter, each with a source strength of emission of one gamma ray per second. To calculate the total gamma ray flux that would be seen by a detector at a given point in this medium, refer to Fig. 50.19. The contribution to the total counting rate from a spherical shell of thickness dr at a distance r from the detector would be the number of emitters contained in this shell multiplied by the attenuation over the path length r to the detector, -K,Pb’
d’P=4*r2.dre -,
. . . . . . . . . . . . . . . . (33)
4ar2
and the total counting rate is just the integral
*=n
s
-eeKaPbrdr,
..
. .....
.
(34)
0
1 *=n- KoPb.
...........................
(35)
HANDBOOK
This simply says that the total counting rate is proportional to nlpb, which can be expressed as the weight percent of the material that is radioactive. Consequently, the utility of expressing the radioactive contents as weight fractions is seen. One of the fundamental difficulties in the interpretation of the gamma ray device measurements is inherent in its very concept. There are nonradioactive clays and there are “hot” dolomites. The use of spectral gamma ray devices can often point out an anomaly such as a “hot” dolomite or other formation with some unusual excess of U, or in other cases K or Th. Both types of devices suffer to some small degree from the borehole environment. Because of mud in the borehole and varying hole diameters, the gamma rays emitted from the formation must pass through different amounts of gamma ray absorbers to reach the detector. Additional complications can arise because of mud additives such as barite or KCl. In the first case, the barium content of the mud becomes a very efficient absorber of low-energy gamma rays emanating from the formation. In the second case, the borehole fluid is also a source of radioactive potassium, which is contained in the KC1 additive. Ref. 7 discusses a method for correcting for these effects. Gamma-Gamma
Density Devices
As noted in an earlier section, the transmission of gamma rays through matter can be related to the electron density if the predominant interaction is Compton scattering. Thus, a gamma ray transmission-type measurement through a formation can be used to determine its density and with some information on the material composition (lithology and pore fluids) the porosity can be determined. The gamma ray source usually used in density devices is ‘37Cs, which emits gamma rays at 662 keV, well below the limit for pair production. This isotope has a half life of about 30 years, which provides a usable, stable intensity during a reasonable period. Some devices use 6oCo, which emits two gamma rays at 1332 and 1173 keV. The earliest devices consisted of the gamma ray source and a single detector, which initially was called a GeigerMiiller tube. However, to compensate for the frequent occurrence of intervening mudcake, modern devices incorporate two detectors (generally both NaI) in a housing that shields them from direct radiation from the source and is forced up against the formation with a hydraulically operated arm. This arm provides a force of application as well as a measurement of the diameter (along one axis) of the borehole. The measurement principle derives from the fact that the counting rate of a detector will vary exponentially with the density of the formation. Consequently, the formation density can be determined simply from an observed counting rate. However, in the case of intervening mudcake of unknown density and thickness, there will be a disturbance of the counting rate. Fig. 50.20 shows the usual logging situation. To correct for this intervening mudcake, the apparent density of the long- and shortspacing devices can be derived. Laboratory measurements then are used to define the correction, Ap, that must be applied to the apparent density from the long-spacing detector to read the value of the formation density behind it.
NUCLEAR LOGGING TECHNIQUES
In at least one device the shape of the gamma ray spectrum is measured and correlated with the photoelectric absorption parameters of the formation, which, in turn, can be linked with the lithology of the formation. The photoelectric factor, Fpe, is proportional to the photoelectric cross section per electron. Fig. 50.21 shows the utility of such a measured parameter for distinguishing between the three principal matrices. Since the Fpe of mixtures does not combine volumetrically, a new parameter, U, which has the property of combining linearly, has been developed for interpretation purposes. The definition of U is the product of Fpp and electron density, U=Fpepe,
. . . . . . . . . . . . . . . . . . . . . . . . . . . . ..(36)
and corresponds to the macroscopic photoelectric cross section. This follows from the definition of Fpe, which is the photoelectric cross section per electron, and pp, which is proportional to the number of electrons per cubic centimeter. Thus, the value of U for any mixture can be computed by making a simple volumetric addition of the Uassociated with each of the pure components of the mixture. Table 50.3 lists some useful lithology parameters for a number of commonly encountered minerals. Fig. 50.22 shows the use of U and density in the determination of lithology once the effect of porosity has been eliminated. Examination of Table 50.3 shows the enormous sensitivity of the parameter U or Fpe to elements with a large atomic number. In particular, note the values of Fpe for the several iron compounds and for barium. In the case of iron, this sensitivity can be exploited to make a determination of shale content of the formation if there is iron associated with the clay mineral. This is discussed in the section on interpretation. However, the sensitivity to barite makes the Fpe measurement difficult in heavily weighted barite muds. If there is a substantial thickness of barite mudcake between the tool skid and the formation or if there is invasion of BaS04 particles into the formation, the resultant photoelectric absorption can seriously disturb the measurement.
50-17
Long Spacing Detector
Short Spacing Detector
Source
Fig. 50.20--Schematic of a compensated density device in a borehole with mudcake.
*
Porosity
4
Neutron Porosity Devices Historically, the neutron device was the first nuclear device to be used to obtain an estimate of formation porosity. The principle of operation is based on the fact that hydrogen, with its relatively large scattering cross section and small mass, is very efficient in the slowing of fast neutrons. Thus, a measurement of the flux of epithermal neutrons resulting from the interaction of highenergy source neutrons with a formation will be related to its hydrogen content. If the hydrogen (in the form of water or hydrocarbons) is contained within the pore space, then the measurement will yield porosity. The simplest version of the device consists of a source of fast neutrons such as Pu-Be or Am-Be with average source energies of several MeV and a detector of much lower-energy neutrons at some distance from the source. Two general categories will be considered on the basis of the types of neutrons detected-epithermal or thermal. To be a little more quantitative about the response of neutron porosity devices, we can use the results of twogroup diffusion theory, * which show that the flux of
Dolomite
i
Fig. 50.21-Values of the photoelectric factor, Fpe, [or the three principal matrices showing the relative Insensitivity to porosity.
50-l a
PETROLEUM ENGINEERING
TABLE 50.3-LITHOLOGY
Elements Hydrogen Carbon Oxygen Sodium Magnesium Aluminum Silicon Sulfur Chlorine Potassium Calcium Titanium Iron Strontium Zirconium Barium
Formula H C 0 Na
WI Al Si S Cl K Ca Ti Fe Sr Zr Ba
HANDBOOK
PARAMETERS FOR VARIOUS MATERIALS
Molecular Weight
z
1.008 12.011 16.000 22.991 24.32 26.98 28.09 32.066 35.457 39.100 40.08 47.90 55.65 87.63 91.22 137.36
1 6 8 11 12 13 14 16 17 19 20 22 26 38 40 56
Fpe 0.00025 0.15898 0.44784 1.4093 1.9277 2.5715 3.3579 5.4304 6.7549 10.081 12.126 17.089 31.181 122.24 147.03 493.72
It
pb
L
2.700
2.602
2.070
2.066
u’
Minerals Anhydrite Barite Calcite Carnallite Celestite Corundum Dolomite Gypsum Halite Hematite llmenite Magnetite Pyrite Quartz Rutile Sylvite Zircon
CaSO s BaSO, CaCO 3 KCI.MgCI,,GH,O SrSO, AI,O, CaCO, .MgCO, CaSO,.ZH,O NaCl Fed& FeO.TiO, M&O, Fe304 FeS 2 FeS 2 Si02 TiO KC; ZrSiO,
136.146 233.366 100.09 277.88 183.696 101.90 I 84.42 172.18 58.45 159.70 151.75 84.33 231.55 i 19.98 I 19.98 60.09 79.90 74.557 183.31
5.055 266.8 5.084 4.089 55.13 1.552 3.142 3.420 4.65 21.48 16.63 0.829 22.08 16.97 16.97 1.806 10.08 8.510 69.10
2.960 4.500 2.710 1.61 3.960 3.970 2.870 2.320 2.165 5.210 4.70 3.037 5.180 4.870 5.000 2.654 4.260 1.984 4.560
2.957 4.011 2.708 1.645 3.708 3.894 2.864 2.372 2.074 4.987 4.46 3.025 4.922 4.708 4.834 2.650 4.052 1.916 4.279
18.016
0 358 0.807 0.119 0.125
1.000 1.086 0.850' 0.850"
1.110 I.185 0.948’ 0.970’
0.40 0.96 0.11 0.12
1.745 2.70 3.42 0.161
2.308 2.394 2.650' 1.700'
2.330 2.414 2.645' 1.749’
4.07 6.52 9.05 0.28
0.180
1.400’
1.468’
0.26
14.95 1070.0 13.77 6.73 204.0 6.04 9.00 8.11 8.65 107.0 74.2 2.51 109.0 79.9 82.0 4.79 40.8 16.3 296.0
Liauids Water Salt water Oil
Clean sandstone Dirty sandstone Average shale Anthracite coal Bituminous coal
C:H:O93:3:4 C:H:Oa2:5:13
NUCLEAR LOGGING TECHNIQUES
50-19
2.65
2.70
5
6
7
I
I
i
8
9
10
Umaa Fig. 50.22-Matrix
identification chart from U and density once the effect of porosity has been eliminated
epithermal neutrons, in an infinite medium containing a point source of fast neutrons, falls off exponentially with the distance from the source, L, with a characteristic length, L,s, which is determined by the constituents of the medium: ~
,=L eeLILs cp, D L ,
.
.
(37)
where D is the epithermal diffusion coefficient, which is related to the transport mean free path of neutrons. At a fixed spacing, counting rates should vary nearly exponentially with the slowing-down length of the formation. An indication of this type of behavior can be seen in Fig. 50.23, which shows, on the left, the counting rate of one of the early epithermal neutron devices as a function of porosity, and on the right as a function of slowingdown length. The matrix effect is much reduced in the
Slowmg-Down
Length.Ls.cm
Fig. 50.23-Counting rates for a long-spacing epiihermal detector in test formations of varrous porositres. On the left, the data are plotted as a function of the formation porosity with th:ee data trends resulting that car respond to the three matrices of the test formattons. On the right, the same data have been replotted as a function of the corresponding slowing-down length for each of the test formattons.
50-20
PETROLEUM ENGINEERING
'6 s az m5 .E z a u
4
23 6 7 k
2
z" 6
'
.o z LT
0
0
10
20
30
40
50
60
70
90
100
Porosity, % Fig. 50.24-The ratio of near to far detector counting rates as a function of porosity for a thermal neutron porosity device.
c
-Sandstone
+ -A-
YY
90
loo
Porosity, p.u, Fig. 50.25-The calculated migration length, L,, as a function of porosity for the three principal matrices: sandstone, limestone, and dolomite.
HANDBOOK
second presentation. It also shows how the counting rate in any other material, once its slowing-down length has been calculated, then can be estimated or, conversely, how the slowing-down length of the formation can be determined from a measurement of the epithermal flux. It was seen in Fig. 50.11 that the slowing-down length is strongly dependent on the amount of hydrogen present in the mixture for which it is calculated. Fig. 50.11 also shows the slowing-down length as a function of porosity for three common matrix materials: limestone, dolomite, and sandstone. From this presentation, it can be seen that if the matrix is known, the appropriate true porosity can be determined. As an operational expedient it has been convenient to convert the epithermal counting rate into porosity directly, assuming a limestone matrix with a slight correction to be made for the other two matrices. The separation of the three curves in the previous figure suggests how such a correction is made. One of the first really quantitative devices of this type used a single epithermal detector in a skid applied mechanically against the borehole wall. This sidewall epithermal neutron device had the advantage of minimizing borehole effects, although it is sensitive to the actual size of the borehole and can be disturbed by the presence of mudcake between the pad surface and the borehole wall. A more recent development is the dual-detector compensated neutron device. This type of device uses a pair of thermal detectors for increased counting rate to improve the statistical uncertainty of the derived porosity values at high porosity. The second detector, the nearer to the source, is used to provide compensation for borehole effects. Although thermal neutron detection is used, it can be shown8 that if the source-to-detector spacings are appropriately chosen, the ratio of the two counting rates should vary exponentially as the inverse of the slowingdown length just as in the case of the single epithermal detector. In practice, however, it is found that some additional corrections must be made to the measurements, which can deviate from expected values if the thermal capture properties of the borehole and formation are significantly different. These generally are provided by the service companies in the forms of charts or nomographs. More recently they have been provided as a part of computerized interpretation. The migration length, discussed in an earlier section, provides a convenient way to characterize the response of the thermal neutron device. Fig. 50.24, taken from Edmundson,’ shows the ratio of the near to the far counting rate of such a device for three types of lithologies as a function of porosity. If the porosity values on the points of this plot are converted through the use of Fig. 50.25, which shows the migration length, L, , as a function of porosity, then the counting rates for the three lithologies lie on a single ljne, as seen in Fig. 50.26. This demonstrates that the response characteristics of the neutron porosity tools are given by some function of the slowingdown length and diffusion length rather than porosity. Although the API committee6 that set up the gamma ray calibration standards also took some steps to standardize neutron log responses, their recommendations for API units have not been implemented. The conventional approach to neutron log output is to calibrate the tool in limestone primary formations and to report all readings
NUCLEAR LOGGING TECHNIQUES
50.21
in apparent limestone porosity. Conversion charts are then necessary to correct the apparent limestone porosity for the matrix in which the measurement actually was made. (As noted previously, some consideration should be given to using the slowing-down length and diffusion length as the units for reporting the log measurements.) These measurements would be converted to porosity by use of charts similar to Figs. 50.11 and 50.25, lying entirely in the realm of interpretation. One of the biggest limitations of the thermal porosity device is the disturbance on the measurement that can be caused by shale, either from its iron or potassium content or associated trace elements with high thermal capture cross section. However, even without the additional disturbance of thermal absorbers, clays and shales present a problem for all neutron porosity interpretation because of the hydroxyls associated with the clay mineral structure. Fig. 50.27 illustrates this point by showing the variation of slowing-down length of a sand/illite and sand/kaolinite mixture as a function of porosity. In both cases the sand and shale volumes are in equal proportions. It is clear that if the presence of clay in addition to the sand is not taken into account, large errors in porosity can result. Also note that the apparent porosity of kaolinite is much larger than that of illite. The examples shown in the figures indicate that a 20-PU sand/illite mixture will appear to be about 2.5 PU, whereas the 20-PU sandjkaolinite mixture will have an apparent porosity of about 36 PU. This will be seen in a later section to be caused by the differing hydroxyl content of these two clay minerals. It is also of note that the most recent neutron porosity device consists of a pair of thermal and a pair of epithermal detectors. This enables measuring an apparent porosity unaffected by thermal absorbers and simultaneously obtaining a measurement of the macroscopic thermal absorption coefficient, C, which additionally describes the formation. Pulsed Neutron Logging Devices Pulsed neutron logging devices respond to the macroscopic thermal absorption capture cross section. The macroscopic thermal absorption cross section depends on the chemical constituents of the matrix and pore fluids. Chlorine, which is nearly always a constituent of formation waters, has a large absorption cross section. Thus, a measurement of the absorption cross section can provide the means of identifying salt water and measuring formation fluid saturation. To determine the macroscopic thermal cross section, the actual phenomenon being measured is the lifetime of thermal neutrons in an absorptive medium. In a manner analogous to radioactive decay, we can predict the timedependent behavior of thermal neutrons. The reaction rate for thermal neutron absorption is given by the product of the macroscopic cross section C and the velocity of the neutron, v. So for a system of NN neutrons the rate of thermal absorption is given by dNN= -Cvdt,
. ..
...
. . . . . . . . . . . . . (38)
which when integrated yields NN=NiC”“,
... ... .
. . . . . , . . . . . . . . . (39)
q
Sandslone (Quartz)
0 Limestone 4 Dolomite @ Water (100%)
2l01 7.5
I 10
15
23
25
30
35
Migration Length, Lm, cm
Fig. 50.26-The ratio data of Fig. 50.24 plotted as a function of the migration length, L,, corresponding to the matrix and porosity of the test formation measurements.
32.1
27.5
12.5
10.0
7.5
5.0 0
5
10
15
20
25
30
35
40
Porosity, p.u. Fig. 50.27-The calculated slowing-down length as a function of porosity for sand and sand/clay mixtures. For the two lower lines the matrix is composed of equal mixtures, by volume, of sand and kaolinite or illite.
PETROLEUM ENGINEERING
50-22
tn
Fast Neutron Burst from Pulsed Source
z 2 > c : 7 z
Build-up & Decay of Thermal Neutrons
HANDBOOK
Since the derivation of the decay-time measurement is based on the simple model of a cloud of thermal neutrons being present and then decaying, it is of some interest to see just how long it is after the burst of 14-MeV neutrons that they become thermalized. To estimate this time we need only to refer to the section on neutron physics, where the average number of collisions for thermalization and the mean free path were discussed. The simplest estimate of the time required is to suppose that between each collision the average distance traveled is the mean free path (l/C,). The time between one collision and the next, At, is then given approximately by
1 100
0
200 Time, ks
300
At,i’ c, v,
Fig. 50.28--Schematic timing diagram of a pulsed neutron capture/gamma ray device.
which relates the number present at time t to an initial number Ni at time zero. The exponential decay constant is seen to depend inversely on the desired quantity C. The practical realization of such a pulsed neutron logging device depends on a pulsed source of high-energy neutrons. Such a device was discussed previously. The basic mode of operation consists of pulsing the source of 14-MeV neutrons for a brief period. This forms a cloud of high-energy neutrons in the borehole and formation, which then becomes thermalized through multiple collisions. This process is illustrated in Fig. 50.28. Only at thermal energies does the absorption become important and the neutrons begin to disappear in accordance with Eq. 39. As each neutron is captured, whether it be by hydrogen or chlorine, gamma rays are emitted, and the decay of the gamma ray counting rate is the actual measurement that reflects the decay of the neutron population. As seen from Eq. 39, the decay constant for a particular formation is given by 1lv.L The value of the capture cross section C is listed in Table 50.4 for a number of pertinent cases. Included in the table is the decay time associated with the particular matrix, which was computed from the relationship K ?d=- c
, ..............................
abs
where K is 4550 psec, because v for thermal neutrons is 0.22 cmlpsec and Cabs, the thermal absorption cross section, is in capture units.
TABLE 50.4-CAPTURE CROSS SECTIONS AND DECAY TIMES
Quartz Dolomite Lime 20-PU lime Waler
Salt water (26% NaCI)
c - (C.U.) 4.26 4.7 7.07 10.06 22 125
it/ -(w=c) 1066 966 643 452 206 36
. . . . . . . . . . . . ..I............
..(41)
where C, is the total cross section and v is given in terms of the energy E by Eq. 23. The 1Iv factor can be replaced by using Eq. 23 in conjunction with the expression (Eq. 30) for the average number of collisions, a, yielding 1 -oQ~'*,
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..(42)
V
where E is the average logarithmic energy decrement defined in Eq. 25. The value of an average mean free path for formations of interest can be estimated from Fig. 50.10. From the above information, the total time, t, (psec), from emission to thermal energies is given by
Evaluation of this expression for 20%-porosity limestone gives an estimate of about 2.8 psec and in water it is only 0.5 psec, both of which are much smaller than the decay times shown in Table 50.4. Numerous measurement schemes are used for controlling the period during which the 14-MeV neutrons are produced and the period during which the gamma rays are measured. Some devices use dual-detector systems in an attempt to correct for the small disturbance that can be introduced by the borehole size and salinity as well as to provide some measure of the porosity. Inelastic and Capture Gamma Ray Spectrometry The primary motivation for the development of induced gamma ray spectroscopy devices was the possibility of performing in-situ chemical analysis of the formation constituents. The tantalizing possibility of directly measuring the ratio of the number of carbon atoms to oxygen atoms and thus providing the first direct downhole measurement of the presence of hydrocarbons spurred the development of a number of technologically sophisticated devices. This is to be contrasted with a traditional approach that depends on the analysis of a core or side-wall sample. Tools of this type are based on a type of chemical analysis that can be performed through the use of neutrons and gamma ray spectroscopy. Neutrons are used to excite the nuclei, which then emit gamma rays of precise
50-23
NUCLEAR LOGGING TECHNIQUES
0
2
4
Neutron
6
I
I
I
J
8
10
12
14
Energy, E,, MeV
Fig. 50.29-Cross sections for the production of inelastic gamma rays by carbon and oxygen as a function of the incident neutron energy.
GeDetector
Gamma
Ray Energy. MeV
Fig. 50.30-Comparison spectra from a high-resoluhon solidstate detector (Ge) compared to the gamma ray spectrum detected with a more conventional Nal detector.
energies uniquely identifying the isotope in question. There are two neutron reactions that can produce such gamma ray emissions: inelastic scattering, which can occur with very-high-energy neutrons, and capture reactions with thermalized neutrons as exploited in pulsed neutron logging. Few elements for well-logging applications have large inelastic cross sections, but fortunately carbon and oxygen do. Fig. 50.29 shows the cross sections for the production of gamma rays from inelastic scattering from carbon and oxygen. These inelastic induced gamma rays are observed not only by spectroscopic gamma ray detection but also in conjunction with timing. To avoid confusion with gamma rays produced from thermal capture, the inelastic gamma rays are detected during the burst of 14-MeV neutrons. At some later time, gamma rays arising from thermal absorption are detected, providing sensitivity to a large number of elements such as H, Fe, Cl, Si, Ca, S, etc. At least two different neutron pulsing and gamma ray detection sequences are currently in use. One method lo uses a fixed time of about 50 to 100 psec between neutron bursts, and another method, ’’ which collects information on the capture gamma rays, uses a variable neutron-pulse interval that is controlled by the characteristic decay time of the thermalized neutrons. Tool design differences can optimize the detection of the inelastic or capture gamma rays. Some designs incorporate the measurement of both through appropriate timing cycles. In addition to the measurement of the gamma ray yields of the various elements, the macroscopic cross section C can be determined from an analysis of the decay of the total gamma ray signal, which is also measured. The only practical limitation on the number of elements is determined by counting statistics and the inherent detector resolution. An experimental tool that uses a high-resolution Ge detector has measured more than two dozen different elements in borehole logging. This type of detector must be operated at very low temperatures (- I96”C), which introduces a number of technological problems for borehole measurements. However. the advantage that it brings is in the much improved resolution, which increases the number of distinct gamma rays that can be distinguished in the spectrum. Fig. 50.30 shows the dramatic improvement compared to a conventional NaI detector for the examination of a natural uranium sample. Two elements that are readily detectable with such a device are aluminum, which is very useful in the classification and quantification of in-situ clays, and vanadium, which can be correlated I2 with the API gravity of the associated oil.
Interpretation of Nuclear Logs The following section discusses how the previously mentioned nuclear logging tools are used in interpretation. However, it should be stated at the outset that this is not intended to be a self-contained log interpretation course. A number of references’“-” of such works should be consulted for further information. The approach taken here is more or less a stand-alone interpretation of each tool. An examination of all the combination measurements and the interpretation techniques used with each tool is beyond the scope of this chapter. Nonetheless, several of the more standard tool combination interpretation approaches are discussed. Fig. 50.31
PETROLEUM ENGINEERING
50-24
Interpretation
Nuclear
Steps
: I Cor;el~iions
of ’ ” ’ : “j”j ‘.
:
.:
Ray
‘. G&n&Density
Porosity ..
Neutron
j j I
‘.’,. ; : :
:
‘:
:
Pordsity :
:
:
,,
//“’
Lithology
-Photoelectric
&
Induced
Clay Typing
The gamma ray log traditionally has been used for correlating zones from well to well, crude lithology identification, and rough volume of shale estimation. With the current state of knowledge of clay composition and other more refined lithology determinations, it is clear that the surest use of the gamma ray is, indeed, for correlation. For estimating the volume of shale, the approach is to scan the log for minimum and maximum gamma ray readThe minimum reading then is ings, Ymin and ymax. assumed to be the clean point and the maximum reading is taken as the shale point. Then the gamma ray reading in API units at any other point in the well, ylog , is scaled accordingly:
. .._...................
Ymax -Ymin
This ratio usually is referred to as the gamma ray index and can be scaled into percent shaliness according to charts I3 depending o n rock type. This method is sometimes appropriate, if in fact the maximum gamma ray reading corresponds to the same type of shale as the values that are being interpreted. Numerous examples show the deficiencies of this method, and for this reason the spectral gamma ray tool was developed. Tools of this type measure, in fact, the relative concentration of three radioactive components of the total gamma ray signal. It is interesting to point out the relationship between the concentration of the three radioactive components and the total gamma ray signal in API units. It is given by YAPt=AxTh+BxU+CxK.
Spectroscopy: Ray Spectroscopy
/
Neutron
interpretation tasks and the nuclear measurements
Interpretation of Gamma Ray Measurements
.
’
C/O~(Gamma Spectroscopy)
indicates four of the steps in the interpretation process and the nuclear measurements used to obtain the desired results. The indicated list of measurement devices or techniques is in the order of the discussion that follows.
Ylog -Ymin
ip,‘betisity/Neutron
Gamma
Pulsed
Saturation
Fig. 50.31-four
F&&r
High Resolution’Gamma
I
V sh a
: : : : jGamma
Used
: i Natural Th, U.K. Spectrosc&
/ “Clean” Zones :: ‘. 1 j
,.
I : ~ :‘.: i
Measurements
HANDBOOK
. .
(45)
associated with them.
When thorium and uranium are measured in ppm and potassium in weight percent, it is found that ratios of the coefficients (A:B:C) are 1:2:4; i.e., 1 wt % K contributes four times more to YAPI than 1 ppm of thorium. It is obvious from this that in a shaly sand, if a mineral rich in potassium (such as mica) is present, the total gamma ray signal will increase and give a false indication of pcrcentage shale when, in fact, this additional radioactivity is caused by the mica. There are two solid reasons for using a spectral gamma ray measurement over the standard gamma ray, which is really reliable only for correlation. The first is for the detection of radioactive anomalies, such as referred to previously, and the second is to make some estimation of the clay types by classifying them in terms of the relative contributions of the three radioactive components. For this second point the reader is referred to publications on spectral gamma ray interpretation. I*-*’ Fig. 50.32 shows a log example from the North Sea in a micaceous sand. At 10,612 to 10,620 ft, a shale is indicated that has a total gamma ray signal of about 90 API units. With just the total gamma ray as an indicator it appears that the zone 10,568 to 10,522 ft contains about half the amount of shale estimated for the lower zone. However, the decomposition of the gamma ray signal shows quite clearly that the amounts of U, Th, and K in these two zones are quite different. In fact, the upper zone is a mixture of sand and mica, whereas the lower zone is, indeed, shale. In the next example, Fig. 50.33, the gamma ray alone would indicate that below the lower boundary of the shale bed at 12,836 ft, there is a relatively clean sand. It can be seen, however, from the K trace that the high level of potassium in the shale zone persists several feet below 12,836. This excess potassium was found to be caused by feldspar, which has considerable impact on the grain density to be used in the interpretation of density logs. The third example, Fig. 50.34, shows how a uraniumrich formation would be misinterpreted (in simple gamma ray interpretation) as being shale. The sudden increase
50-25
NUCLEAR LOGGING TECHNIQUES
-#
, Depths
Gamma Ray
Thorium
Uranium
Potassium
50
0
API
200
Fig. 50.32-A
0
ppm200
wmloo
%
5
spectral gamma ray log from the North Sea in a micaceous sand.
50
4J
%o
0
0
PETROLEUM
50-26
Gamma Ray
Depths
Thorium
Uranium
Potassium
ENGINEERING
HANDBOOK
Porosity and Fluids Analysis bv Volume
Hydrocarbon
Fig. 50.33-A
spectralgamma ray log from Nigeria where a continuing trace of K is attributed to the presence of feldspar.
in uranium content alone signals that this is not a simple shale of the variety in the adjacent levels. Core analysis showed this zone, however, to be rich in organic material and U is often trapped in organic complexes. Porosity Determination Gamma-Gamma Density Devices. The basic output of the gamma-gamma density device, bulk density, is conceptually the simplest measured parameter to interpret in terms of porosity. The basic relation (Eq. 1) is Pb =d’&‘f+(l
I water
-d’h’ma,
which volumetrically links the density of the pore fluid, pf, and the rock matrix density, pmo, to the bulk density,
Pb.
However, there are a few difficulties to overcome to interpret the output of such a density device, especially the matter of electron density index, oe. It was shown in an earlier discussion that the gamma-gamma density device is measuring the electron density index. Table 50.3 shows a comparison between bulk density and electron density index. It is in close correspondence for nearly all the compounds listed except for water and hydrocarbons. This is because the average value of Z/A is about % for all elements except hydrogen. It is seen that because of
NUCLEAR LOGGING TECHNIQUES
50-27
0
GRAPl
150
20, 0
0
B i i i i i
Fig. 50.34-A
K%
Uwm
Tppm
100 %
0
i / i4
spectral gamma ray log showing a zone of anomalous U concentration
this discrepancy for hydrogen, the bulk density and electron density index of water differ by about 11% To compensate for this fact, a simple transform of the electron density index is made so that in water-filled limestone the transformed or log density, p log. agrees with the bulk density. Fig. 50.35 shows this simple transform where the bulk density for 0-PU limestone and water are plotted against the electron density values. The equation of the straight line connecting these two points,
pb=1.07~p,-o.188,
5
10,o
.
.
. ..
. . . . (46)
corresponds to the published transform I4 used by the logging companies. It is worthwhile to point out that this transformed density, p l0g, will also agree to within 0.004 g/cm3 for the other principal matrix materials listed in the table.
Returning to the interpretation problem, the solution of Eq. 1 for porosity yields
$=-
Pm
-Pb
p*-Pf’
. . . . . .
. . . . . . . . .
. . . .
. .
(47)
.
so the problem rests on knowing the values to insert for fluid and matrix density. Before examining the means for determining these values, it is perhaps of some interest to know to what precision these two parameters must be known. It is interesting to look at the uncertainty that can be tolerated on the value used for the matrix density, pm0 . From the previous equation we can write
dC$=
Pb -Pmo (Pf-PmlJ2
1 -~
1
ap,.
Pf -Pm2
(48)
PETROLEUM ENGINEERING
50-28
As mentioned earlier, the modern gamma-gamma density devices are compensated measuring devices. They use two detectors at different spacings from the gamma ray source to compensate for the possible intervening presence of mudcake or drilling fluid. Normally. in addition to the density curve the log will also show a trace of the compensation, generally referred to as the Ap curve. This curve represents the correction made to the apparent density seen by the long-spacing detector (P,,~) based on the discrepancy between the long- and short-spacing measurements. The counting rate from either detector can be converted to an ap arent density after a series of laboratory calibrations. Y* If there is not any intervening material between the tool surface and the formation being measured, then the two values will be equal. As the mudcake thickness increases, the two density values will diverge for some reasonable value of thickness (generally less than 1 in.). The quantity Ap is determined by experimentation, as a function of the density differences, to be the amount to be added to the apparent long-spacing density, pls, to match the bulk density of the formation-i.e.,
2.5
1.o
2.0
1.5 Electron
2.5
3
Density, per g/cc
Fig. 50.35-The transform between the measured electron density index, pe, and bulk density, pb.
If this is evaluated for the case of a sand of about 30% porosity we can use the values pb =2.16, pf= 1.OO, and pmn =2.65 and obtain d$=0.43dp,.
HANDBOOK
...
.
... .
. . . . (49)
Thus, for the uncertainty in 4 to be less than 0.02, the uncertainty in p ma must be less than 0.05 g/cm3. A more detailed analysis of the uncertainty in grain density that can be tolerated can be found in Ref. 2 1. For values of fluid density it is necessary to know the type of fluid in the pores. The fluid density for hydrocarbon may range from 0.2 to 0.8. Salt-saturated water (NaCI) may be as high as 1.2 g/cm 3, and with the presence of CaCl2, values even as great as 1.4 g/cm 3 may occur. However, the uncertainty that can be tolerated in pf is much greater than that for p ma. An error analysis of Eq. 41 for the values chosen above shows that &#J=O. 188pf, which allows about double the margin of error. The value for matrix density in simple cases can be taken from Table 50.3, which shows a rather narrow variation between 2.65 g/cm3 for quartz and 2.96 g/cm3 for anhydrite. Grain densities for shales are an entirely separate matter and will not be covered here. The obvious problem left is assigning a matrix density, which can only be done with a knowledge of the lithology. In essence, all density interpretation aimed at porosity determination revolves on this. Before going on to the determination of lithology and thus an estimate of grain density, quality control of the density measurement should be discussed.
p,,=pls +Ap.
...,...
. ...
. (50)
Although it commonly is thought that Ap is a measure of the mudcake thickness, h,,, it is, in fact, proportional to the product of mudcake thickness and the density contrast between the mudcake, pmc, and the formation density-i.e., Apcxh,,(pb
-pmc).
...
.
...
. (51)
Beyond some thickness (- 1 in.), the compensation scheme will break down and the ph value will be in doubt. However, this point cannot be identified simply by use of a cutoff value of Ap. A very small gap of water (p,, = 1) in front of a low-porosity formation would yield a large value of Ap and yet be perfectly compensated for, whereas a 1-in.-thick mudcake of medium density in front of a high-porosity zone may yield a small Ap with some residual error in the compensation. Nonetheless, it is certain that the Ap curve will be used as quality control on the bulk density with some fixed cutoff value despite this caution. Neutron Porosity Devices. Modem neutron porosity devices are of two types, depending on the energy range of detection: thermal or epithermal. By convention. the log output usually is scaled in equivalent limestone porosity units. Under appropriate circumstances, this would correspond to the true porosity of a clean, water-filled limestone formation. In the following discussion it is assumed that the log reading already has been corrected for the various environmental effects. In addition to the environmental corrections that must be made before the porosity values are interpreted, there are three effects that must be considered in more detail. Matrix Efsect. As in density logging, it is necessary to know the rock matrix to make any practical use of the app:lent limestone porosity value measured. Fig. 50.36 shows, for a thermal and an epithermal device, the matrix correction necessary to transform the measured units into the appropriate porosity units. It should be noted that these
50-29
NUCLEAR LOGGING TECHNIQUES
-SNP’ --CNL.
30
-%NP’mr
Neutron PorosityIndex ILimestone~. p.u
--r&l CNLlcorNeutron PorosityIndex (Limestonel. p.u
0 0
10
20
Porosity,
30
40
p.u.
Fig. 50.36-Matrix correction chart for two specific neutron porosity tools.
Fig. 50.37-Experimental values for the ratio of epithermal counting rates as a function of porosity in limestone calibration formations.
charts are for two very specific tools (CNL* and SNP*). When such tools are involved, the appropriate chart for the corresponding tool should be used, since some of the so-called matrix effect is tool-design dependent. However, a large part of the matrix effect can be understood in terms of the two basic parameters used to describe the bulk parameters of the formation (i.e., the slowing-down length and the migration length). First consider the case of epithermal detection. To demonstrate the construction of the matrix-effect correction curves, there are four steps to consider. 1. The first step is the link between the measurement (for this case we take the simple case of using the ratio of near- to far-detector counting rate) and porosity in the primary laboratory calibration standards. This is a freshwater-filled limestone with g-in. borehole. Fig. 50.37 shows the behavior of the ratio, F=NN,, lNNe as a function of limestone porosity, +rS. From this plot a fit can be established to ascribe a functiqnal relationship between the measured parameter F and the limestone porosity @jS,
that allows the prediction of the measured ratio from the known slowing-down length of the formation. 3. The next step is to establish the connection between the slowing-down length, L, , and porosity for limestone as shown in Fig. SO.39 and seen earlier in Fig. 50.11. This curve now represents the limestone “transform” of Eq. 52 and the porosity axis represents true porosity. 4. The slowing-down lengths of sandstone and dolomite now are calculated as a function of porosity and are shown also in Fig. 50.39. They fall on either side of the limestone response because of their different chemical compositions, which influence their slowing-down lengths.
two
F=J@,,).
.. .. . ..... ....
..
. . . . . . (52)
2. In the second step, the relationship between the measured parameter F and the slowing-down length, L, , must be established for measurement in all three of the principal matrices. That this can be done easily is shown in Fig. 50.38, where measurements in quartz, dolomite, and limestone are shown for a range of porosities. From this plot a new fit can be found, F=f(L,), ‘Mark of Schlumberger
. ....
...
....
. . . . . . . (53) Fig. 50.38-Data of Fig. 50.37 plotted as a function of the equivalent slowing-down length, L,, of the corresponding formations.
50-30
PETROLEUM ENGINEERING
25.0
0
5
10
15
20
25
30
35
40
Porosity, p.u Fig. 50.39-Estimation of the epithermal matrix effect from slowing-down length, L,. as a function of porosity for sandstone and dolomite
HANDBOOK
The apparent limestone porosity for either formation can be found by selecting a porosity, lo-PU sandstone for example, and finding the corresponding slowing-down length (approximately 15.5 cm). The apparent limestone porosity then is obtained by finding the porosity associated with the limestone formation of the same 15, value. In this case it is 8.5 PU. The same case for dolomite indicates 14 PU instead of 10 PU. A similar procedure can be used for a thermal neutron porosity device. As shown earlier, it has been found useful to cast the results in terms of the migration length L m. 9 Because the L, contains some information concerning the macroscopic thermal absorption cross section, the results are qualitatively similar to the preceding but differ slightly in magnitude. This can be seen by performing the preceding exercise on the plots of L, vs. porosity of Fig. 50.25. Fig. 50.40 shows the neutron/density crossplot for a dual-detector thermal device. The matrix effect can be observed by comparing the equiporosity points on the individual lithology lines with the apparent limestone porosity scale on the abscissa. These discrepancies are the same as indicated in the portion of Fig. 50.36 indicated as “thermal.” Ref. 23 discusses the effect of absorbers on the thermal tool response. Gas Effect. Neutron porosity devices have been calibrated for liquid-filled porosity. However, the replacement of the liquid in the pores by gas will have a considerable impact on the slowing-down length of the formation and thus on the apparent porosity. In general terms, partial replacement of the water component of the mixture by a much lighter gas will increase the neutron slowing-down length and thus the apparent porosity will decrease. The actual apparent porosity decrease will be a function primarily of the true porosity, the water saturation, the gas density, and, to some extent, the lithology. In a situation such as this, replacement of fluid in the pores by a less-dense gas will decrease the bulk density of the formation. These two effects have been exploited in well logging by making the density and neutron porosity measurements in a single measurement pass. On the log presentation these two effects cause the density and neutron traces to separate, which can be recognized easily as being caused by the presence of gas, if the invasion is less than 6 in. pas separaTo quantify the traditional neutron-density tion indication and to illustrate the possibility ofcstimating
gas
saturation
from
an
epithermal
neutron
mcasuremcnt and a density mcasurcmcnt. conxidcr Figs. SO.41 and 50.42. In both these figures the slowing-down length of a sand formation has been computed between
Lcro and 40 PU at 2-PU increments. These values of slowing-down length have been plotted as a function ol the corresponding
bulk density
of the formation
for the
five gas saturations indicated on the figures. In the caxc of Fig. 50.41. the gas density, P,~%has been taken to bc Equtvalent Limestone Porosity, %
Fig. 50.40-A
neutron/density cross plot for a thermal neutron porosity device. The lithology of a formatlon can be identified by plotting points representlng o, (In limestone porosity units) and pb. Point A may represent a 22.p.u. limestone or. less likely, a mixture of sandstone and dolomite.
O.OOI g/cm”. and in Fig. S0.47. the gas dcnslty has been taken to be about 0.25 g/cm3. which covers the cntirc range possible under normal rcscrvoir conditions. In cithcr cam it is clear that. for the presence 01‘gas at a fixed poroGty. the slowing-down sociated with the water-tilled
length is lqcr than th;lt ahporosity. The mterpretation
of this larger value of L, ih an apparent decrease in porosity. In the caxc of the total ,:a\ saturation curve of
NUCLEAR LOGGING TECHNIQUES
Fig. 50.41-A
plot of slowing-down length, L,, vs. bulk density, pb, for sandstone formations with varying gas saturation. Invasion of borehole fluid is assumed to be negligible and the gas density is taken to be 0.001 glcm3.
Fig. 50.42-Effect of gas saturation in sandstone for a gas density of 0.25 g/cm 3.
Fig. 50.41, L, values greater than - 28 cm would correspond to zero or negative apparent porosities on the log
+D 0.65
readings. On the plots of L, vs. ph. a pair of points (L,, , p,,) will yield the saturation and porosity corresponding to the conditions
of gas density
specified.
For both figures
0.05 @N
the as-
sumption for the calculation is that the matrix is sandstone with no shale. The gas density difference for the two plots spans the range of expected gas densities. The saturation referred to on the figures is with reference to a gas/water mixture. For the lowest curve on both figures, is entirely filled with water.
the porosity
Since the slowing-down length normally is not presented on a neutron porosity log, an example taken from the log of Fig. 50.43 can serve as a guide. From the gas zone clearly
indicated
on this figure
values for the illustration:
600
we can use the following
@N, neutron
porosity
(sand)=
27 PU and $0, density porosity (sand)=35 PU. The lowermost curves on Figs. 50.41 and SO.42 serve to determine slowing-down
the correspondence between +N and the length. L, It is indicated by the horizon-
tal line to be about porosity
I I cm for this example.
The density
of 35 PU can be seen to correspond
to a density
of about 2.07 g/cm”. as indicated by the vertical lint. The intersection of these two points at the coordinate (2.07. I I), shown in the figure, indicates about 25%’ gas saturation in the case of a gas density of 0.25 g/cm” (Fig. 50.42), and a saturation of about 12.5% if the gas dcnsity ix taken to be nearly zero. The porosity tion can be found by following the
670
of the formaslope of the
equiporosity lines from the example coordinate to the lower liquid-saturated line and is seen to indicate a value of about 33 PU for both casts. With more information concerning the gas properties of a reservoir, this interpretation can be used instead to yield an indication of the invasion of the drilling fluid into the zone
of
investigation
of
the neutron
700
and density
devices. Shale Effect. Generally. the presence of shale tends to increase the neutron porosity values. The reason for this lies in two effects: additional hydrogen resulting from the
Fig. 50.43-Log example of the neutron/density combination exhibiting the characteristic crossover behavior In a gas zone.
PETROLEUM ENGINEERING
50-32
Fig. 50.44-Comparison of (1/L,)3 for sandstone, kaolinite, and illite as a function of porosity. The apparent porosity of pure illite is seen to be about 53 p.u. and for illite, 12 p.u.
Flg. 50.45-Variation of (l/L,)3 vs. porosity for sand and sandlkaolinite mixtures. A line at 30 p.u. indicates the effect of changing the matrix from sand to kaolinite, and another indicates the change in (l/L,)3 expected when the 30 p.u. is filled progressively with kaolinite.
1
“I
0 LM+6w q
so +sw
A WL+sW l LM+Fw+B 0
I
6
I
10
20
30
Ax, cu
Fig. 50.46-Correction for a thermal neutron porosity tool function of the formation, C.‘4
as a
HANDBOOK
hydroxyls in the clay minerals, and in the case of thermal porosity devices, the possibility of additional thermal neutron absorbers such as boron associated with the clay minerals. Initially, consider the case of thermal absorbers and consider just two types of clay minerals, kaolinite and illite. For these two clays (and many others) we refer to the data compiled by Edmundson et al. 9 The chemical formula for kaolinite is A14Si40 tc(OH)s and the formula for illite is K2Si6A1sFe302e(OH)4. The important point to note about these formulations is the differing amount of (OH). A rough calculation indicates that kaolinite has about one-third the hydrogen density of water and that illite, with a lesser amount of hydroxyls, has about one-tenth the hydrogen density of water. In the case of either of these “pure” clay minerals, a neutron porosity device will detect some large value of porosity, since the slowing-down length will be influenced greatly by the presence of the (OH) components. That the slowing-down length is considerably affected can be seen in Fig. 50.44, which shows the value of L, of sand, illite, and kaolinite from 0 to 100 PU. The ordinate in this figure is (1/L,)3, which has been chosen because it tends to vary linearly with the combination of two materials of differing values of L c. Values for the two pure clay minerals are indicated at 0 PU. From the figure, the apparent porosity would be about 53 PU for pure kaolinite and about 12 PU for illite. This is consistent with the trend expected from the hydrogen density. For the slowing-down length, the choice of the replacement of three Fe atoms for three Al atoms is immaterial, but it will have an impact on the thermal neutron absorption because of capture by the iron. By using a plot similar to Fig. 50.44, the expected response of an epithermal neutron porosity device to a mixture of kaolinite and sand can be predicted. Fig. 50.45 shows an example of this. In the case of a true 30 PU (that is, 30% of the volume is water-filled), the mixedmatrix line indicates the change of L, with a change in the sand/kaolinite matrix. Following the indicated line, a matrix of 70% sand and 30% kaolinite would have an apparent porosity of about 41% compared to the actual value of 30 % . On the other hand, we can take the case of 30 PU, or more precisely the case of 70 ~01% being sand, and ask what happens to the value of L, as the porosity is filled with kaolinite. This process also is indicated by the porosity-infilling line in Fig. 50.45. It is clear that the endpoint of this line must lie on the line of the 30/70 kaolinite mixture. As indicated in this case, the minimum apparent porosity as deduced from the slowing-down length will be about 12 PU where, in fact, there will be no porosity available for fluids. The impact on thermal neutron porosity devices is somewhat more difficult to predict and will depend in detail on the tool design and consequent response. A similar type of graphical construction using the migration length instead of the slowing-down length can be used to see that for the normal neutron absorbers, such as iron, in the clay minerals there is not a large effect. However, if boron is present in any substantial quantity, this will not be the case. To deal with this problem Arnold et al. 24 have determined experimentally a correction for the apparent porosity of a dual-detector thermal neutron porosity
NUCLEAR LOGGING TECHNIQUES
device as a function of the macroscopic absorption cross section KL of the formation. It is shown in Fig. 50.46. Despite the foregoing discussion. it must be recognized that neutron porosity devices do. in fact, respond to porosity. among other things. The dynamic range of the measurement at low porosity is excellent because of the sensitivity of the slowing-down length in this range. The problems of interpretation caused by the influence of shale are tractable when the neutron measurements arc combined with other tools. Lithology Determination Neutron/Density Combination. One of the traditional methods of lithology interpretation is the neutron/density combination. The useful property of combining these two measurements can be seen in Fig. 50.40: the three principal lithologies form three different response lines. The grain density. P,,~~,. increases in an almost linear fashion from sand to dolomite. so that it is tempting to draw lines of equal grain density for intermediate points that do not lie on any of the three lines. This type of presentation is shown in Fig. 50.47. With this approach, the particular lithology mixture is not of great importance but a fair estimation of the appropriate grain density is obtained despite the fact that p,,],, is not a characterizing parameter for neutron logs. The combination of the neutron and density measurements in this fashion can solve only simple binary mineral combinations. To interpret the results unambiguously, the two minerals must be known. For example, one can imagine a result. marked as Point A on Fig. 50.40, arising from a formation consisting of a sand and dolomite mixture. In this case, with no additional knowledge. the interpretation of the indicated point, intermediate between dolomite and sandstone. would be limestone. Photoelectric Factor. Discrepancies such as these can be resolved by the use of additional information. In particular. one such nuclear measurement is the photoelectric factor. F,,, It is convenient for purposes of interpretation to use the quantity U (Eq. 36). It has the property of combining volumetrically for the case of several substances being present in the scattering region whose individual absorption characteristics can be computed. For a two-component system (fluid and matrix) of porosity C#J this can be written as u=ufc#l+u,,,,,(1
-f$).
Neutron Porosity Index.4,.,,. P.U.
Fig. 50.47-Extracting
apparent grain density, prna, from the neutron/density cross plot.
One elementary use of the Fpr curve in conjunction with density is to make a simple two-mineral model. This is no more than formalization of the relationships seen in the preceding figure. This is done by solving the following set of equations for U and p, and using the fact that the volumes sum to unity: u,,,,=iJ,v,
+U2V2+iJf$,
plog=p,V,
+prV2+pf.$.
(56)
and I=V, + v2 ++.
(54)
F,,,. for this mixture then can be determined from Eq. 36, where P~=(Pc)l.~+(Pr),,,n(l
-4).
.(55)
The results of this type of computation are shown in the crossplot of Fig. 50.48, which shows how F,,,. varies as a function of density for the three principal matrices: limestone. dolomite, and sandstone. The interesting thing about this presentation is the order in which the three lines fall; dolomite now is bracketed by limestone and sandstone. It is obvious that in the hypothetical case of the sandy dolomite. given previously. the ambiguity about the presence of limestone would be removed when inspecting the corresponding value of F,,,, In this case it would clearly indicate a sand/dolomite mixture.
Bulk Omsity, pb,g/cc
Fig. 50.46-A
cross plot of the photoelectric factor vs. density. Lines for the three principa! matrices are indicated. The points represent the sampled log data.
PETROLEUM ENGINEERING
50-34
D-l%
Iron Content by Weight) -10%
To demonstrate the quantitative nature of the F,‘,,, mcasurement, consider the following argument for the determination of the weight percent of a trace photoelectric
F pe-3
1
absorber
in an otherwise
represents
two-component
the photoelectric
factor
system.
If F,,,,.,
of the trace absorber
and the associated volume fraction is sidered to be much smaller than unity), proximate equation applies: 1600
HANDBOOK
V, (which
is conthe following ap-
XMeasuredl . . ..
(1~~,~+CI,,,(,(l~~)+II,V,, where
.. . .
(57)
V., < < 1 and _.
U,=p,,F,,<~,.
_.
.(58)
Note that the third term in this equation represents the product of the trace element absorption factor and its associated mass contained in I cm3:
_.
U,V., =F,,<.\.p.,V\. Thus. the weight
_. _.
per cubic centimeter
.(59)
of the absorber can
be determined from the measured parameter (i.e.. from the product of the measured p and F,,,,) Cl from the following:
p,v\=
~-~,~-~,,,,A~-~)
The fraction given by Fig. 50.49-A
(6’3)
F ,w, by weight
of the solid
fraction.
f\, , is then
log example showing the conversion of the excess F,, in a shaly sand to the weight fraction of iron. In Track 1, the estimate from Fpe (Eq. 61) is compared to values obtained by core analysis. An interesting
application
of this idea is shown
for the
The indicated parameters for the two suspected minerals can be inserted in this equation to solve for the appropri-
log data of Fig. 50.48. The measured F,,,, curve is shown in Track 2 of Fig. 50.49 along with the curve of the anticipated F,, based on pure sandstone. The shading represents the “excess” photoelectric factor, which can be
ate porosity
converted
and lithology
mix.
to percent
weight
of iron by use of the above
However, there is no reason to limit this type ofanalysis to two minerals. It can be expanded to many more with
argument. The resulting curve of the iron concentration is found in Track 1 of Fig. 50.49, along with a series of
the addition of supplementary measurements such as Th, U. K. Al. Fe, and Si. The natural combination with the gamma ray spectral information has been shown useful for complex mineralogy in which two different three-
discrete measurements of the iron concentration made on the core samples. The good argument demonstrates the validity of the supposition that, in this case, the F,,(, meas-
mineral combinations Another interesting
in the shale and the volume
can be treated. 2s use of F,, can be to get an esti-
mation of shale in sand. The F,,(>values measured in shales are related primarily to their iron content. For an example of this application, refer to Fig. 50.48. The data points shown on the crossplot are from some sand and shale sequences. The clean-sand points are evident by their placement with respect to the indicated sand line. The shale points are those scattered to higher values of F,, . In this case the lithology the photoelectric
measurement
absorption
resulting
is responding from
to
the iron as-
sociated with the shale. In this particular case the shale is known to be a mixture of kaolinite and illite and the iron is associated with the illite.
urement
is responding
primarily
to the iron concentration
of shale present.
A similar
procedure could be followed for any other suspected trace element of sufficient concentration and photoelectric absorption factor.
Induced-Gamma-Ray
Spectroscopy. The induced gam-
ma spectroscopy tools are very important for lithology determination in complex situations. In the case of induced capture gamma rays a large number of elements can be identified: chlorine.
hydrogen, Lithology
silicon.
calcium.
identification
iron,
sulfur,
and
can be made by com-
paring the yields of particular elements. For example, anhydrite is identified easily by the strong gamma ray yield from sulfur and calcium associated with this mineral.
NUCLEAR LOGGING TECHNIQUES
TABLE 50.5-ATOMIC DENSITIES IN UNITS OF AVOGADRO’S NUMBER (6.023 x 10z3) Density (g/cm 7 2.71 2.87 2.65 2 96 0.85 1.0
Limestone Dolomite Quartz Anhydrite Oil Water
Limestone paring
Oxygen (atoms/cm3)
Carbon (atoms/cm 3,
0.081 0.094 0.088 0.087 0.056
0.027 0.031 0.061 -
can be distinguished
the
silicon
and
from
calcium
sandstone yields.
by com-
Numerous
references”.” show examples of these types of procedures as well as interpretation schemes proposed by some service companies. High-resolution enormous
spectroscopic
advances
devices
in mineralogical
will
Fig. 50.50-Gamma ray spectrum obtained with a high resolution Ge gamma ray spectrometer and Cf neutron source.
provide
identification.
Such
devices use solid-state gamma ray detectors instead of the conventional Nat detectors, which suffer from poor resolution. One of the most promising applications of such devices is the possibility of making aluminum activation measurements. Because aluminum is a common constituent of clay minerals. it is well adapted to quantitative clay content determination. As an example of the type of information that is obtainable from a high-resolution gam-
Vanadium
Aluminium
.FEzik--
0
(w-d
200
0
(W
ma ray spectroscopy device. refer to Fig. 50.50. which shows the gamma ray spectrum obtained after irradiation of the formation
with
a zs’Cf
source.
Along
with
the
gamma rays from the naturally occurring thorium, uranium. and potassium, the artificially produced radiation from manganese, sodium, aluminum, and vanadium is seen. The gamma vanadium
ray
intensities
from
the aluminum
isotopes can be used to produce
and
a log calibrat-
ed in weight percent of the two elements. In the case of the aluminum, the measurement is a continuous one made at about 400 ftihr and is shown in Fig. 50.5 I along with core measurements from the same well. To detect the vanadium, since it is present in rather small amounts, stationary readings were taken. These values are indicated along with error bars representing measurement caused by counting traces illustrate
the uncertainty of the statistics. These two
the type of detailed
evaluations
be made by logging devices, which previously made only with extensive core analysis.
that can could be
Saturation Determination Inelastic Gamma Ray Spectroscopy. Two nuclear tools are well adapted for the determination
of saturation.
The
first is based on the determination of the ratio of carbon to oxygen atoms in the formation. The use of such a ratio is shown clearly in Table 50.5. where it is seen that thcrc is a significant difference between the atomic C/O ratios of oil,
water,
and the common
matrix
minerals.
Fig. 50.52 shows how the atomic C/O ratio changes as a function of porosity and water saturation for the three principal matrices. From this figure clean formations of a given lithology is relatively
straightforward.
it is clear that for the interpretation
An inherent
difficulty
in the
measurement is immediately obvious. At low porosities the dynamic range of the C/O ratio as a function of water
Fig. 50.51 -Aluminum and vanadium logs of an oil-bearing shaly sand derived from a high-resolution gamma ray spectrometer. The solid bars represent the results of core analysis. The dashed bars indicate the log value of vanadium and its statistical uncertainty.
S-36
PETROLEUM ENGINEERING
HANDBOOK
0.7
0.6
0 ‘Z
0.5
2 g z G
0.4
0.3
0.2
Porosity,
/*
,./-
+
Fig. 50.53--Solution
of S, with Z.
0.1
,.aO/* *-I . cc I 1
0
I
20
30
Porosity,
4, %
10
In terms of water saturation,
1
into water
the fluid component
and hydrocarbon
40 c I<,~=(I
-$P,,,,,
The graphical Fig. 50.52-Variation of C/O as a function of porosity and water saturation.
+G,,.C,,.
solution
+$(I
saturation
shrinks to zero. Examples
of interpretation
of
complex situations can be found in the
-S,,.)C,,.
of this equation
in Fig. 50.53. To use this approach El, must be known. The presence of shale, which
this ratio in more references. 28Zu
is broken
components: (63)
for S,, is shown
the I alues of C,, and
may contain
thermal
ab-
sorbers such as boron, will seriously disturb this simple interpretation scheme. but a number of references”’ indicate methods for dealing with the problem. For saturation determination, the results of a single measurement run are questionable
if the water
device used for the determination
ly in shaly zones. Perhaps the greatest successful application of this type of device is in the time-lapse technique. In this procedure
of water saturation.
par-
in cased wells, is the pulsed neutron device. This
log responds
primarily
to the time taken for the thermal
neutrons to be absorbed by the formation. The most common important thermal neutron absorber is chlorine. which is present in most formation waters. Hence, the response of the pulsed neutron
tool resembles
the usual
opcnhole resistivity measurements. The advantage. however, of the pulsed neutron technique is the ability to log in cased hole. It can distinguish between oil and salt water contained in the pores. If the porosity
is known,
gas/oil
interfaces
can be distinguished.
Under ideal conditions of salinity. porosity, and lithology. the water saturation, S,,.. can be computed. In the simplest case of a single mineral, the measured
the change in saturation
c, s,,.,
-S,,.z
.
(62)
..,,..............
(64)
4G I,‘-c/E) Uncertainties volume)
in the quantity
disappear
in
(such as C,,,,, . 2:,,, and clay
this
differential
measurement
technique.
damental
+4C,.
the diffcrcnce and the differ-
-cz
mation
-r$)z:,,,,,
between two runs in a producing
=
Future Interpretation
&,jg =(I
15 o/c. particular-
reservoir can be determined simply from ofthe two measured C values, the porosity. ence in C,, and C,,--i.e.,
value of C 1,j(,can be thought of as consisting of two components. on; from the matrix and the other from the forfluid:
is below
is less than
50,000
ticularly
ppm and if the porosity
sahnlty
Pulsed Neutron Logging. The second type of nuclear
New interpretation approach
Models
models
will evolve
to the interpretation
from
a more fun-
of complex
lithol-
ogies in which relationships are formed between the geochemistry of the formation, as determined from core analysis, and log measurements.
NUCLEAR LOGGING TECHNIQUES
50-37
The premise of this approach chemical signature of a formation formation
on the minerals
is that the total geomay yield valuable in-
present,
including
clays,
be related to the types and abundances of clay minerals present, to the electrical properties of the clays and, even
reasonable,
to the
location
for example,
of the clays.
that chemical
It seems
data can not only
distinguish kaolinite from illite, but also that the chemical properties of a detrital kaolinite will differ from those of a kaolinite grown One of the primary
slowly in pore spaces. tools for the penetration
area of interpretation is the high-resolution ic tool, which was described previously.
into this
spectroscopIt will enable
us to obtain a precise mineral identification at each location of interest. However, other devices, such as the induced gamma ray spectroscopy tool. the gamma-gamma density device with a direct measurement of lithology , and the combination thermal and epithermal neutron device, are being examined for their responses to particular minerals of interest, for incorporation into this interpretation scheme. In addition
to the possibility
timates
this approach
from
of obtaining
grain-size
and thus an additional
esinput
to permeability transforms, one result will be the real possibility of the detection, quantification, and classification of the clay minerals from log measurements.” One of the primary benefits of such an interpretation output will be a reservoir damage risk assessment. This will be based on the knowledge
that has
been acquired through
unfor-
tunate experience concerning potential damage to a reservoir that can occur when the clay mineral content is not considered in production planning. For example, acidization of a formation containing chlorite, an iron-rich clay mineral,
can produce
an iron oxide
gel that fills
pores,
ruining a potentially valuable formation. Another example is that diagenetic pore-lining kaolinite particles will remain in place at low production rates. At higher rates, however.
the particles
may break
loose,
lodge
h=
the
grain size, and other indications of the environment of deposition and diagenetic alteration. This information may
perhaps,
F,, = photoelectric F prx = photoelectric
in pore
may lead to a new cycle of future tool development.
Nrvf = NN~ = Np = N, = P=
them from perturbations other purposes.
on measurements
designed
Nomenclature A = atomic mass D = thermal diffusion
coefficient
E = energy
EGR = gamma ray energy E;
= initial
Ek = kinetic
EN = neutron
energy energy
energy
E,
= energy
before
E,
= energy
of mono-energetic
Jr
= fraction
scattering
by weight
F = measured parameter
of solid
gamma
rays
for
mudcake
constant
mass absorption distance
from
diffusion
4= r= s, = t= t% = U= Uf = u = cl; = v= V.rh = v.x = x= I=
migration
length
=
length
mass molecular
weight
number
of scatterers
average
number
Avogadro’s initial
per unit volume
of collisions
number
number
of particles
number
of neutrons
neutron
counting
rate at far detector
neutron
counting
rate at near detector
number
of particles
counts
from
a radiation
detector
probability of having
x nuclei
probability
of nonoccurrence
path length
(radius)
water
decay
to the detector
saturation
time half-life product fluid
Fpe and electron
of
density
parameter
matrix
parameter
trace element
parameter
velocity volume
of shale
associated
volume
fraction
number of decays observed number
emitter gamma
ray reading
point
in the well
in API
units at any
Ymax
-
maximum
gamma
ray reading
Ymin
=
minimum
gamma
ray reading
6h = thickness of slab material h= decay constant Y= t= Ph = PP =
electron density
Pf
=
fluid
P#
=
gas density
Plog
=
log density
P/F
=
average
value
average
logarithmic
bulk
of Poisson
index
apparent
long-spacing
Pm
mudcake
UC0
denGty
density
microscopic
cross section
deviation
fraction
decrement
density
solid matrix density
=
distribution
energy
density
Pmcr = lJ=
in
dr
atomic
Cd=
7d and Cabs
the source
slowing-down
particles
z=
between
coefficient
length
time
Ylog
factor
trace absorber
of
thickness
conversion
pi = probability
One
can imagine measuring specific geochemical parameters with an entire range of new tools rather than inferring
factor
thickness
h,,. = K= K, = L= Ld = L, = L.7 = m= M= n= n= NA = Ni = NN =
throats, and damage production. Although geochemical interpretation is in its infancy, initial experience with clay type and grain-size prediction from core analysis data and log data has been very encouraging. Refinement of this type of interpretation mode1
absorption
= Compton cross section
or standard
PETROLEUM
50-38
OP” = C=
cross section macroscopic
for the photoelectric thermal
absorption
effect cross
section thermal
absorption
macroscopic formation
cross section
Compton fluid
cross section
cross section
hydrocarbon
cross section
macroscopic
cross section
observed matrix
formation
cross section
cross section
total cross section water
cross section
decay
time
porosity density
porosity
limestone neutron
porosity porosity
radiation
flux
intensity
of radiation
flux
of epithermal
neutrons
References
4 5 6. 7.
8. 9.
Evans, R.D.: 771~Aiomic Nuclrus. McGraw-Hill Book Co., New York City (1967) 426-38. Weidner. R.T. and Sells, R.L.: Hmwntar~ Modern Phwics, Allyn and Bacon, Boston (1960) 372-78. Bertozzi, W., Elbs, D.V., and Wahl, J.S.: “The Physrcal Foun dation of Formation Lithology Loggmg with Gamma Rays.” Geophwics (Oct. 1981) 46, No. 10. Kreft, A.: “Calculation of the Neutron Slowmg Down Length in Rocks and Soils,” Nukleonrka (1974) XIX. Segesman, F.F.: “Well-loggmg Method,” Geophwjc~ (Nov. 1980) 45, No. 11. Belknap, W.B. era/.: “API Cahbration Factlity for Nuclear Logs.” Drill. and Prod. Prac.. API. Dallas (1959). Ellis. D.V.: “Correctton of NGT Logs for the Presence ot KCI and Barite Muds,” paper presented at the 1982 SPWLA Annual Logging Symposium, Corpus Chrtsti, July 6-8. Allen, L.S. et&.: “Dual-Spaced Neutron Logging for Porosity.” Geop,phwics (Feb. 1967) 32, No. 1. Edmundson, H. and Raymer. L.L.: “Radioactive Loggmg Parameters for Common Minerals,” paper presented at the 1979 SPWLA Annual Logging Sympostum, Tulsa, June 3-6.
10. Culver, R.B.. Hopkinson. E.C.. and Youmans. A.H.: “Carbon/Oxygen (C/O) Logging Instrumentation.” Sot. I’?(. ,!?a~. J (Oct. 1974) 463-70 II Hertrog. R.C. and Plaseh. R E.: “Neutron-Excited Gamma-Ray Spcctrometry for Well Logging.” IEEE Tmm. NW. S-u (Feb. lY79) NS-26. No. I.
ENGINEERING
HANDBOOK
12. 7he Roir of Trace Metals in Petroleum. T.F. Yen (ed.). Ann Arbor Science Publishers Inc.. Ann Arbor (1975). I3 Well Logging and Interprefatiorr Techniques. Dresser Atlas, Houston (1982). I4 Log Interpretation-Vol. 1, Principles, Schlumberger, Ridgefield. CN (1974). 15. Desbrandes, R.: Theorie et Inrerpretarion des Diqraphies, Editlons Technip, Paris (1968). 16 Serra, 0.: “Diagraphies Differ&-Bases de I’lnterpretation,” Bull., Cent. Rech. Explor:Prod Elf-Aquitainc. Editions Technip. Paris (1979). I7 Hilchie, D.W.: Applied Openhole rLq Interpret&on, Douglas W. Hilchie Inc., Golden, CO (1978). 18 Hassan, M.. Hossin. A., and Combaz. A.: “Fundamentals of the Differential Gamma Ray Log-Interpretation Technique.” Trans.. SPWLA (1976) paper H. I9 F&l, W.H.: “Gamma Ray Spectral Data Assists in Complex Formation Evaluation,” The Log Amdyst (Sept.-Oct. 1979) 20. No. 5. 3-38. 20 Serra, 0.. Baldwin, J.. and Qutrem. J.A., “Theory. Jnterpretatton and Practical Applications of Natural Gamma Ray Spectroscopy.” Truns.. SPWLA (July 1980) paper Q. 21 Granberry, R.J., Jenkins, R.E., and Bush, D.C.: “Gram Density Values of Cores from some Gulf Coast Formattons and their Importance in Formation Evaluation,” paper presented at the 1968 SPWLA Annual Logging Symposium, New Orleans. June 23-26. 22 Ellis. D.V. r’t t/l.: “Litho-Density Tool Calibration,” Bx P<,(. 01,~. J. (Aug. 19X5) 515-23. 23 Ellis, D.V. and Case, C.R.: “CNT-A Dolomite Response.” paper S presented at the 1983 SPWLA Annual Logging Sympostum, Calgary, June 27-30. 24 Arnold, D.M. and Smith, H.D. Jr.: “Experimental Determination of Envmxrmental Corrections for a Dual-Spaced Neutron Porostty Log,” paper W presented at the 1981 SPWLA Annual Logging Symposium. Mexico City, June 23-26. 25 Quirein, J.A.. Gardner, J.S., and Watson. J.T.: “Combined Natural Gamma Ray SpectraliLitho-Density Measurements Applied to Complex Lnhologies,” paper SPE 1 I143 presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 26-29. 26 Flaum, C. and Pirie, G.: “Determination of Lithology from Induced Gamma Ray Spectroscopy,” paper H presented at the 1981 SPWLA Annual Loggmg Symposntm, Mexico City, June 23-26. 27 Gilchrist, W.A. Jr. et rrl., “Applicatton of Gamma Ray Spectroscopy to Formation Evaluation.” paper presented at the 19X2 SPWLA Annual Loggin: Symposium, Corpus Chrtsti, July 5-9. 28 Westaway. P.. Hertzog, R.C., and Plasek, R.E.: “The Gamma Spectrometer Tool Inelastic and Capture GaInma-Ray Spectroscopy for Rescrvo~r Analysis,” Sot Per. .h,g. J. (June 1983) 553-64. 29 Oliver, D.W., Frost, E., and Fettl, W.H.: “Contmuous Carbon/Oxygen Logging-Instrumentation. Interpretive Concept\ and Field Applications,” paper TT presented at the I981 SPWLA Annual Logging Symposium, Mexico Cny. June 23-26. 30 Pulsed Neutron Lqging. W.A. Hoyer (ed.), SPWLA Reprint Volume (1979). 31 Herron, M.M.: “Mineralogy from Geochemical Well Logging.” paper presented at the 1984 Annual Meeting of the Clay Mmerals Society, Baton Rouge. Oct. l-4.
Chapter 51
Acoustic Logging A. (Turk) Timur. chc\,roa COT.
Introduction Acoustic wave propagation methods have become an integral part of formation evaluation since the first downhole measurement of velocities was conducted in 1927. ’ These early measurements were conducted to obtain time/depth curves to use in interpreting seismic data.’ In the 1930’s, proposals were made to conduct velocity measurements in a fashion similar to electric logging, by using an acoustic transmitter and one or more receivers. First successful implementation of this technology was in the late 1940’s and early 1950’~.~-’ Commercial acoustic velocity logs were first introduced in 1954 by Seismograph Service Corp. in the U.S. and by United Geophysical in Canada. Since then, technology involving borehole measurements of acoustic wave propagation properties has developed significantly and has become established as a major formation evaluation method. These acoustic wave propagation methods used in well logging can be broadly classified into two groups: transmission and reflection. Properties measured in each method and their applications in formation evaluation are listed in Table 51.1 Compressional wave velocities measured by acoustic logging were found to be related to porosity so closely that the acoustic log became a standard porosity tool. which it still is in many areas. The second most common use of borehole acoustic measurements is in evaluating cement jobs by measurements inside casing. This chapter describes the use of acoustic wave propagation properties in formation evaluation after a brief description of elasticity. acoustic wave propagation properties in rocks, and methods of recording these in the borehole.
Elasticity Introduction The theory of elasticity investigates relationships between external forces applied to a body and resulting
changes in its size and shape.’ In this theory, it is assumed that displacements are small and the body returns to its original condition after the forces are removed. Applied forces and the resulting deformations are described by stresses and strains. Stress is the force, F, per unit area. A, applied; strain, t, is deformation per unit length, t. or volume, V, as illustrated in Fig. 5 1.1. Within the elastic limit, as shown in Fig. 51.2. stresses are found to be proportional to strains (Hooke’s law). The ratio of stress to strain is a different constant for different loading conditions. These proportionality constants are defined as elastic moduli. which are fun damental properties of a material.
Young’s Modulus, E. This is the ratio of tensile or compressive stress (FL/A) to the resultant strain (tL, =ALlL): E=-
FLiA ALIL
Shear (or Torsion) Modulus, G. The ratio of shearing strain E,, =(AL/L) is
stress (F,IA) to the shearing
F,7IA G=-. 6s Bulk Modulus, K. Bulk modulus describes of V under hydrostatic pressure, p:
the change
K=P AVIV where K is also the reciprocal
of compressibility,
c.
PETROLEUM ENGINEERING
51-2
TABLE 51.1-ACOUSTIC
WAVE PROPAGATION
Property
METHODS
Applicatton
Transmission
Compressional- and shearwave velocttles
Compressional- and shearwave attenuations
Reflection Transit time and amplitude of reflected waves
seismic and geological interpretation porosity lithology hydrocarbon content geopressure detection mechanical properties of rocks cement bond quality location of fractures rock consolidation permeability indication location of vugs and fractures orientation of fractures and bed boundaries channeling and microannulus casing quality
Poisson’s Ratio, p, This is a measure of the geometric change of shape under uniaxial stress. It is expressed as d, the ratio of the fractional change in diameter, (transverse strain, eT) to the fractional change in length (longitudinal strain, EL): Adld p=aL,L.. Relationships Among Elastic Parameters. These four elastic parameters are not independent; any one parameter can be expressed in terms of two others: E=2(1 +p)G
Acoustic Waves Acoustic waves propagate mechanical energy. For instance, if an elastic material is subjected to an instantaneous force at one end. it is compressed (Fig. 51.3).
HANDBOOK
This disturbance is then transmitted along the material by a series of compressions and rarefactions. The disturbance travels at a constant velocity that is a fundamental property of the material. The elastic moduli and the density determine the velocity of propagation for each material. Two types of mechanical wave propagation will be described qualitatively. Detailed discussions of acoustic wave propagation are given in Refs. 7 through 11.
Compressional Waves. Compressional
waves are those in which the mechanical disturbance is transmitted by a particle motion parallel to the direction of wave propagation (Fig. 51.3). They are also called longitudinal, pressure, primary, or P-waves. Particles of the material oscillate around this rest position in simple harmonic motion. As they move from equilibrium, they push or pull their neighbors, thereby transmitting the disturbance through the material. The velocity of this compressional wave motion, lip, is a constant for a given material:
v,=+(K+4/,G)“, P
.
...
.
. .(I)
where p is the density.
Shear Waves. Shear waves, also called transverse,
torsional, or S-waves, are those where particle motion is perpendicular to the direction of wave propagation (Fig. 51.4). Particles in the material again move about their rest position with simple harmonic motion. For this motion to be transmitted, however, each particle must have a force of attraction to its neighbor. Whereas compressional waves can be propagated simply by elastic collision of one molecule with the next, attractive forces must exist between adjacent molecules to transmit shear waves. Since these forces are very small in gases and liquids, fluids do not transmit shear waves. The velocity of shear waves, v,, , is also a constant for a given material:
v,,=
G 0 P
% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2)
Yield StrengIh Breaking Point Elastic Limit STRESS t Hooke’s Law Region
STRAIN -
Fig. 51.1-Longitudinal,
transverse, and shear deformations.
Fig. 51 .P-Stress/strain
diagram for an elastic material
ACOUSTIC LOGGING
. . . . . . . . . . .
. . . . . . . .. . . . . . . . . .. . ..I....... . . . . . . . .. . . . . . . . . .. . . . . . . . . .. . . . . . . . . .. . . . . . . . . .. . . . . . . . . .. . . . ..I.. *... . . . . . . . .. . Dlrecllon cd PartIck MOllO”
. . . . . . . . . .
a . . . . . _ . . . . .
51-3
A A B . ..I.. . . .-. . . . . . . . ..a... ..-.. . . ..m. . s.... . . . ..-. . . .. . . . . w...... ..-.. . ..-.. . . .. . . . . . . . . . . .” . . . . . .“. . . .. . . . . . . .-. . . . .. . . . . . . . . ..“.. . . ..m.* L-AW.Wde”gth
. * .
. . . . . . . . . . .
A . .. . . me.* . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . ... . . ... . . ... . .
. . . . . . . . . . .
. . .. . . . ... . . . a. .. .. . . . .. . . . .. . . . . . . .. .. . . . .. . .. .. . . . ... * rJileCtion 0‘wave
of Acoustic Waves
L’= hf,
where X is the wave length. Motion of either compressional or shear waves in an extended medium is characterized by an infinite number of particles, each vibrating in simple harmonic motion. A simple description of this wave propagation is given by a plane wave solution of the wave equation:
u=A cos(2+2n~). where u is the particle motion at a given point, s, away from the source and at any given time, t. At any given time, t=O, the displacement along the wave varies as cos(2as/X); hence, the u is equal to signal amplitude A, where s is equal to even multiples of wavelength-i.e., s=O, X, 2X. Motion of each particle, on the other hand, is described by a simple harmonic motion given by
u=A cos(27rjl). An additional feature of acoustic waves to be considered is attenuation. As one moves away from the source, the intensity of sound decreases. This decrease of acoustic waves results from (1) geometric spread of energy, reflection, refraction. and scattering, and (2) absorption, whereby mechanical energy is converted into heat. The decrease in intensity because of absorption is given by 0
Ware PmpagafK.n
Fig. 51.4-Shear
wave.
Acoustic waves have many characteristics similar to light waves. They undergo interference, diffraction, reflection, and refraction. At a boundary separating materials of two different velocities, they are mode converted, reflected, and refracted according to Snell’s law. For either compressional or shear waves, velocities are related to frequency, f, by
,=I
Dlrecllon 01Parllcle “lbM,lO”I
*:::: r-.... . :* ..*** *. .*...*. :..*..:::: :*.... . . . . . . :.::*..* .“..:. .*:::a .*...*.*:::. .,.. *....... :. .:...*......:::::f:.............‘ . .-.. . .. .*...*a-...-,*. -.*: . . . . . :.:::...:..,.,....:.::::. . .. .. .. .*a.. .*... . .,.* . . . . . . . . *. . . . .**... .*... :.: :::.. ,.....*... *.-Z.“.. .*... *. . . . :::::::.....: .*,,.. . . . . ::::::. ..: . . . . ***... .,.*. .:.*, *.-...a.. .-.-.::e: .:...:.a *...*.a a.. .-a Dlrecllon Of
Propagalion
Fig. 51.3-Compressional
Characteristics
. . . .
B * . * . . . . . . * .
distance,
wave.
s, from the source is
A=A 0 e-ffs 1 where A,, is the amplitude at the source. A schematic diagram of an experimental apparatus is given in Fig. 51.5 to illustrate the measurement of acoustic properties. Two piezoelectric elements are attached to the specimen as shown. A pulser provides the electric pulse to the transmitting piezoelectric element and also triggers the oscilloscope trace. The transmitter vibrates according to the change of voltage with time, generating a mechanical pulse in the specimen. As it travels through the specimen, the mechanical pulse is attenuated. The receiving piezoelectric element converts this attenuated pulse into an electric pulse that is displayed on the oscilloscope screen. The travel time of the mechanical pulse through the specimen is read on the horizontal scale of the oscilloscope, and the velocity is calculated from
L v=-.
t By using a set of either P-wave or S-wave transducers, both velocities, vp and v,?, can be measured as described. These velocities, assuming an infinite, isotropic, homogeneous, and elastic medium, are related to elastic moduli by
4 v,~~=P=K+~G,
v,‘p=G,
..
..
.
. _.
(3)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...(4)
e-2cu.\
where I,, is the acoustic intensity at the source, I is intensity at a distance, s, from the source, and 01 is the coefficient of absorption. The acoustic intensity is proportional to the square of the amplitude; therefore, the amplitude, A. of a wave at a
Fig. 51.5-Experimental apparatus for measurement of velocity and attenuation.
PETROLEUM ENGINEERING
51-4
Acoustic Properties
Or, in more common units, attenuation decibels per unit length, defined as
I
a=-
20
Models
in
A2
Other parameters defining attenuation are the quality factor, F,, and the logarithmic decrement, 6. Coefficients of compressional and shear wave attenuation (op, as) are related to the respective quality factors (Fqp, F,,y) and the logarithmic decrements (6,,, 8,) by
/
1 ffv -=-=F, of
6 a,
where v is velocity Fig. 51 .&Factors
is given
log A’.
L2-L1
\
HANDBOOK
affecting acoustic properties of rocks.
... ....
.
. ....
.
. (6)
and f is frequency.
Acoustic Wave Propagation in Rocks Introduction
and
/A=
o.s(v,/v,)* (v,,v,)2
- 1 , -1
. .
.. .
(5)
where P, K, and G are P-wave, bulk, and shear moduli, respectively, p is Poisson’s ratio, and p is density. As mentioned earlier, these same elastic constants can be obtained directly by measuring lateral and longitudinal strains as functions of stress. Elastic constants measured in this manner are referred to as static elastic constants in contrast to dynamic elastic constants measured through the use of acoustic wave propagation techniques. One method for measurement of attenuation requires specimens of two different lengths from the same material. Assuming that the voltage amplitude of the received signal from the specimen of length L t is A I and from the specimen of length L2 is AZ, and that voltage amplitudes are proportional to the amplitudes of mechanical pulses, the two amplitudes can be expressed as
A, =A,CaLI
and
A
2
=A
0
e-uL2
Hence, the coefficient tained from
cy=-
1 InA’.
L2-L,
A2
of absorption,
nepers/cm,
is ob-
Acoustic wave propagation properties of rocks are known to depend on porosity, rock matrix composition, stress (overburden and pore fluid pressures), temperature, fluid composition, and texture (structural framework of grains and pore spaces), as illustrated in Fig. 51.6. I2 A unified approach involving measurements of compressional and shear-wave velocities, analyses of rock composition, and use of theoretical models to interpret these data was described in Refs. 13 through 16.
Acoustic Properties Acoustic wave propagation properties were described in the preceding section for homogeneous, elastic media. Applications of these relationships to rocks, however, are complicated by the presence of pores and cracks, and fluids contained in them. A simplified, theoretical development is described in the Appendix to illustrate some of these complications by incorporating rockframe, pore-fluid, and rock-grain compressibilities into the velocity equations. As indicated earlier, acoustic wave properties in rocks are functions of numerous independent variables. Therefore, evaluation of various theories of acoustic wave propagation requires laboratory experiments conducted on rock samples under controlled pressure, temperature, and saturation conditions. Various experimental methods have been developed for measuring acoustic wave propagation properties of rock samples. Detailed description of one of the laboratory systems is given by Timur. ” It is designed to conduct sequential measurements of properties of both the compressional and the shear waves on rock samples subjected to simulated subsurface conditions. A typical experimental setup is shown in Fig. 51.7, where a rock sample is assembled between two transducers in a sample holder. This assembly is placed in a pressure vessel and subjected to varying overburden and pore fluid pressures and temperatures. A minicomputer digitally records the compressional and shear-wave pulses transmitted through the rock samples, as well as sample temperature, overburden and pore fluid pressures, and sample length changes.
ACOUSTIC LOGGING
Es v,
” I vi
Navalo Sandstone Porosity PO/P1
11.5. Density
I
00.00
1 - 0.00
2.46
2.30
4.00 0.16
OVERBURDEN PRESSURE, 8.00 12.00 16.00 0.31
0.47
0.62
PSI x 101 20.00 24.00
26.00
0.78
109
0.94
r 7 z
Pore Fluid
Insulated P and S Wave Transmitter
_
Sample (Jacketed)
_
P and S Wave
Thermocouple
Linear Variable Differential Transformer
Fig. 51.7-A
2iirifT@
typical sample (d= 8.9 cm, L = 5.1 cm) assembled for acoustic measurements.
A typical set of compressional and shear-wave velocity data obtained with this apparatus is shown in Fig. 5 1.8. The rate of change of porosity in this sample with varying overburden and pore fluid pressures is shown in Fig. 5 1.9. These data were obtained from concurrcnt measurements of changes in the sample pore and bulk volumes during acoustic measurements. Fig, 5 1.10 illustrates typical compressional and shear wave attenuation data. obtained from the amplitude spectra of transmitted pulses. Porosity Porosity dependence of v,, in rocks has been intensively investigated. “W This forms the basis for estimating porosities from in-situ measurements with an acoustic velocity log. Results of early laboratory measurement of compressional-wave velocities determined on watersaturated sandstones are plotted vs. porosities in Fig. 5 1.1 I. ” The porosity/velocity relationship is within the indicated statistics as long as the lithology remains relatively constant.
Fig. 51.8-Pressure
dependence of compressional- and shearwave velocities in a Navajo sandstone.
Porosity dependence of v,, has also been investigated to some extent.25m28 A change in shear-wave travel times (lit),$) per unit change in porosity ($J) is found to be almost twice the corresponding change in I /II,, Rock
Composition
Rock composition affects the velocities in significant ways, as illustrated in Fig. 51.12.‘” Laboratory data plotted in this figure are for cores saturated with brine and subjected to an overburden pressure of 3,000 psi. The two principal minerals in the rock were quartz. in the form of tripolite, and calcite. They were mixed in relative proportions ranging from approximately 50% quartz to 80% calcite/20% quartz. The calcite/50% samples with lower porosity had a continuous calcite matrix, whereas the samples with a higher porosity had a continuous quartz matrix. Effects of rock composition usually are taken into account by establishing velocity/porosity relationships for each group of rocks of similar composition through correlations of both the laboratory and the field data. This is illustrated in Fig. 51.12 by two separate groupings, one for calcite matrix and the other for quartz. Rock composition plays a significant role in acoustic wave propagation properties. A procedure for comprehensive analyses needed for this purpose was described by Jones et al. I3 First, they conducted a combination of measurements of X-ray diffraction, elemental analysis, clay analysis, and grain density measurements. Each of these then was assigned an experimental error, and linear programming was used to establish the rock mineral composition, as shown in Table 51.2.
PETROLEUM ENGINEERING
HANDBOOK
100 Berea Sandstone
h r 16
60 Fq 40
20
4 1
,L 0
4
8 12 OVERBURDEN
16 20 PRESSURE. PSI x 101
24
0
28
stone.
Stress Pressure dependence of velocities of compressional and shear waves also has been the subject of numerous studies. Velocities of elastic waves traveling in a porous medium are known to be functions of both the external (overburden) pressure, pO, and the internal (pore fluid) pressure, pf. Some of the experimental results indicating dependence of compressional-wave velocity on confining pressure are given in Fig. 5 1.13 for various rock
VELOCITY,
2.5 1
3 I B
30
4.5
T
r
5
15
\
I
10
1
I
0
12
1
,
1
I
/
110
100
90
80
VELOCITY.
70
60
50
sec/ft x 10m6
data determined in laboratory for water-saturated sandstones compared with timeaverage relation for quartz/water system.
0
6
I
7
20 7
r-1
ft/sec (m/s) Matrix 22500 (6858) Brine 5235 (1596)
Calcite
4
Quartz (Tripolite) Matrix 19200 (5852) Brine 5235 (1596)
5
Fig. 51 .l I-Velocttylporosity
5
ft/sec x lo3 15
\p
5
RECIPROCAL
km/s
4 I I--II
0
10
120
3.5 I
3
-1
17
psi
samples including dolomite, limestone, and sandstone and for a sandpack. 29 In general, velocities increase with increasing p0 and decrease with increasing pt. From a theoretical analysis of elastic wave propagation in sphere packs, Brandt3’ predicted velocities to be functions of (p, -npf), where n is a number between 0 and 1. Experimental data of Hicks and Berry”’ and Wyliie et al. I9 indicated n to be close to unity, whereas data obtained by Banthia et al. 32 indicated values of n to
6
---
I
8000
Fig. 51 .I+Pressure dependence of compresslonal and shear attenuation in a Berea sandstone saturated with brine.
Time Average ft/sec (m/s) Malrix 19500 (5944) ’,I Fluid 5000 (1524)
‘9
PRESSURE,
VELOCITY,
4
ft/sec x 103 II!-- _12 13
35
I
6000
km/s
3.5 I
;ci
,
4000
DIFFERENTIAL
dependence of porosily of Navajo sand-
Fig. 51.9-Pressure
I
2000
I
,
I
100
90
80 TRAVEL
P-WAVE
Fig. 51.12-Comparison
I 70
I I 60
\I
\ 50
40
TIME, sec/ft x 10m6
of compressional-wave velocities as function of porosity for brine-saturated tripolite samples under confining pressure of 3,000 psi.
ACOUSTIC LOGGING
TABLE 51.2-ROCK Sample Petrography Grain density Grain porosity X-ray, wt% Quartz Calcite Dolomite Clay Feldspar Pyrite Anhydrite NAA and AAS, wt% Si Al Ti Fe MQ Ca Na :: Phyllo-silicate Computed volume, % Quartz Calcite Dolomite Clay Feldspar Pyrite Anhydrite Silica Siderite
COMPOSITION
Navajo sandstone medium-porosity, well-sorted quartzite 2.60 19.4 93.0 1 1.7 0.7 0.4 42.60 1.20 0.79 0.20 0.02 0.20 0.00 0.16 54.00 6.00 68.37 4.73 0.57 6.93 -
be significantly less than 1. To investigate this discrepancy, Gardner et al. 33 conducted experiments taking into account the past pressure history of samples. They found that p n and pi are equally effective in changing velocities-i.e., n = 1, provided that the differential follows a pressure cycle pressure (pd =po -pf) previously imposed on the sample (Fig. 51.14).
Temperature The effect of temperature on elastic wave velocities is considered to be of second order and usually is neglected in seismic exploration and acoustic log interpretations. To study this effect, early laboratory experiments’4-38 were conducted by measuring velocity as a function of overburden pressure at constant values of temperature instead of as a function of temperature at constant pressure. Also, the effects of pore fluid pressure were not considered. Later, the effects of temperature on the velocities were investigated through laboratory measurements on rock samples subjected to simulated subsurface pressure conditions ” (Fig. 51.15). On the average, the compressional wave velocities were found to decrease by 1.7% and the shear-wave velocities by 0.9% for 100°C increase in temperature. Below freezing temperatures, however, the effect of temperature on elastic wave velocities become much more significant. An increase of 50% or more in compressional wave velocities is observed upon freezing the pore fluid in some rock samples.39 Below freezing, compressional wave velocity in water-saturated rocks was found to increase with decreasing temperature, whereas it was nearly independent of temperature in dry
z G 0
13 -Y
Sandstone 11
d = 18 i
0
2000
4000 6000 8000 PRESSURE, psi
10.000
Fig. 51.13-Compressional-wave velocity vs. confining pressure for brine-saturated carbonates, sandstone and sand pack.
rocks. The shapes of the velocity vs. were functions of rock composition, the pore fluids. Some of the velocity subfreezing temperature is illustrated
temperature curves pore structure, and vs. porosity data at in Fig. 5 1.16. 39-43
Fluid Composition An understanding of the effects of fluid composition on elastic wave properties has become much more significant with the increasing interest in detection of hydrocarbons with seismic measurements. As a result, these effects have been the subject of many studies, both theoretical and experimental, in the recent literature. The
Fig. 51.14-Compressional-wave ferential pressure.
velocity as a function of dif-
PETROLEUM ENGINEERING
51-8
Berea 0
0 ,A
h
Sandstone (,po = 1360, pf = 600 bars) a
I Do
v
o
(PO = 345, pf = 150 bars) 0
0
7
,
3.05
9
a
c Lp? = 138, pf = 60 tars)
0 Compressional Wave Velocity A Shear Wave Velocity c
,i
?
(p. = 1380, pf = 600 bars fi-~ x -A%
2.30
L--~
I
.~
20
0
40
60
80 100 120 140 160 lE0 200
TEMPERATURE. Fig. 51.15-Temperature
shear-wave sandstone.
“C
dependence of compressional- and velocities in brine-saturated Berea
0.40 Simpson
(Ref. 41) 9
0.35 10
E % p- 0.30 k :: ii ’ 0.25 i
14 c G
8 E 5 0.20
0 d >
'6 16
6 0.15
7
/ 0.10
lLaboratory Measuremenls
0
AField Measurements
g
from Alaska
-10 10 20 30 40 50 60 70 60 90 100 POROSITY, PERCENT
Fig. 51.16-Compressional-wave
function of porosity.
first important theoretical contribution was made by Gassmann,44 who described the relationships between pore fluid, rock skeleton (or frame), and the rock grains by starting with first principles of the theory of elasticity. Later, Biot45,46 developed a more comprehensive theory of elastic wave propagation in a fluid-saturated, isotropic and microhomogeneous porous solid over a wide frequency range. Biot’s theory, which reduces to that of Gassmann at low frequencies, incorporates the effects of fluid composition through the density and compressibility of the saturant fluid (see Appendix). Geertsma4’ investigated the applications of Biot’s theory to the interpretation of acoustic logs and estimated expected range of velocity dispersion by comparing velocities at zero and infinitely high frequencies. Since the estimated velocity dispersion was found to be generally less than 3%, the low frequency approximation of Biot’s theory and, hence, Gassmann’s theory is useful for most applications. Brown and Korringa” further generalized Gassmann’s theory and succeeded in removing the requirement of macrohomogeneity. The experimental data of King, 4’ shown in Fig. 5 1.17 for brine-, kerosene-, and air-saturated (dry) Boise sandstone ($=25 %), illustrated the predicted behavior; compressional-wave velocity is greater in brine-saturated rocks than in comparable gas-saturated rocks, with the reverse true for shear-wave velocity. On the other hand, experimental data of Gregory 5o in Fig. 51.18 indicate that for some rocks, shear-wave velocity behavior upon the change of saturation from gas to brine is opposite to the predictions of the Biot theory. This may be due to the presence of isolated microcracks in these rocks, whereas the BiotiGassmann theories assume the pore structure to be open and interconnected. Texture
Umiat
ii
HANDBOOK
20 22 is: SE! 32
velocity of frozen rocks as a
Texture in this context is the structural framework of the rock consisting of solid matrix and pore structure. Its importance in elastic wave propagation has been dramatically illustrated in Fig. 51.19. The data in this figure are the compressional and shear-wave velocities in dry and water-saturated Troy granite with a porosity of 0.3 %. 5’ Velocities were measured as functions of confining pressure by maintaining pore fluid pressure (pf) at 1 bar. Compressional-wave velocities are higher when the rock is water-saturated, whereas the shear-wave velocities are unchanged between the two states. What is most interesting, however, is that a porosity of only 0.3% is affecting the velocities b 20% or more. Classical bounding theories5z-5r obviously cannot account for these large changes in the respective moduli because of large differences between the properties of rock matrix and fluid in the pores. This is because they used the total porosity without considering how it is distributed. Scanning electron micrographs (SEM’s) shown in Fig. 5 1.20 show pore space in Troy granite to consist mainly of thin cracks, typical of most granites. 56 The effects of these cracks on elastic wave propagation properties have been investigated extensively, and many theoretical models have been developed. 14q5’ The theoretical curves shown in Fig. 51.19 were obtained by fitting the velocity data with the noninteractive scattering theory. I4 For these theoretical formulations, the rock is
ACOUSTIC LOGGING
---O
2.9 -r? E x 5 2.7 ti d >
-0
Brine -A
Kerosene Dry 0.90
2.1 0.85 1.9
0
5
10
15
20
25
POROSITY,
30
35
40
O/o
1.7 velocity ratio vs. porosity for dry, (v,),, fully water-saturated, (v,),. rocks.
Fig. 51.18~S-wave
and
1.5 Boise Sandstone 6 = 25% DEPTH,
1.3
0
0.1 0.2 DIFFERENTIAL
0.3 0.4 PRESSURE,
km
0.5 k bar
Fig. 51.17-Observed and theoretical compressional- and shear-wave velocities in Boise sandstone as a function of pressure for three saturation flulds. The circles, triangles, and squares are laboratory data from King for brine-, kerosene- and air-saturated (dry) samples.
assumed to consist of a solid matrix and pores of spherical and oblate spheroidal shapes. Using the SEM’s as a guide and the porosity as a constraint, the pore space was modeled by a spectrum of pore shapes ranging from spheres to very fine cracks. Theoretical velocities were calculated as a function of pressure by first determining the ranges in pore shapes at each pressure condition. Depending on the fit, the pore aspect ratio (ratio of minor to major axis of an ellipsoid) spectra were adjusted and calculations were repeated until good fits were obtained to all velocities. Theoretical curves plotted on Fig. 5 1.19 are based on the final model. Effects of various pore shapes on acoustic velocities as predicted by the noninteractive scattering theory are illustrated in Fig. 51.21. The effects shown in this figure are for a rock with matrix properties of K,,, =0.44 megabar, G=0.37 megabar, and pm=2.7 g/cm’; for water with K,,, =23.2 kilobar and pw, = 1 g/cm”; and for gaswithK,=1,5XlO-‘kilobarandp,=lO-’g/cm’. As indicated, for a given porosity, the thinner (smaller aspect ratio) pores affect the velocities much more than the spherical pores.
1:: 1~
0
,
,
0.2
0.4
DIFFERENTIAL
---
0 Sat’d
-
0 Dry
Troyyranite
0.6 PRESSURE,
0.8 k bar
and theoretical compresslonal (v,) and shear (w,) velocities in dry and water-saturated Troy granite as a function of differential pressure. The data (points) are from Ref. 51.
Fig. 51.19-Observed
PETROLEUM ENGINEERING
51-10
Fig. 51.20~-Scanning
electron micrographs of pore system cn Troy granite
HANDBOOK
ACOUSTIC LOGGING
51-11
This theory also was used to analyze the “wellbehaved” (according to Biot/Gassmann) experimental data of Fig. 51.17, where the results are plotted as solid and longand short-dashed curves. Additionally, however, it also can explain the “unexpected’ ’behavior of the experimental data of Fig. 5 I. 18, as illustrated in Fig. 5 1.2 1 by its predictions for the S-wave velocities in rocks with pores of various shapes. Modeling of the real rock can be achieved by approximating the regular pores by spheres and rounded spheroids and by approximating the grain boundary spaces and flat pores by low-aspect-ratio cracks. However, there is no practical way to measure a pore aspect-ratio spectrum independently. An extensive study by Hadley 58 involved counting hundreds of cracks on three SEM’s, each covering about 1 mm2 of rock surface. These results are being used for testing “crack” theories. So far, these theories have added much to our understanding of acoustic wave propagation; their practical applications, however, have not yet materialized.
12345012345 --
-\ -.
1 y
--Az,.oi
I\
I\
\
I
\
1
1, I
', \\
I
1.c
\
',o,,
.
\ \
'1 'h
'\
\
\ I
I
'1
\ .
\
I
\
I
\
I “il-:“‘
\
'
\,,,,r
\o.os
O.O!
::,“:r;a:r
\ 0.01
1
I
P-Wave I I POROSITY,
I %
I
1 I
/
S-Wave 1 I POROSITY,
1
1
%
Fig. 51.21-Normalized P- and S-wave velocities vs. columr 1 concentration of inclusions (porosity) of different aspect ratios for water- and -gas-saiurated pores, respectively.
Acoustic Wave Propagation Methods
Summary Factors affecting acoustic wave propagation properties of rocks were illustrated in a qualitative fashion with emphasis on compressional and shear-wave velocities, mostly because attenuation properties are much less understood. Among the factors influencing velocities, porosity, lithology (mineral composition and structural framework), saturation and differential pressure are considered primary, and the others, with certain qualifications, secondary. As the previous discussion indicates, significant advances have been made in understanding the properties of acoustic wave propagation in rocks. Further advances will be made because of the significance of this work, not only in formation evaluation, but also in seismic exploration.
Introduction Acoustic wave propagation methods used in well logging can be classified into two groups: transmission and reflection (Table 51.1). In the transmission method, one or more transmitters emit acoustic energy, which is transmitted by formation and/or casing and is detected by one or more receivers. In the reflection method, one or more transducers emit acoustic energy, part of which is reflected by the borehole wall and/or casing and is detected by the same transducer. In this section, both the transmission and reflection methods will be described, starting with a description of acoustic wave propagation in a borehole and followed by various methods of recording acoustic data.
(A) Wavefronts
Fig. 51.22-Compressional, P, and shear, S, wave propagation in or around a fluid-filled borehole.
PETROLEUM ENGINEERING
traveling with a velocity, waves reach the borehole and refracted. For angles wave critical angle tI1,,
Pseudo-Rayleigh
Compressional
I
i Airy Phase
IIMt+
Fig. 51.23-Acoustic
waveform.
vf. in the mud. When these face, they are both reflected of incidence less than the Pm
part of the energy is transmitted into the formation in the form of compressional wave and another part as a shear wave, and the remainder is reflected back into the mud as a compressional wave, all according to Snell’s law. At or near the P-wave critical angle, a shear wave is still transmitted into the formation and P-wave reflected back into the mud, but a P-wave is critically refracted and travels with the v,’ in the formation, close and parallel to the borehole wall, while continuously radiating P-wave energy back into the mud at the same P-wave critical angle (Fig. 5 I .22). At the S-wave critical angle (o,,). O,y=sin-’
Acoustic Wave Propagation in a Fluid-Filled Borehole The propagation of elastic waves in a borehole filled with liquid has been studied extensively.60-70 Only a qualitative description of the phenomenon will be given here for identifying the components of an acoustic pulse reoorded in a borehole. The general geometry for the transmission method is illustrated in Fig. 51.22, which shows a single receiver logging sonde. Two pressure transducers are spaced on an acoustically insulated body, the upper one to generate compressional waves in the borehole fluid and the lower one to detect compressional waves reaching it. The receiver converts these waves to electrical signals. These are transmitted to the surface and displayed on an oscilloscope as a record of received-signal amplitude vs. time and recorded either in analog form on film or digitally on magnetic tape. This received signal, which is referred to as the acoustic waveform, represents several acoustic waves and is illustrated by the synthetic waveform trace shown in Fig. 51.23. For the usual case of a liquid-filled borehole in a formation with both the compressionaland shear-wave velocities higher than borehole fluid velocity, two body (or head) waves and two guided waves are propagated. These waves are shown in Fig. 5 1.23 in the order of their arrival time at the receiver: (I) compressional wave, (2) shear wave. (3) pseudo-Rayleigh waves, and (4) Stoneley waves. Compressional and shear waves, which are also called P. primary, and S, secondary waves, respectively, are head or body waves because they travel in the body of the formation. Pseudo-Raylcigh and Stoneley waves, which also are called reflected conical (or normal mode) and tube wave (or water arrival). respectively, arc guided waves because they require the presence of the borehole for their existence. A description of the various ray paths of these waves may help further in understanding elastic wave propagation in and around the borehole. The acoustic transmitter shown in Fig. 51.22 generates compressional waves
HANDBOOK
“f , ( v5 >
the S-wave is critically refracted and travels with the \J,, in the formation along a path similar to that of the refracted P-wave. It also continuously radiates P-wave energy back into the mud at the S-wave critical angle (Fig. 51.22). Beyond the S-wave critical angle, all the incident energy is reflected back into the mud to form the guided pseudo-Rayleigh waves (Fig. 5 1.24). To summarize, the compressional wave travels as a Pwave between the transmitter and the formation, in the formation, and also between the formation and the receiver (PPP); the shear wave travels as a P-wave between the transmitter and the formation, an S-wave in the formation, and again as a P-wave between the formation and the receiver (PSP). If the formation shear-wave velocity is slower than borehole fluid velocity, shear waves cannot be refracted along the borehole wall; therefore, no shear head wave is generated. As described earlier, compressional and shear waves travel at velocities determined by the elastic moduli and the density of the formation:
.(7) and
(.. p,, is the bulk density
.
.
of formation, and I,, and I, are compressionaland shear-wave transit times. The body waves travel at all frequencies at speeds given by Eqs. 8 and 9. They are nondispersive (variation of velocity with frequency is negligible), and undergo attenuation and geometric spreading. Attenuation, 01, of the body waves is proportional to the logarithmic ratio of the amplitudes, A 1 and A?, at distances s t and s? from the source 15,t6:
ACOUSTIC LOGGING
where (Y is in decibelift and F,, is a geometrical spreading factor. The tingy packet shown between the compressional and shear waves is called the leaky or PL mode. 66 It is a guided wave generated by the interaction of the formation with totally reflected compressional waves between the compressional and shear critical angles. Paillet and White@ have shown that the leaky mode propagates at a velocity close to that of compressional waves in the formation and its phase velocity decreases with increasing frequency. They also have shown that the leaky mode amplitude, and hence the shape of the compressional wave train, varies with a change of Poisson’s ratio. Pseudo-Rayleigh and Stoneley waves are the two main guided waves. They both arrive after the shear wave, have larger amplitudes and longer durations than cithcr the compressional or the shear wave, and are disperaivc.67 The pseudo-Rayleigh wave is gcneratcd by the total internal reflection of the acoustic energy at the borehole face beyond the shear critical angle. It travels within the borehole by multiple internal reflections without loss of energy into the formation; therefore, it is a guided wave. Its amplitude decays exponentially in the formation away from the borehole face, but is oscillatory in the fluid. A pseudo-Rayleigh wave is not generated unless I’., > l’f and it travels with a velocity 11,.such that vf< I’,. s v,> with an Airy phase traveling slower than ‘f. Fig. 5 I .25 shows the dispersion characteristics for the phase and group velocities of the guided waves in a fluid-filled borehole. ” The parameters used are (1) for the formation, P-wave velocity= I5 x IO3 ftisec, S-wave velocity=9~ 10’ ftisec, density=2.3 g/cm”, and (2) for the borehole fluid, P-wave velocity=6x 10’ ftisec, density = 1.2 g/cm3 : the borehole diameter is 8 in. The phase and group velocities plotted are normalized to the P-wave velocity of the borehole fluid. As shown in this figure, the pseudo-Rayleigh waves are very dispersive. At the low-frequency end. there is a cutoff frequency below which these waves are not generated. At this frequency, the pseudo-Rayleigh wave phase velocity is equal to the shear-wave velocity of the formation and it steeply decreases with increasing frequency and asymptotically approaches at high frequencies the velocity of the fluid in the mud. Group velocity of pseudo-Rayleigh wave has an Airy phase that travels more slowly than the borehole fluid velocity (Fig. 5 1.25). Pseudo-Rayleigh waves have large amplitudes and arrive after the refracted shear wave, often making identification of the smaller-amplitude S-wave arrival difficult. However, only a small error is made if the velocity estimates are made by using the pscudoRayleigh arrivals. The second type of guided waves is the Stoneley wave. which is the true surface wave coupled between the borehole fluid and the formation. The particular motion of these waves is shown in Fig. 5 1.26. 7’ where Y is the borehole radius. Their amplitudes decay exponentially both in the fluid and in the formation away from the borehole face. As shown in Fig. 51.24, they are slightly dispersive. have no geometric spreading, and travel at
51-13
<
-----
p
-
s Guided Waves
-.
-.
Fig. 51.24-Two-receiver
sonde and the ray paths of body and guided waves.
CUtOIl Frequency
- -
0
Group
I 10
I 20 FREQUENCY.
I 30
ktiz
Fig. .51.25-Dispersion characteristics of the pseudo-Rayleigh and Stoneley waves.
51-14
PETROLEUM ENGINEERING
HANDBOOK
velocities slightly slower than that of the borehole fluid or formation shear wave velocity, whichever is less. Unlike the formation shear wave or pseudo-Rayleigh waves, Stoneley waves always are present, whether or not v,~ is greater than vf. They arrive as a compact pulse slightly later than that for a direct fluid arrival or shear arrival if v,~< vf. Stoneley wave amplitudes are high at low fre uencies and decay rapidly with increasing frequency. 9 ’ In the low-frequency end, the Stoneley waves are called tube waves and travel with a velocity, v,, given by’ i I r
Rock
r=R
0
Fig. 51.26-Stoneley
“f
v, =
Elorehole F.X.?
Kf
( 57
(or tube) wave particle motions
,~,
. . .. .. . .. . .. .. .. . ... . . ...
>
where Kf is the bulk modulus Q=P~;
(9)
of the fluid, given by
>
and
Formrtlo”
Fig. 51.27-Transit tool.
time measurement
by a single-receiver
ou1put
Therefore, in formations with v, < vf, so that neither shear nor pseudo-Rayleigh waves are present, the Stoneley wave can be used to estimate formation shearwave velocity if formation bulk density is available from a density log. The dispersion characteristics described so far (of the pseudo-Rayleigh and the Stoneley waves) are for a borehole containing a point source. The effects of the logging sonde on dispersion behavior also have been investigated by Cheng and Toks6z.67 Their study indicated, first, that the dispersion curves for the pseudoRayleigh wave are shifted to lower frequencies as the borehole radius increases. They further found that for a relatively rigid tool, presence of a logging sonde simply makes the borehole diameter appear smaller, thus shifting the dispersion curves to higher frequencies. As stated at the beginning of this section. only a qualitative description was given of the elastic wave propagation in a fluid-filled borehole. Ray theory is only an approximation when describing elastic wave properties in a cylindrical geometry. Accurate description of this phenomenon requires solution of the wave equation for cylindrical boundary conditions. The reader is referred to the references given at the beginning of this section for a more quantitative treatment.
From Receiver 1
Methods of Recording Acoustic Data
OlAput From Receiver 2
Fig. 51.28-Transit
time measurement by a two-receiver tool.
As described in the previous section, an acoustic waveform is rich in information. It may have four component waves: compressional, shear, pseudo-Rayleigh, and Stoneley. Each of these, in turn, has four measurable properties: velocity, amplitude, amplitude attenuation, and frequency. 27 Various methods of logging were developed to record one or more of these properties. A brief description of some of these logging techniques, with emphasis on those in more common use. follows.
ACOUSTIC LOGGING
--------
51-15
MeasuredTnnsltTlmr
Fig. 51.29-The effect of hole enlargement on the response of acoustic velocity logging tools: (a) one-receiver type and (b) two-receiver type.
Conventional
Transmitter
Acoustic Logging
The most commonly used property of acoustic waves in a borehole is the velocity of compressional waves. In conventional acoustic logging, the time, t, required for a compressional wave to travel through 1 ft of formation is recorded as a function of depth. This parameter, 1, referred to as the interval transit time, transit time, or travel time, is the reciprocal of the velocity of the compressional waves:
,=,,J“P
Transit time also is referred to as compressional-wave slowness and is identified as fP to differentiate it from shear wave transit time:
Velocities observed in acoustic logging vary from 4,000 to 25,000 ft/sec; hence, the travel times range from 40 to 250 ~s/ft.
Tool Characteristics. The original acoustic logging tool, as mentioned earlier, used one transmitter and one receiver (Fig. 51.27). Values of L recorded in this arrangement, however, also include travel time of sound in mud in the borehole. To remove this component, a dual-receiver commercial tool was introduced74 to measure the time difference between the arrival of the signal at the first receiver and at the second receiver (Fig. 51.28). Two-receiver systems, however, also were found to be unsatisfactory, especially at boundaries of hole irregularity, 75 as illustrated in Fig. 5 1.29. To improve accuracy of 1 measurement further, a borehole-compensated sonde (Fig. 51.30) with two
lr Transmitter
Fig. 51.30-Borehole-compensated
acoustic log
PETROLEUM ENGINEERING
51-16
Caliper Hole
BHC
Diam.
Measurements +I
from Lower Transmftler
Log
2’ Span
Inches i
Sonic
HANDBOOK
t p see/it 16
100
70
40
LT
Fig. 51.31-Travel
time measurement with the borehole-compensated acoustic log.
transmitters and four receivers was developed.76 This borehole-compensated tool may be considered to be systems. As ilcomposed of two separate two-receiver lustrated by the measurement scheme in Fig, 5 1.3 1, perturbations caused by hole irregularities are oppositely directed; therefore, they cancel. These sondes usually have a 2-ft span between the receivers with a 3-ft spacing between each transmitter and its near receiver.
Fig. 51.32-Presentation
of acoustic log
Log Presentation. Transit time 1 measured by acoustic velocity logs is recorded as a function of depth across Tracks 2 and 3 in units of microseconds per foot (psecift). The typical example shown in Fig. 51.32 also has the integrated travel time recorded at the left edge of Track 2 as a series of pips, placed at l-millisecond intervals.
Additional Curves Recorded. A three-arm
caliper and a gamma ray curve can be recorded simultaneously in Track I of the conventional acoustic logs (Fig. 51.32). The gamma ray curve can be replaced or supplemented by a spontaneous-potential (SP) curve; however, this SP should be used only for qualitative interpretation because of proximity of the electrode to the metal in the sonde.
Tool Span. The usual span for the acoustic log receivers
h
ib,
Fig. 51.33-The
effect of bed thickness on the response of an acoustic velocity logging device: (a) bed thinner than the span and (b) bed thicker than the span.
is 2 ft; however, tools with receiver spacings of 3 in.77 to 1 rn” or longer also have been developed for special applications. The shorter the span, of course, the more detail given by the tool. The relative effects of bed thickness. h, and tool span on measured transit times are illustrated in Fig. 5 1.33. The log measures only the formation between the receivers. The measured transit time is the weighted average of transit times in formations between the receivers.
Cycle Skipping and Triggering on the Noise. In transit time logging, the first arrival of the acoustic pulse must trigger both receivers of the sonde to yield correct values
51-17
ACOUSTIC LOGGING
SP
1 /
1’Span
5 7; L-
-
Detection
3’Span
3’Span
P
Cycle Sklpptng .Accentuated
4
I
Levels
Near
Receiver -
Far Receiver
I
14
Fig. 51.34-Cycle
I + 1 Cycle
skip and triggering on the noise
of t. Under certain conditions, even though the first arrival is strong enough to trigger the first receiver, it may be attenuated to such an extent that by the time it reaches the far receiver it may be too weak to trigger it (Fig. 5 I .34). Instead, the far receiver may be triggered by a later arrival in the same acoustic pulse. This causes large and abrupt increases in the recorded transit time values. This phenomenon, known as “cycle skipping,” may occur when the signal is strongly attenuated by (1) gas sands, especially if they cause gas in the mud; (2) poorly consolidated formations: (3) recently drillstem-tested intervals, because of the release of gas; (4) fractured formations: and (5) aerated mud. If the detection levels are set too low, however, either one or both receivers may be triggered by noise, which is always present as the tool is being dragged up the hole. Depending on the receivers involved, triggering may cause 1 spikes either too short or too long. Examples of cycle skipping and trig ering by noise are illustrated in Figs. 51.35 and 51.36. $9
Calibration. The precision of measurement of acoustic transit time with the acoustic log is determined by the precision of the timing circuitry, which, in turn. is controlled by the frequency of the quartz crystal used. For the usual crystals of 2.5 MHz, the potential resolution of the transit time measurement is f0.4 psecift. The accuracy of the transit time measurement, however, depends on many other factors in addition to the precision of the timing circuitry. A discussion of some of the factors affecting the measurement of transit time is given by Thomas.‘j
Fig. 51.35-Sonic
log run in Edwards limestone: (a) 1-ft span, (b) 34 span, and (c) 34 span with intentionally accentuated cycle-skipping.
An essential factor is to ensure the proper calibration of the logging system. Calibration procedures of each commercially available acoustic velocity system are described in respective service company manuals. These should be required before and after logging to ensure the accuracy of the surface equipment. It is important to emphasize, however, that most calibration procedures do
Interval
Induction Resistivity (API 50
Units) 100
Travel
0.2
2.0
150
200 -7-
Fig. 51.36-Cycle
Time
(psecht)
(f]M)
x
skip and noise on acoustic log
100
PETROLEUM ENGINEERING
TIME,
2000
@SEC
just that. They merely check linearity of some of the circuitry in the surface instrumentation without any input from the downhole sonde. A true calibration requires measuring the response of the complete system, surface instrumentation, and sonde in a standard environment. For this purpose, the tool is placed in a fluid-filled steel sleeve and transit time is checked against the known value of 57 psec/ft. In addition, some free pipe in the surface casing should be logged while going in and coming out of the hole, and checked against the value for steel of 57 psec/ft. Anhydrite beds, with a transit time of 50 pseclft, and other formations with known transit times sometimes can be used to check the accuracy of the log; however, these methods are useful only if the downhole velocities in naturally occurring rocks are known not to vary from location to location or with depth of burial.
3000
Amplitude/Time
Fig. 51.37-Acoustic
HANDBOOK
As described earlier, the acoustic wave (Fig. 51.37a) contains information other than compressional wave velocity. One of the methods developed to record some of this formation is the amplitude/time recording. In this method, which is also called the “X-Y mode,” the amplitude of acoustic energy is recorded as a function of time at preassigned depths along the wellbore (Fig. 5 1.37~). Usually, this is achieved by analog recording of the output of one of the receivers on film. Within the last few years, however, the introduction of wellsite and downhole computers has made possible the digital recording of waveforms from an array of acoustic receivers. For example, with one of these tools, a waveform is digitized at every %-in. depth interval of the borehole to obtain more than 500 data points. Processing of this wealth of new information is a current area of research that is expected to increase significantly the usefulness of borehole acoustic measurements.
waveform recording
Intensity/Time
L
Sonde
Fig. 51.38-Approximate volume of investigation tional acoustic logs.
Recording
of conven-
Recording
For most applications, analog recordings of waveforms at %-in. depth intervals are rather cumbersome to use. Hence, for routine use, to obtain a continuous recording or a log, waveforms are recorded in the intensity/time mode. In this presentation, each waveform is reduced to a series of dashes of varying width and intensity, depending on its frequency and amplitude (Fig. 51.37b). The process can be visualized by rotating the acoustic waveform of Fig. 51.37b by 90” on its horizontal axis and then recording the positive-going portions of the wave train as series of dashes and leaving the negativegoing portions as blank spaces, as shown in Fig. 51.37 c. The intensity/time log (Fig. 51.37d) is obtained by stacking these dashed lines from each depth interval. Unfortunately, this process has not been standardized. Some service companies have the negative part of the waveform as the dark dashes and the positive part as the light blanks; other companies, vice versa. Also, some service companies have the time increasing from left to right, while other companies increase in the opposite direction. The various trade names for this presentation are Variable Density Log’” (VDL) by Schlumberger and Dresser, 3-D Log’” by Birdwell, and Micro-Seismogram Log’” by Welex.
ACOUSTIC
LOGGING
51-19
Long-Spaced Acoustic Logging Conventional acoustic logs have a Introduction. relatively shallow depth of investigation, Di. The approximate bulk volume of the rock investigated by conventional acoustic logs is illustrated in Fig. 51.38. so This region is most subject to alterations because of stress relief, mechanical damage caused by drilling, and chemical alteration (clay hydration) caused by drilling fluid. An important early study by Hicks” clearly demonstrated that acoustic velocities in certain formations sensitive to damage were significantly lower when measured near the borehole face than when measured deeper in the formation. Hicks” clearly demonstrated that these borehole effects on acoustic velocities diminish with increased transmitter-to-receiver spacing. Since then, many investigators have observed drastically poor logging data caused by borehole enlargement and formation alteration around the borehole.
Borehole Size, Effects of borehole geometry on log measurements can be considered in terms of hole rugosity and hole enlargement. Borehole rugosity, which can cause significant errors in pad-type tools (such as density. sidewall neutron porosity, microrcsistivity, and highfrequency dielectric measurements) can produce diffractions in acoustic waves propagating along the borehole. In general, these should not affect the first-arrival compressional transit time measurements but can affect the
Fig. 51.40-Effects
Long Spacing 8-10
190
ft Sonde
160 170 160 7 i
150
2
130
Conventional 3-5 ft Sonde
140
120 110 Transmitter-Near Receiver Spacing
100 90
6
8
10
12
14
16
16
20
HOLE DIAMETER. IN. Fig. 51.39-Maximum
detectable formation various transmitter-to-near-receiver
of cavity on density, sldewell neutron, and acoustic logs.
transit time, spacing.
51-20
PETROLEUM
HANDBOOK
Long Spacing (E-10 11)
Conventional (3-5 11) 120 100
40
R
ENGINEERING
150
5 I a <
Long Spacing Acoustic Log
R
R
Conventional Acoustic Log
R
150
120
30
100
9
‘r\;; e :::I d :_p :. :.1 z:i; o:::.’ n I; e::jI :. ::. ‘.::: :. .’
i g i n
f
2 a p
10
E’ 20
A I
1
;
r ::: ., :.:.:. :. m ‘.:. :. a t ‘ ....:,‘ . ‘ .. i ‘..,.I. ‘. .’.‘ ‘.. 0 ‘. .. & n
T
Fig. 51.41-Comparison
of depth of investigations of conventional and long-spacing acoustic logs.
amplitudes. The hole size, however, can have a significant effect on the transit time measurements if the hole is large enough and the tool is centralized because the acoustic energy traveling directly down the hole in the mud might arrive at the receiver before the formation compressional wave. Hole size effects on acoustic measurements have been investigated extensively. ‘%** For a centralized tool, Goetz et al. 8L computed the travel times along the direct mud path and the refracted path in the formation, for various hole sizes. Some of their results are illustrated in Fig. 5 I .39 in terms of I vs. borehole diameter. Below the line labeled conventional 3- to 5-ft sonde, a centered tool will read the formation transit time. Between this line and the dashed line (computed for a receiver with a 5ft spacing from the transmitter), a centered tool will record a value intermediate between formation and mud transit times. Above the dashed line, a conventional acoustic log measures the velocity of compressional waves in the mud. The upper solid line is for a longer-spacing acoustic log with 8- to lo-ft receiver spacing. Below this
2
3
4
5
6
7
8
9 IO 11 12 13 14 1s
ALTERATION DEPTH (Inches from Borehole Wall) Fig. 51.42-Effects of formation alteration on measurements with convemional (3 lo 5 ft) and long-spacing (8 to 10 ft) acoustic sondes.
line, the long-spaced tool measures high formation transit times in larger-diameter holes in the range where conventional tools would record incorrectly low formation travel times. Even though these borehole size effects are important. conventional borehole-compensated acoustic logs can record reliable measurements under much more adverse borehole conditions than other porosity tools, such as density and neutron tools. The influence of a cavity on the density, sidewall neutron, and conventional acoustic tools is compared in Fig. 5 1.40. s3 In this figure, over the elliptical cavity indicated by the calipers on the density and acoustic logs, both the density and sidewall neutron curves are useless, whereas the acoustic log provides reliable data. This feature of the acoustic log is used to complement density and neutron porosity that are not reliable because of poor hole conditions.
Formation Alteration. A more important
factor affecting the borehole acoustic measurements is formation alteration or damage around the borehole (Fig. 51.41). This can occur because of stress relaxation near the borehole wall, mechanical damage caused by prolonged exposure to drilling, or chemical alteration of the fomation by interaction of drilling fluid with sensitive clays in the formation. Under these conditions, accurate measurements of acoustic velocities depend on hole size and transmitter receiver spacing, as well as velocities of both altered and unaltered zones around the borehole. Formation alteration was investigated by Goetz et ul. ** by assumi n g a step profile transit time around the borehole, with the altered or damaged zone having a transit time kd that is greater than the undisturbed formation 1 and a mud transit time of 200 psec/ft. They computed the depths of investigation of conventional acoustic (3- to 5-ft) and long-spacing (8- to lo-ft) acoustic logs in a 10.in.-diameter borehole. They also
51-21
ACOUSTIC LOGGING
,’ LTd’
10' 12' 10'
Fig. 51.44-Borehole-compensated
transit time measurements: (a) conventional and (b) depth derived.
LTl
to 12-ft spacing. Borehole compensation is accomplished by a depth-derived measurement scheme illustrated in Fig. 51.44b, rather than the inverted array technique shown in Fig. 5 1.44a, which was described earlier (Fig. 5 1.3 1). To obtain the transit time at depth level, first the transmitter Tr is pulsed twice and the respective times fI =Tr -RI, t? =Tr --‘RI are recorded. The transit time for this case is given by
II -tz tI =-
psecift, 2
Fig. 51.43-Schlumberger
long-spacing sonic log.
calculated formation alteration (td-t) as a function of alteration depth for unaltered formation transit times of 100, 120, and 150 psec/ft. Their results, plotted in Fig. 5 I .42, illustrate the ability of the longer-spacing tool to overcome the effects of formation damage. In this figure, the area to the left of each curve represents the conditions for reliable measurements. For example, at an alteration of 20 psecift, a conventional tool can handle an alteration of 5 in. if the formation transit time, I, is 100 psec/ft, but only 3 in. if t= 150 psec/ft.
Long-Spacing Acoustic Logging Tool. Both the borehole enlargement and the formation alteration effects can be accommodated by acoustic tools with longer transmitter-to-receiver spacings. A schematic diagram of the Long Spacing Sonic’” by one such tool, Schlumberger, s4 is shown in Fig. 5 1.43. Two transmitters, 2 ft apart, are at the bottom, and two receivers, 2 ft apart, are at the top, with 8ft spacing between the two sections. Two long-spacing logs are recorded concurrently, one with 8- to IO-ft spacing and the other with lo-
which is subject to errors discussed earlier if the hole size is different at the two receiver positions. After the tool has moved 9 ft 8 in. up hole, the transmitters will be spanning the same depth interval between the points of refraction. This time they are each and the travel times, t3 =Tt -+R? and pulsed, f4 =Tz +Rz are recorded by the second receiver (Rz). For this second case, the transit time is given by
f4 -13 11 = -
psecift,
2 which is subject to the same errors as t, but in an opposite direction. The depth-derived transit time for the 8 to IO-ft spacing is obtained by averaging these two measurements:
II +t2 t2 A similar borehole compensation is obtained for the lo- to 12-ft spacing by using the second transmitter T2 in the first position, instead of T , , and the first receiver R r in the second position, instead of RZ
51-22
PETROLEUM ENGINEERING
250
HANDBOOK
pseclft
LJJ BHC Sonic Travel Time (psedft)
‘( :. Spacing
140
Hole O::n 4 Days --------_---_ --Hole Open 79 Days
-r-r-~Ir-lr-~-r1-l
r y-r 7
40
T r
.
r
i
-I
..C'> CT
r
-;
., -'
,, _ ' . j
Fig. 51.45-Formation
Fig. 51.46-Conventional and long-spacing acoustic logs tn a sand/shale section.
Effects of prolonged exposure to drilling and drilling mud on acoustic velocities measured with a conventional borehole-compensated acoustic log are illustrated in example logs in Fig. 5 1.45 taken from the reference by Misk et al.*’ The dashed curve is obtained after the hole has been exposed to drilling for 4 days with the borehole relatively undamaged; the solid curve is after 79 days of exposure. During this period, the formation over much of the interval has been damaged enough to increase the 1 by 30 psecift or more. As described previously, long-spacing acoustic logs are less affected by altered zones A comparison of conventional and long-spaced acoustic logs is shown in Fig. 51.46 for a sand/shale section.73 In the upper section, the conventional log is reading higher values of I than those by the long-spacing tool, probably because of shale alteration. In Sand Z, both logs are in agreement. whereas in sections directly above and below Sand Z. the conventional log is reading significantly higher values of t. probably because of hole washouts.
The example in Fig. 5 1.47 is a comparison of the two acoustic tools in shallow and deeper Louisiana gulf coast of both sand/shale sequences. s6 Physical characteristics the shale at 3,470 ft and the sand at 3.500 ft have been altered by drilling and interaction with mud filtmte. The conventional spaced tool is reading 15 psecift higher because of this alteration. This is also reflected by a lo-millisecond difference between the respective transit time integration curves shown in the depth tract. In the deeper section, as the formations become more compacted, the formation alteration is reduced; hence, the conventional and long-spacing measurements are in agreement within the interval 8,500 to 8,600 ft. Even though, in most instances. the t values from 8- to IO-ft and lo- to 12-ft spaced receivers are in agreement, very deep formation alteration can sometimes affect the I values recorded by the S- to IO-ft receivers. The example in Fig. 51.48 is from a shallow well with modified depths. ” In the upper zone, the 8- to IO-h spacing is reading values higher by IO psecift than those given by
alteration caused by exposure to mud; bit size 12% in.
ACOUSTIC LOGGING
51-23
GR
160
psedft 60
b :I il i i
-
Fig. 51.47-Conventional (BHC) and long-spacing (LSS) acoustic logs in a Louisiana gulf coast sand/shale sequence.
the lo- to 12-ft spacing, because of very deep formation alteration. In the lower section, the 8 to IO-ft spacing still reads a few microseconds higher down to the compacted formations below depth 227 ft. In the final example shown in Fig. 51.49, the better response of the long-spaced logs in enlarged boneholes is illustrated. In the upper section, the conventional spaced tool is reading the mud transit time in a hole washed out
Fig. 51.48-Very
deep formation alteration.
to 20 in. In the lower section, the borehole is not washed out but the conventional tool is reading up to 60 ,usec/ft too high because of formation alteration. Below 8,700 ft, all three curves (i.e., the 3- to 5-ft, 8 to lo-ft, and IO- to 12-ft curves), are in agreement.
Summary. significantly
Borehole size and formation alteration can affect the properties of acoustic waves
PETROLEUM ENGINEERING
51-24
HANDBOOK
1 \
’
II -
\
I / c
I
3’-5’+\ BHC :
,‘“L
I Fig. 51.50-Identification of shear arrivals on analog recording of (a) acoustic waveforms and (b) variable-density (3D) presentations.
1 II I I I_ I / I-
-I i
traveling in a borehole. The long-spaced acoustic tools are much less affected by borehole conditions and yield more reliable values of compressional-wave transit times under borehole conditions in which conventional tools would be grossly in error. The vertical bed boundary resolution of the long-spaced tool is the same as that of the conventional tool since the receiver spacing is 2 ft for both. Because of the longer transmitter-to-receiver spacing, the acoustic energy has to travel farther; therefore, it is attenuated more. This has caused more frequent spiking and cycle skipping on the long-spaced acoustic logs; however, this technology is improving through the introduction of more powerful transmitters, more sensitive receivers, downhole digitizing, and surface processing of waveforms.
Shear-Wave
Fig. 51.49~-Response of conventional and long-spacing acoustic logs In an enlarged borehole.
Logging
The borehole acoustic measurement methods described so far have been for obtaining compressional wave velocities. The desirability of obtaining other information contained in the acoustic waveform has long been recognized. I7 Most of the effort has been directed toward obtaining the velocity of shear waves. Early attempts involved hand-picking the shear-wave arrivals on the analog recording of either waveforms or variable-density-microseismogram or three-dimensional (3.D)-presentations as illustrated in Fig. 5 1.50e3 Another method involves automatic recording of shear-wave travel times by a bias technique. “v’)’ In this a high-amplitude event following the method, compressional-wave arrivals is assumed to be the shear wave arrival. The transit time of these waves is measured by setting the voltage bias level higher than the compressional-wave amplitudes. A thorough investigation of conventional methods for determining shear-wave velocities from long- and shortspaced acoustic logs was conducated by Koerperich.” In this study. borehole experiments were conducted by using a conventional Schlumberger Borehole Compensated Sonic Log@ (BHC) with two transmitters and four receivers at 3- and 5-ft spacing and a Schlumberger experimental long-spaced tool with a single transmitter and four receivers located at 10, 12. 14. and 16 ft from the
ACOUSTIC LOGGING
transmitter. Waveforms recorded with these tools in a carbonate section are shown in Fig. 51.51 for several transmitter-to-receiver spacings. As indicated in this figure, it is easier to identify the later arrivals on the longer-spacing waveforms because of the greater separation in arrival times. Some measurement results from this study are shown in Figs. 51.52 and 51.53 for a carbonate and a sand/shale section, respectively. For both compressional and shear waves, long spacings generally yield slightly lower travel times (higher velocities) than short spacings. Another important aspect of this study involved laboratory measurements of acoustic velocities on core samples. Compressional and shear-wave velocities were measured on core plugs subjected to simulated subsurface overburden and pore pressure conditions. These results are lotted as circles in Figs. 51.52 and 51.53. Koerperich r, states that average agreement between the laboratory and log shear velocities (for both the longand short-spaced tools) is within 2% for carbonates and 8% in sandstones, and that it is slightly better for the compressional waves. He states further that these differences between the laboratory and the log values are nonsystematic. The foregoing discussion demonstrates that determination of shear transit times in a borehole by hand-picking the arrival times from waveforms or from variabledensity presentations is at best a tedious and not very accurate process. Further, attempts to automate this process by threshold detection have been subject to errors when using an axial transmitter/receiver logging technology designed primarily for measurement of compressional-wave travel times. The reasons for these errors are explained by some of the recent modeling studies of acoustic wave propagation in a fluid-filled borehole. 6sm67These studies demonstrate that the shearwave arrival is indistinguishable from the onset of the reflected conical waves on the synthetic acoustic waveforms. However, the phase and group velocities of the reflected conical wave at its low-frequency cutoff are equal to the formation shear-wave velocity (see Fig. 5 1.25). Hence. if the onset of the reflected conical wave is measured in error, the transit time will be close to that of the shear wave. This might be the case in some of the previously discussed studies.
Acoustic Array Logging Borehole modeling of acoustic wave propagation has demonstrated the need for a new generation of acoustic logging technology to extract more information from acoustic waveforms. Acoustic logging tools having arrays of transmitters and receivers, and complex digital signal processing capabilities have been developed to analyze the data obtained. One such tool is shown in Fig. 51.54.” It has a Iowerfrequency transmitter (1 1 kHz vs. the conventional 20 kHz), an array of four receivers placed at a longer spacing from the transmitter, and a downhole digitizer to record waveforms without cable distortions. Surface instrumentation records the signals digitally. The processing method, using a four-fold correlation algorithm. analyzes waveforms from the four receivers simultaneously to obtain compressional and shear-wave transit times (Fig. 51.55).
51-25
Depth. II
r
T-R Spacing
“S‘ Wave Time Pick
591.6
3’
591.6
5
-
5946-v
10’
12’
594 7
1000
0
2000
Time.qec
waveforms recorded at various transmitter-to-receiver spacings in a carbonate section.
Fig. 51.51-Acoustic
Another acoustic array log is a 12-receiver experimental sonde developed by Schlumberger. ” It has a single and an array of 12 receivers. The IO-kHz transmitter receivers have been arranged both in a nonuniform array spanning 4 ft with spacings of 0, 6, 9, 12, 1.5, 18, 21, 24, 27, 30, 36, 42, and 48 in. and in a uniform array spanning 5.5 ft with 6 in. between the receivers. The spacing between the transmitter and a receiver array is adjustable between 5 and 25 ft. An experimental tool developed by Elf Aquitaine uses an array of transmitters and an array of receivers. ” The transmitting array has five transmitters uniformly spaced at 0.25 m apart; hence, it has a span of 1 m. The receiving array has 12 receivers uniformly spaced at I-m intervals. The distance between the receiving and the transmitting arrays is set at 1 m. Finally, the prototype sonde by Schlumberger (shown in Fig. 51.56) has an eight-receiver array and two transmitters.‘j In addition, it has two additional receivers spaced at 3 and 5 ft from the transmitter to simulate conventional tools. It also has the capability to measure the compressional-wave velocity of the waveforms are digitized borehole fluid. Again, downhole and transmitted to the surface for recording and analysis. As apparent from the previous discussion, this is a very active area of development. Tools are constantly being developed to explore the extraction of additional such as pseudo-Rayleigh and Stoneley information, wave velocities, from acoustic waveforms. Capabilities are being developed to record large amounts of data. For example, more data are obtained with one of these array tools in a l-mile-deep well than are recovered in a l-mile seismic section. A parallel and complementary area of development is signal processing methods for analyzing these data. Processing methods such as direct phase determination, y4 slowness time coherence, 93 and semblance 77,95 have been developed to permit automated analysis of shear-wave transit times. Array processors are being added to wellsite data acquisition systems to permit realtime signal processing.
51-26
PETROLEUM ENGINEERING
Fig. 51.52-Borehole and laboratory measurements of compressional- and shear-wave transit times in a carbonate section.
Fig. 51.53-Borehole
and laboratory measurements of compressional- and shear-wave transit times in a sand/shale section.
HANDBOOK
51-27
ACOUSTIC LOGGING
I
0
r----
Gamma Ray APIU
,
-------------
-;rx;]
,
L------------------l Van Cartridge
1
(Telemetry. Analog-toDigital bonvertk)
T&& Compr.
0.3 Ill
tP
0.3 Ill 0.3 In
-
C
spacers
iii four-receiver acoustic array log with a downhole digitizer.
Fig. 51.55-Compressionaland shear-wave transit time log obtained by analysis of the waveforms recorded with the sonde in Fig. 51.54.
So far, emphasis has been on extraction of shear-wave velocity from acoustic waveforms. With continued improvement in tool design and signal processing, it is expected that in the not too distant future, acoustic logs will record not only the velocities of compressional, shear, pseudo-Rayleigh and Stoneley waves, but their attenuations as well.
generate a picture of the borehole wall. When the borehole wall is smooth, the amplitude of the reflected signal is high; it is recorded as a light spot. Lowamplitude reflections from fractured or vuggy walls are recorded as dark spots. The resulting log is essentially a black and white picture of the borehole wall, split vertically along magnetic north and flattened (Figs. 51.58 through 5 1.60). For the borehole televiewer (BHTV) log, the vertical scale is depth and the horizontal scale corresponds to azimuth of the borehole wall. An isometric view of a vertical fracture intersecting the wellbore in an east-west direction is shown on the left in Fig. .51.58.97 The corresponding BHTV log on the right shows the fracture as two vertical dark lines 180” apart. Similarly, an isometric of a south-dipping fracture or bedding plane is shown with the corresponding BHTV log in Fig. 5 1.59. An example of a BHTV log (SeisvieweP by Birdwe1198) based on amplitude imaging is shown in Fig.
Fig. 51.54-A
Reflection Method The reflection method of acoustic wave propagation logging is basically similar to sonar. A single transducer rotates at constant speed, emitting acoustic pulses in the megahertz range and recording their echoes from the borehole face (Fig. 51.57). As in the transmission method, both travel times and amplitudes are used. The azimuth of the beam also is recorded. The first such logging tool, the borehole televiewer, Vh used only the amplitude of the reflected signals to
PETROLEUM ENGINEERING
51-28
S
Receiver Electronics
R ~
W
E N
Fluid-Delta
1III.
T Measurement
Wideband Receivers Spaced 6” Apart
*o-
--_ . --.
N
il
Vertical Fracture Intersecting Well Bore
E
S
W
N
BHTV Log
Fig. 51.58-Isometric
Rg\
Two Standard
UT\
Ceramic
Two Low-Frequency
Receivers
Transmitters
LT/’
Transmitter
Electronics
l-l Fig. 51.56-An
HANDBOOK
eight-recerver
acoustic array sonde.
of a vertical fracture intersecting a borehole and corresponding BHTV log.
51.60 for a borehole intersected by two fractures. The corresponding isometric on the right describes the two different dips and strikes. Significant hardware and signal processing improvements have been made to early BHTV uses transit technology. 97,99-101 Current technology time information to obtain an image, in addition to the image obtained from the amplitudes of the reflected signals. Transit time images complement amplitude images in many ways. Transit time measurement is essentially a near-perfect borehole geometry tool with a resolution of 0.05 in. BHTV images developed from the transit time measurements can be considered as twodimensional (2D) relief maps of the borehole. Further use of transit time measurements is made in generating tilted polar scan displays. 99 These are essentially 3D casts of the borehole, which can be viewed from all directions. The tilted polar scan of Fig. 51.61 shows a damaged section of a casing viewed from two angles, which also can be viewed from any desired angle.
Applications Introduction Some present and possible future applications of acoustic logging will be presented to illustrate the use of borehole acoustic measurements described earlier and listed in Table 51.1. Discussion here will emphasize the more important uses, and only references will be given to more routine and less significant ones.
Seismic and Geological Interpretation
Fig. 51.5743lock
diagram of BHTV logging system.
Borehole measurements of acoustic properties were developed originally to obtain time/depth curves to use in seismic interpretation. lo2 In addition to recording transit times of the compressional waves as functions of depth, acoustic logs also integrate these data and record a tick mark on the log for each millisecond of elapsed time. These marks are then used in conjunction with check-shot surveys for seismic interpretation. 79,‘03 Recent advances in borehole shear-wave velocity recording also have allowed this technology to be used with surface seismic shear surveys in a way similar to the compressional-wave velocity log use with the seismic compressional surveys. ‘04
ACOUSTIC LOGGING
51-29
An important geological application of acoustic logs has been for correlating geologic sections. As described earlier (see Fig. 51.39), acoustic log response is much less affected by borehole irregularities than are some of the other porosity logs. As a result, acoustic logs provide valid data over a large proportion of the borehole. Further, acoustic logs usually show much character and detail. Therefore, they have been useful for locating bed boundaries, identifying gas/oil interfaces, and determining subsurface geology. An example of geological correlation is shown in Fig. 5 1.62; even though the two wells in this figure are 10 miles apart, the character of the compressional transit time curves is quite similar.
Porosity Borehole measurements of acoustic velocities were instrumental in the development of quantitative formation evaluation in the 1950’s, although they were developed initially to aid seismic interpretation. Over the years, the primary use of acoustic logs in formation evaluation has been the determination of porosity from measurements of compressional-wave transit time (t= l/v,). Earlier in this chapter, factors affecting acoustic properties were described through both theoretical and experimental studies of elastic wave propagation in porous media. On the basis of these discussions, it would be at best naive to expect a simple linear relationship between porosity and compressional-wave transit time. However, empirical observations have indeed demonstrated the validity of such a relationship under certain special conditions.
BHTV
Dip:
Orientation
Angle:
tan-’ h/d
Log
of Minimum
Fig. 51.59~isometric
of fracture or bedding plane intersecting borehole at moderate dip angle, and corresponding BHTV log.
N
E
S
W
N
5560
Consolidated Rocks. A commonly
used linear relationship for estimating porosity from acoustic measurements (based on laboratory measurements of acoustic velocity and porosity in porous rocks and other materials) was proposed by Wyllie et al. 18,t9 Commonly referred to as the Wyllie time-average equation, it is expressed as
Dip Ang le q ir ec lia n 58’ N 70 E
5561
5562 Angle Direction 740 N 46 w
5563
5564
1
G
, (l-4)
VP
“L
V,
. . ..
or in terms of transit times,
. .
(10)
as
5565
Fig. 51.60-BHTV
indicating two fractures of different dips and
strikes.
t=&+(l-4)1,,
......
. . . . . . . . . . . . . . (11)
where ( (= 1lvP) = transit time of the compressional waves for the liquid-saturated porous medium, I~(= l/vL) = transit time for saturant liquid that forms the solid frame of the porous medium, t, (= l/v,) = transit time for rock matrix that forms the solid frame of the porous medium, and $I = porosity. This relationship 1’(hL -tm)++t,
can be rearranged ..
as
.... ....
. . . . (12) Fig. 51.61-BHTV tilted polar image of a section of a damaged casing.
PETROLEUM ENGINEERING
51-30
Fig. 51.62-Acoustic
log correlation between two wells
Porosity Evaluation from I
d=-X-
,I/(//.//.. 30
40
50
t -t,
I
Ipwtm
FCP
60
70
60
I,,
90
100
110
120
/Jsec/ll v,
ftlsec
i,.
@?c/ft
Sandsloner
16,000
- 19,500
55.5
- 51.3
Limestones
21,000
- 23,000
47.6
- 43.5
Dolomites
23,000
- 26,000
43.5
- 38.5
Fig. 51.63-Porosity
evaluation from acoustic log
130
HANDBOOK
where the slope is m=tL-t,,, and the intercept is b=t,. The most attractive feature of Eq. 12 is its simplicity. It states that the transit time of an acoustic wave in a porous rock is the porosity-weighted average of its transit times in the matrix and the liquid in its pores. Also, it extrapolates to correct values for 0 and 100% porosities-i.e., I, and tL, respectively. This simplicity coupled with pedagogically pleasing qualities made Eq. 12 popular and, more importantly, established acoustic logging as an important tool in formation evaluation. As stated, however, there is no theoretical justification for such a simple relationship. In the Appendix, the linear relationship, Eq. 13, is shown to be a second-order approximation of a comprehensive relationship, Eq. A-9, with the intercept h approximately equal to the matrix transit time and the slope m strongly dependent on elastic properties of the porous rock frame and the compressibility of pore fluid. Nevertheless, under the right conditions, a linear dependence of transit time on porosity has been established through literally hundreds of empirical observations. A graphical representation of the time-average equation, Eq. 11, is given in Fig. 51.63. lo5 This is a good beginning for determining porosity from acoustic log measurements when no other information is available. It provides acceptable values of porosity for wellcompacted rocks with uniform pore size distribution and under effective stress (difference between the overburden stress and pore fluid pressure) of at least 4,000 psi. In most applications, the linear relationship of Eq. 13 has been found to be more useful than the time-average equation, Eq. 11, provided that the values of b and m can be determined. As indicated in the Appendix, the parameter b is approximately equal to (l/v,,,); therefore, it depends on rock matrix properties. Published values for b range from 50 to 60 yseclft for sandstones, from 45 to 50 for limestones, and from 40 to 48 for dolomites. Velocities of compressional and shear waves for a large number of materials are given in handbooks by Clark lo6 and by Simmons and Wang. lo7 An extensive list of compressional and shear transit times have been compiled by Wells et al. lo8 for minerals and rocks encountered in oil and mineral exploration. Probably the most comprehensive compilation of compressional and shear-wave velocities for marine sediments, rockand rocks is given, for various forming minerals, pressures and temperatures, in a recent handbook by Carmichael. ‘09 A set of compressional and shear-wave velocity data from the literature is listed in Table 5 1.3 ” for selected materials, to illustrate the range of velocities encountered in and around the borehole. The values of m depend on the elastic moduli of the rock frame, which in turn are controlled by the effective stress and pore structure and by the compressibility of the pore fluid. Changes in velocities have been observed to become smaller with increasing effective stress. Therefore, pressure dependence of m may be small enough to be neglected in normally pressured sections below 7,000 ft. Effects of pore structure might be
ACOUSTIC LOGGING
51-31
TABLE 51.3-ACOUSTIC
VELOCITIES
Material
v,(fllsec)
v,(ftlsec)
Nonporous solrds anhydrite calcite cement (cured) dolomite granite gypsum limestone quartz salt steel Water-saturated
20,000 20,100* 12,000 23,000 19,700 19,000 21,000 16,900 * 15,000* 20,000 porous rocks in situ
dolomites limestones sandstones sands (unconsolidated) shales‘
11,400 12,700 11,200 11,100 12,000 8,000 9,500
Porosity (o/o) 5 to 20 5 to 20 5 to 20 20 to 35
20,000 18.500 16,000 11,500 7,000
to 15,000 to 13.000
to 11,500 to 9,000 to 17,000
11,000 to 7,500 9,500 to 7,000 9,500 to 6,000 -
Liquids’ * water (pure) water (100,000 mg NaCIIL) water (200,000 mg NaCIIL) drilling mud petroleum
4,800 5,200 5.500 61000 4,200
Gases air (dry or motst) hydrogen methane
described qualitatively by stating that the magnitude of m increases with decreasing grain contact areas. Thus, m is small for crystalline rocks and larger for granular and shalier rocks, ranging from 0.5 to 1.5 psec/ft for carbonates and from I to 3 psec/ft for sandstones. Compressibility of the pore fluid depends on whether it is gas, oil, or water and becomes significant in poorly consolidated rocks (see Eq. A-7). In well-consolidated rocks under high effective stress, the relative contribution of pore fluid compressibility to the overall rock elastic moduli is small; therefore, variations of m because of pore fluid content may be neglected. The large range in values of b and m necessitates the use of core analysis data to calibrate the acoustic log for estimating porosity. For this purpose, porosities and travel times are measured on core samples under the equivalent subsurface pressure conditions, and the linear relationship between the two is established by statistical analysis. If laboratory measurements of I are not available, restored pressure measurements of porosity, or porosity corrected for equivalent subsurface conditions can be correlated to I from the acoustic log to establish the linear relationship. provided that adequate depth correspondence between core and log data can be established. There are numerous field examples of acoustic log measurements yielding reliable estimates of porosity in well-compacted, clean sandstones and carbonates, provided that the lithology is known. Fig. 51.64 illustrates
1,100 4,250 1,500
the close agreement between acoustic-log-measured transit times and core-measured porosities for carbonate sections in two wells. In fact, the acoustic log in certain areas is the most consistently reliable porosity device. To reiterate, the conditions required are (1) lithology is accurately known, (2) porosity is largely intergranular, and (3) rocks are well compacted and subjected to a differential stress of at least 4,000 psi. As with other conventional porosity logs, variations in lithology make porosity estimates from compressionalwave transit times unreliable. To overcome this. acoustic logs are used with density and/or neutron logs, or with measurements of shear-wave transit times described in the next section.
Secondary Porosity. Another application of the acoustic log is for estimation of “secondary porosity” in vugular and/or fractured rocks. For this, it is assumed that compressional wave velocity is affected only by the primary or intergranular porosity. The density and neutron logs are assumed to respond to total porosity. Hence, any difference between these is assumed to be secondary porosity consisting of vugs and/or fractures. An example of this is shown in Fig. 5 1.65, where the section contains anhydrite with fracture porosity. ’‘u Notice that while the transit time I remains approximately constant over the entire section, density oh decreases from 2.97 to 2.83
51-32
PETROLEUM ENGINEERING
South
Ralph
Wevburn Mlsswpplan
Saskatchewan
100 Salt
Steelman
LImestone Tlrn.3
85
Potential
millivolts
-
30
25
40
100
1 ft, 2 Receivws
21
15 ~--
Self
(%) 10
Saskatchewan
Tranl,, 55
Poro.lfy
Field
Limestone
/Jsec/tt
70
Spacing
35
(Kvqsford)
M~ss~rs~pp~en Tranr,,
HANDBOOK
Specsng
Potential
/.lsecm
70
mdlivolts 5
Tlrnl?
85 -
55
40
1 ft. 2 Receivers
Porolltv
-
(%)
0
/ 3
> L-
Sonic Log /---ore Analysis
Zore I 4naIySiS-j-
t / / I
I --_--+-I ----i--1
t
‘?.
I r
;
’
-
i
+
I~<-,
Note: Porosity Scale Based on Matrix Velocity , Vm
Fig.
51.64-Acoustic
log
vs.
core
analysis
porosity
q
23,000 ft/sec
-1 L L-
ACOUSTIC LOGGING
g/cm 3 . and the neutron porosity 4 W increases from 0 IO 4%. thereby indicating a secondary porosity of 4%.
Poorly Consolidated Rocks. In poorly consolidated sandstones, reliability of porosity estimates from acoustic logs is rather poor. In these cases, usually a combination of density and neutron logs is preferred. One significant advantage of the acoustic log is that it is much less affected by the hole conditions, such as washouts and rugosity. This was illustrated in Fig. 5 I .39 where the density and sidewall neutron logs were responding to hole conditions whereas the acoustic log was found to yield reliable estimates of porosity. Several methods have been developed to obtain porosity information from acoustic logs in poorly compacted sands. 21.1’1 One approach 2’ involves adjustment of porosity calculated from the time-average equation using a compaction correction factor Fc,,. First. the apparent porosity $,, is computed from
I$,=-.
‘-‘,,I
...
. .
-
.(14)
~1‘ - ’01 t Then this value is corrected rected porosity, 4,.. from
&=$.
by F,,
to obtain the cor-
.
.
.(15)
‘P The values of Fc7, (Fig. 5 1.63) range from 1 to 1.6 or higher. One method used to estimate F,, is based on estimating the compaction of sands from the compaction of adjacent shales. If the transit time of adjacent shales is 100 psecift or less, they are assumed to be compacted. Hence. to obtain the correction factor, the transit time L,,,~ observed in the nearby shales is divided by 100.
FcP=*. 100
.
.
. ..
.. ..... .
.
.(16)
Other methods for determining F,, include determination of porosity either from a resistivity log in a waterbearing sand or from other porosity logs such as density and/or neutron, and then comparing the value with 4,, obtained from the acoustic log. More recently another empirical relationship for estimating porosity from compressional-wave velocity was developed by Raymer et al. ’’’ on the basis of extensive field observations of transit time vs. porosity. The relationship reported is for the full porosity range from 0 to 100%; however, for the porosity range of interest, 0 to 37%, it is expressed as
Fig. 51.65~Secondary porosity in the Auquilco formation. Neuquen basin, Argentina.
TRANSIT
where v, is 17,850 filsec for sandstone, 20,500 ftisec for limestone, and 22,750 ftisec for dolomite, respectively; and of is velocity of sound in the pore fluid.
TIME,
psedlt
Fig. 51.66-An empirical relationship for estimating porosity in sandstone, limestone, and dolomite.
PETROLEUM ENGINEERING
51-34
HANDBOOK
Time Average Eq. 1, 56 psec/li.
a) Laminated c) Grain Boundary Structural
l Clean
Sands
A Shaly
Sands
b) Framework Velocity,
Structural
ft/sec d) Dispersed
80 I,
50 Fig.
90
INTERVAL
100 110 120 130 140 150 7J60 TRANSIT
TIME,
vsec/ft
correlations for moderately consolidated to unconsolidated sands.
51.67-Velocity/porosity
Sandstone
Fig. 51.68-Shaly sand models for acoustic wave propagation studies.
A graphical representation of this empirical relationship is given in Fig. 51.66. Raymer et al. t It found this relationship to be a better estimator of porosity than the time-average equation. They also reported that it is applicable to both consolidated and unconsolidated rocks. Predictions from this relationship and from the timeaverage equations were investigated by Hartley It* for the moderately consolidated to unconsolidated sands of the Gulf of Mexico. The lack of agreement indicated in Fig. 5 1.67 led Hartley to the universally applicable conclusion that empirical relationships “may provide erroneous porosities if they are applied outside of the data set from which they were developed.”
fif 95 1
0
CD Clay
0
-
Laminated
--
Structural
-.-
Dispersed
Shaly Sands. Another
Compressional
10 CLAY/SHALE
20
30
FRACTION
Fig. 51.69-Estimated shale effects shear velocities.
40
50
OF FORMATION,
on compressional
60 %
and
aspect of Hartley’s study t ” considers the effects of shaliness in porosity interpretation. In Fig. 5 1.67, porosity predictions from the empirical relations are worse for the shaly sands. Effects of shales on acoustic velocities are not very well understood; as a result, they are difficult to account for. A recent theoretical study by Mineart’” shed much light on this problem by relating clay effects to their distribution within the rock framework. Minear used the KusterToksoz ‘I4 model of porous media and divided clay distributions into four groups. As illustrated in Fig. 51.68, these four groups are (1) the laminated model (Fig. 51.68a), in which clay-mineral-rich and shaly layers alternate with clean sandstone layers. (2) the framework structural model (Fig. 51.68b), in which shale grains substitute for quartz grains randomly, (3) the grain boundary structural model (Fig. 5 1.68c), in which shale grains occur at some, but not all. boundaries between the quartz grains, and (4) the dispersed clay model (Fig. 51.68d), in which clays occur dispersed in the pore fluid or lining the pores but not between the grain contacts.
ACOUSTIC
90
51-35
LOGGING
110
100
130
120
150
140
I,, dn Laboralory
Data
(Ref.
27)
Field
Data
C Limestone
OLtmertone
ADolomite
QDolomltc 0 Sandntone
1 Sandstones
Fig. 51.70-Compressional-wave transit time.
(hiked
Lithologlar
Excluded)
transit time vs. shear-wave
One of the obvious conclusions in this study is that the time-average equation is applicable to the laminated model. A more interesting conclusion, however, states that the framework (Fig. 51.68b) and grain-boundary (Fig. 5 1.68~) shales seem to have the same effect on acoustic velocities. Further results of this study are summarized in Fig. 51.69. The differences, t&ly -tclean, between the transit times of the shaly and clean formation for both the compressional and shear waves are plotted vs. the clay or shale fraction for a sandstone with a porosity of 30%. Structural and laminated shales have approximately the same effect on I,, and l-5 but increase t,, more than I,, Dispersed clay, if it has a density close to that for sandstone, has about the same effect on L,, as the structural and the laminated clays: however, its effect on I,, is only about one-third of that by the other two.
Lithology Estimation of lithology from conventional acoustic log measurements may be made by solving for the matrix travel time from the time-average equation if the porosity is known from another source. Even though this technique has been used under certain conditions, matrix transit times of the most common rock types determined in this fashion are not distinct enough to make this a very useful method. A more deterministic method for establishing lithology from acoustic log measurements is based on the relationships shown in Fig. 5 1.70. In this figure, laboratory- and borehole-measured values of compressional-wave transit times are plotted against shear-wave transit times. Laboratory data cover a porosity range of 5 to 30% for sandstones and 5 to 2.5 % for carbonates. and an effective stress range of 0 to 6.000 psi.” As indicated, each lithology has a well-defined trend, regardless of porosity or effective stress (depth). Lines of equal velocity ratio
Fig. 51.71-Compressionalto shear-wave velocity ratio vs. compressional-wave velocity. Data from Fig. 51.70.
(v,Iv,) are closely spaced for dolomites and limestones1.8 and I .9, respectively. The sandstones range from 1.6 for low-porosity sands to 1.75 for highporosity sands under low effective stress. Lithology identification is also illustrated in Fig. 51.71 by replotting the velocity ratio data of Fig. 5 1.70 vs. compressional wave velocities. Use of borehole measurements of compressional and shear transit times is described by NationsEX for determining porosity and lithology in mixed-lithology rocks. He assumes that velocity ratio is a constant for a “pure” rock type: 1.6 for sandstones, 1.8 for dolomites, and 1.9 for limestones. He further assumes that mixed-lithology rocks will exhibit a ratio that is directly proportional to the content of the two minemls and that porosity is distributed equally between the two. From the velocity ratio, he first determines the mineralogical composition; then, on the basis of this information, assigns the appropriate matrix transit time for calculating porosity. An example of the results of this technique is illustrated in Fig. 5 1.72 for dolomite/sandstone and dolomite/ limestone mixtures.
Hydrocarbon
Content
Acoustic signals on microseismogram or variabledensity logs are known to disappear sometimes in oil and gas zones in unconsolidated formations. This property is used to locate oil/water contacts. as well as gas caps, but is not completely reliable. Sometimes, even within the bame zone, signal disappearance may or may not be indicative of presence of hydrocarbons. Laboratory studies conducted by Gardner and Harris”’ on sandpacks indicate that shear-wave velocities decrease when liquid is added to sandpacks, whereas the compressional-wave velocity increases (Fig. 51.73).
51-36
PETROLEUM ENGINEERING
Lithology
HANDBOOK
Set
0 Dolomite-Sandstone *Dolomite-Limestone
4\ c
Water Saturated
- 1000 ps, 200 PSI
3
Dolomitlc Sandstone With Part of Pore Space Not Connecte
3 0. 0. 0
0 0 FDC-CNL
I 10
I
I
I
I
I
20
30
40
50
60
POROSITY,
POROSITY.
Fig. 51.72-Porosity
from compressional-wave transit time corrected for lithology by the velocity ratio vs. porosity from density/neutron crossplot for complex lithologies.
\ \ \ -we_
5000
,y
\
psig
‘.
Fig. 51.74-Ratio
of compressional-wave to shear-wave velocity for sands and consolidated rock.
These observed differences between compressional and shear-wave velocities are illustrated by plotting velocity ratio as a function of porosity and pressure (Fig. 5 1.74). Also shown in this figure is the velocity ratio range of 1.75 & 0.20 for the consolidated sedimentary rocks. A velocity ratio greater than two indicates an unconsolidated sand saturated with liquid. Below this value it may be either an unconsolidated sand containing gas or a consolidated rock. For the consolidated rocks, the ranges of velocity ratios for liquid and gas saturation were obtained by Gregory50 through laboratory measurements. The results of his study are summarized in Fig. 51.75. Additional experimental data obtained on a sandpack are shown in Fig. 51.76. ’I6 Laboratory measurements of compressionaland shear-wave velocities are measured as a function of water saturation and plotted on this figure together with measured values of density. These data and the previous observations may be interpreted in general terms through use of the GassmannBiot theory described in the Appendix. Taking the square roots of Eqs. A-l and A-2 gives, respectively,
\
I L’,,= PC/ +f(Kf) Ph ‘%[ I
I
20
40
and
POROSITY, 40 Fig. 51.73-Variation
of compressional-wave and shear-wave velocilles of wet and dry sands with porosity at 5,000 psig differential pressure.
v,,=
G % . ( Ph >
Predictions of these equations also are plotted on Fig. 5 1.76 as dashed lines. One of the predictions of Eq. A-l is that for 100% gas saturation, incompressibility of pore
ACOUSTIC LOGGING
1 .QO
,.20 _ 1.10 0
Consolidated Sedimentary Rocks Pressure Range - O-10,000 psi I 5
I 10
I I I 1 15 20 25 30 POROSITY, %
1 35
1 40
Fig. 51.75-Variations of velocity ratio with porosity for watersaturated and gas-saturated rocks.
fluid (K$ is much smaller than that of the rock matrix (K,,,); hence, f(Kf) becomes negligibly small (see Eq. A-4). Therefore, P-wave velocities calculated from this equation for the gas-saturated rocks are smaller than those for the liquid-saturated rocks. The S-wave velocity, however, becomes the function of gas saturation through dependence on the bulk density because the shear modulus G is the same for the rock whether it contains gas or liquid. Hence, as indicated in Eq. A-2, shear-wave velocity increases upon introduction of gas to the extent that the bulk density decreases. Returning to the P-wave velocities, since the compressibility of gas is much larger than that of water, a small amount of gas reduces pore fluid compressibility essentially to that of gas as predicted by Eq. A-7 (see Appendix). Cf=S,,.c,,.
fii $J = i e
5.0
I Measured
4.0’7
i
I (VP)
,
-I ---L-__-!-Computed rvp)’ I
/
0.2
0
WATER
I Ii i -----/ I
0.6
0.4
0.8
SATURATION,
Fig. 51.76-Compressional-
and shear-wave velocity and bulk density vs. saturation for a sand pack.
Sonic, ii secift -200 180 I I 1.o 10.0 Resistivily f!M 1
Induction
I
I
in both intervals.
Effects of gas saturation on the compressional to shear-wave velocity ratio is illustrated in Fig. 5 1.78 for a deep dolomite reservoir. ‘I7 Over the 18,500 to 18,520-ft interval the v,,Iv, ratio is 1.8; this is as expected for a dolomite lithology. Over the gas zone below 18,520 ft, however, this ratio is reduced to 1.6, and clearly differentiates the gas zone. A similar gas effect is shown in Fig. 5 I .79 for a sandstone reservoir. In this ratio is reduced
the gas zone.
from
130
I
Log
where cX is gas compressibility. Hence, a small amount of gas reduces compressional-wave velocities significantly, but additional gas saturation has little further effect. This was illustrated by the laboratory data and theoretical prediction plotted in Fig. 5 I .76. A field ex51.77 confirms this by ample shown in Fig. demonstrating that compressional-wave transit time does not differentiate the upper zone at 90% gas saturation from the lower one containing 20% gas, because the I curve essentially is responding to the velocity of the mud
clearly dehneating
1.0
S,
i-(1 -S,,.)c,,
case, the vp/v,
1 1.
1.67 to 1.5 1, again
Fig. 51.77-Gas
effect on acoustic log
100.0 I
PETROLEUM ENGINEERING
51-38
Fig. 51.78-Gas effect on compressional- to shear-wave velocity ratio in a dolomite reservoir.
1.6
1.7 t
Velocity
Fig. 51.81-Scope pictures from selected levels in the log on Fig. 51.80.
In general, the effects of gas saturation on acoustic velocities in rock may be summarized as follows. 1. Compressional-wave velocity is greater in liquidsaturated rocks than in comparable gas-saturated rocks, whereas the reverse is true for shear-wave velocities. 2. The difference in compressional-wave velocity for the liquid- and gas-saturated states becomes negligibly small with increasing depth, whereas the equivalent difference for the shear-wave velocities remains constant. 3. Under equivalent pressure conditions, compressional-wave velocity decrease upon gas saturation (in poorly consolidated rocks) is much greater than that in well-consolidated rocks. Attenuations of elastic waves are also used to identify gas zones. ’I8 This is illustrated in the typical Gulf Coast sandsshowninFigs.51.80and51.81.InFig.51.80,the induction log indicates two gas zones: one in a thin stringer at 5,476 ft and the other in a massive sand at 5,520 ft underlain by water. Scope pictures in Fig. 5 1.8 1 were recorded with a single-transmitter, dual-receiver acoustic log while going into the hole described in the previous figure. In Fig. 51.81a, the lower-receiver signal is just becoming affected as it moves very close to the gas stringer. One foot lower, at 5,477 ft, the lower receiver is in the top of the gas zone. In Fig. 5 1.8 lc, the lower receiver is in the gas sand and the upper receiver is being affected. In the massive gas sand at 5,540 ft, both receivers are showing almost total compressional wave loss, whereas in the water sand at 5,580 ft, a strong signal is apparent at both receivers. For comparison, a typical shale response at 5,462 ft is given in Fig. 5 1.8lf.
rllTl Ralio
Fig. 51.79-Gas effect on compressional- to shear-wave velocity ratio in sandstone reservoir.
t
Fig. 51.80-Typical gulf coast induction log indicating Iwo gas sands.
HANDBOOK
ACOUSTIC LOGGING
51-39
0
Geopressure Detection Geopressure refers to a buried rock/fluid system in which the fluid pressure is greater than the hydrostatic pressure of a full column of formation water. Geopressure also is called abnormal pressure or overpressure. Abnormally high fluid pressures are found worldwide. Such pressures occur when fluid in the pore space begins to support more overburden than just not all the compressional forces are fluids-i.e., transmitted by the rock matrix only. The ability to predict the occurrence and magnitude of abnormal pressures is a requirement in planning efficient drilling and, ultimately, completion procedures. Hottman and Johnson”’ established a procedure for determining the first occurrence of geopressure and the precise depth vs. pressure relationship. They observed that for hydrostatic-pressure formations in a given a plot of the logarithm of geological province, compressional-wave travel time in shales, i,,h, vs. depth is generally a straight line. The divergence of the observed travel time kc,,, from that obtained with the established normal trend kli is a measure of the pore-fluid pressure in the shale and, hence, in the adjacent permeable formaa trend of tion (Fig. 51.82). They also established resistivity vs. depth for shales and used it similarly in conjunction with acoustic log data. A field example showing acoustic log response in an abnormal pressure section in the North Sea is given on the right track of Fig. 5 1.83. ‘*” A remarkably accurate prediction of abnormal pressure by surface seismic measurements is shown for comparison in the left track. A procedure for evaluation of formation pressure is summarized as follows. “’ 1. Plot shale velocity or transit time and establish a normal compaction trend line. 2. Locate the anomalous pressure top at the depth at which plotted data points diverge from the normal trend. 3. Take the difference between observed shale transit time and normal shale transit time. 4. Convert the difference to formation pressure gradient by means of an empirically derived curve for a given age and for a given area (Fig. 5 1.84 was used for the example shown in Fig. 51.83). 5. Multiply the pressure gradient obtained by depth to compute the formation fluid pressure at that depth. Another approach for evaluating abnormal pressures is suggested by Eaton. ‘*’ He proposes the following empirical relationship for predicting pore fluid pressure
2
-
4
-
6
-
8
10
12 'ob /
14
Fig. 51.82-Prediction
of Qeopressure from shale transit time.
Predicted
Actual
Abnormal Pressure
Abnormal
TopL
Pressure
Normal Pressure
I
Top
or
Lithology
Change
Abnormal-’
(Pf):
Pressure
1( i
where
I,,‘,-‘n
D = = = = (P/D) ,r
depth, ft pore fluid pressure overburden stress normal hydrostatic (0.456 psiift for fresh waters), 1, = transit time on the curve at depth,
p/D p,/D
Mud Top
gradient, psi/ft, gradient, psi/ft, pressure gradient Gulf
Coast,
0.434
for
= 38
Wt.
= 13.3
Chalk
Fig. 51.83-Comparison hole
extrapolated
normal
1
pressure
t&-f, Mud Top
= 36
Wt. = 14.0 ____.~.~ Chalk
of seismic prediction and actual downenvironment.
PETROLEUM ENGINEERING
HANDBOOK
‘oh = observed
transit time at depth, and m = empirical exponent varying regionally around a value of three.
17
Cement Bond Quality
MEASURED,
I&, - NORMAL
Fig. 51.84-Transit-time/pressure
0
correlation, North Sea.
200
I400
.#,,I
600
600 ..,
1000
,I..
‘I ‘I ,I
I-
Fig. 51.8%Free
fs,,
‘; Caring
Travel
pipe
Time
The primary purposes of oilwell cementing are to secure casing to prevent leakage to the surface and to isolate producing zones from water zones. With the increasing cost of completing wells, accurate determination of the quality of the casing cementation has become necessary to avoid costly recompletion and squeeze cementing jobs. The successful cementing of a well is affected by many factors: cement setting time, pressure, temperature, hole size and deviation, formation and cement characteristics, casing surface, and damage to the cement bond by perforating or squeezing operations. These when and many other factors must be considered evaluating the effectiveness of a cement job. Early in acoustic logging, it was observed that the amplitude of an acoustic signal in a firmly cemented pipe is only a fraction of that of a free pipe. tZ3 Since then, downhole acoustic measurements have been firmly established as the primary technology for determining not only to the casing but to the formacement bondin tion as well . ” %.‘25 Under favorable conditions even the compressive strength of cement can be determined. ‘I6
Free Pipe. A schematic axial transmitter and receiver configuration is shown in Fig. 5 1.85 for cement bond logging. ‘*’ In a free pipe, most of the energy is confined to the casing and the borehole fluid, as indicated in Fig. 5 I .85. The resulting acoustic waveform as recorded by the receiver is also shown in this figure. The following observations characterize waveforms observed in free, unbonded casing. 1. The first arrival of the waveform is equal to the total travel time in casing between transmitter and receiver, plus the travel time in fluid between the tool and the pipe. 2. The amplitude of the entire waveform is high. 3. The waveform exhibits a highly uniform frequency. 4. The waveform is persistent and lasts a relatively long time. Good Bond to Casing and Formation. When the cement is perfectly bonded to both the casing and the formation, a very favorable acoustic coupling is developed. As a result, maximum energy is transferred to the formation, and very little energy is transmitted through the casing and cement sheath. As shown in Fig. 51.86, the waveform shows practically no signal at the casing arrival time and very little amplitude until the formation arrival time.
Bond to Casing and to a High-Velocity Formation. In areas of high-velocity formations, signals from the formation arrive at the same time as or earlier than the casthereby complicating the interpretation ing signal, significantly (Fig. 51.87). -.
\
Fig. 51.86-Good
bond to casing and formation
Cement Bond to Casing Only. A commonly
occurring condition is that the periphery of the casing is totally surrounded and bonded by a hardened sheath of cement that
51-41
ACOUSTIC LOGGING
0
200
,; 400
600
1
.I
Fig. 51.87-Bond
is not bonded to the formation (Fig. 5 1.88). This might happen because the cement does not bond with mudcake of poorly consolidated formations, or the mudcake dries and shrinks away from cement. Under this condition, energy traveling through the casing is attenuated drastically because of the highly attenuating cement sheath. The annulus outside the cement sheath offers very unfavorable acoustic coupling; hence. very littlc energy is transferred to the annular fluid and virtually none into the formation. This is indicated by the lack of later-arriving formation energy in the waveform of Fig. 51.88. The energy observed at Y!O psec is the beginning of the fluid wave for the transmitter-toreceiver spacing of 5 ft.
Partial Bonding. A most difficult situation in evaluating cement bond quality is the condition of partial bond (Fig. 5 I .89). A small gap may be formed between the casing and cement in an otherwise well-bonded casing. In this situation the waveform typically contains two distinct wave energies. The first wave energy arrives at casing time, since part of the casing is free to vibrate. The second wave energy arrives at a time indicated by the velocity of the formation. Hence, both a moderately strong casing arrival and a moderate-to-strong formation arrival exists. The typical partial-bonding waveform is characteristic of either a microannulus or a channel in the cement. A microannulus is a very small separation between casing and cement. Normally, a hydraulic seal exists with a microannulus. but not with a channel in the cement. Thus. it is important to differentiate between the two. The best way is to rerun the bond log with pressure on the casing. If a microannulus exists, the casing will expand, decreasing the separation and transferring acoustic energy to and from the formation. The casing signal will decrease and formation signals will then become more evident. However, if only channeling exists, pressuring the casing will not greatly alter the log. Another way to differentiate between microannulus and channeling is by noting the length of section over is which the condition exists. ‘I5 Since microannulus thought to be caused by the condition of the exterior surface of the casing, such as the presence of grease or mill
Fig.
51.88-Cement
I, i
I-
Time
to casing and to a high-velocity formation.
1
t.-. ‘1
Travel
1000
:
.*:
1 ,-Casing I
800
Casing
ikeI
Time
bond to casing only.
varnish, the effect tends to appear over a long section of log. Channeling ordinarily occurs over shorter sections. Examples of various bonding conditions are illustrated by the variable-density (3D) log shown in Fig. 5 I .90. “’ The interval from X552 to X614 ft shows a good pipe bond but no formation bond. Only a few formation arrivals can be seen, indicating a lack of acoustical coupling between the cement sheath and the formation itself. Above and below this interval are sections of poorly bonded pipe. This probably is due to channeling. This is suggested by the strong pipe signal overriding a weak formation signal. The interval from X468 to X518 ft i$ well bonded, as evidenced by the strong formation signal. However, there is evidence of a microannulus between X506 and X518 ft. Here the fonnation signal is distorted somewhat by a casing signal. “’ A recently introduced technology, the Cement Evaluation Tool by Schlumberger. shows great promise in differentiating between microannulus and channeling. I”’ This tool is based on the acoustic reflection method; however, unlike the boreholc telcviewcr with one rotating transducer, it has eight transducers placed on a centralized sonde at 45” from each other in a helical path. These transducers, emitter and receiver. are about
0
200
,400 ‘I -f~
-~
600
800
1000
I ,‘I,.
.,
4
, /
_I
-
Fig.
51.89-Partial
C&g
bonding
Tk~el
Time
PETROLEUM
51-42
usec
I-
ENGINEERING
HANDBOOK
lncreasina
Good
Bond
Probable Micro-Annulus
Channel-Poor
Good No
Bond
Bond
Bond
Channel-Poor
Fig.
51.90-Good
bond to casing-no
to Casing
to Formation
Bond
bond to formation
Fig. 51.92-Full waveforms and variable-density ferent bonding conditions.
log for dif-
1 in. in diameter and operate at 500 kHz. They repeatedly send a short ultrasonic pulse toward the casing to make it resonate in its thickness mode. Cement behind the casing is detected as a rapid damping of this resonance, whereas a lack of cement gives a longer resonance decay. An example of a cement evaluation log is shown in Fig. 5 1.91. I30 The right track can be viewed as a map of cement behind the casing. It is divided into eight channels, each one representing one transducer with a shading from white (free pipe) to black (good cement). In this example, a channel is clearly visible as a white streak.
Summary of Bonding Conditions. Typical full waveforms for various bonding conditions are summarized in Fig. 51.92. 128 When there is no cement bonded to the casing, a free casing signal is indicated on the variable-density log as straight dark lines with distortion at the collars. This distortion occurs for a vertical distance equal to the spacing between the transmitter and receiver of the logging instrument (6 ft on the example shown in Fig. 51.92). When there is good cement bonding both to the casing and to the formation, there is no casing signal. but there is a strong formation signal. The difference in response for the low- and high-velocity arrivals for a well-bonded section is clearly illustrated in the lower section of the variable-density log of Fig. 51.92.
Maxlmwn
Cased-Hole Evaluation
Fig.
51.91-Ultrasonic
cement evaluation log
Most existing wells were completed before the advent of reliable porosity logging devices; therefore, accurate porosity data for planning of enhanced recovery operations must be obtained through existing casing. Radioactivity logging measurements commonly are used for this purpose; this information, however, can be supplemented by the acoustic log measurements in wells
ACOUSTIC
51-43
LOGGING
where a good cement bond exists between casing and the formation. 13’ A recent study ‘X2 involving laboratory modeling and computer simulations has indicated that acoustic logging can be successful in both bonded and unbonded casing. Through-casing acoustic logs have provided reliable measurements of compressional and shear-wave velocity data for evaluating porosity and lithology. An openhole and cased-hole comparison is shown in Fig. 5 1.93 for the compressional and shear-wave transit times t,, and I,, The logs were obtained by analysis of the waveforms digitally recorded with the acoustic logging system shown in Fig. 51.54. The agreement between compressional and shear transit time logs run in open and cased holes is excellent. This further enhances the role of acoustic measurements in cased-hole evaluation.
Interval
A knowledge of the mechanical properties of rocks is important in drilling, production, and formation evaluation. Mechanical properties include the elastic properties such as Young’s modulus, shear modulus, Poisson’s ratio, and bulk pore compressibilities, as well as the inelastic properties such as fracture pressure gradient and formation strength. Borehole measurements of acoustic properties in combination with density log measurements are being used more and more for in-situ determination of mechanical properties of rocks. Elastic constants describe the Moduli. mechanical properties of matter: Young’s modulus, shear modulus, bulk modulus, and Poisson’s ratio. Knowledge of these moduli for rocks is needed in studying the propagation of acoustic waves, as well as in practical engineering problems connected with drilling, formation fracturing. and predicting reservoir performance. A commonly used approach to gather this information is to obtain core samples and to conduct laboratory experiments. For meaningful results. these measurements must be made at equivalent subsurface conditions. Needless to say, these are time-consuming and costly. Even then the results are suspect because the process of coring removes the overburden stress from the sample and causes other disturbances that may not be reversible. Numerous studies have been conducted that compared elastic moduli obtained by the static (from measurements of stress and strain) and the dynamic (from acoustic velocities and density) methods. In rocks subjected to lower effective stresses, the dynamic elastic moduli are higher than the static values; as the stress increases, however, these differences decrease. ‘33.‘31 Theoretical studies by Walsh ‘X predicted that this could be caused by the resence of cracks in rocks. In fact, Simmons and Brace’ P’ found the static and dynamic moduli to be in close agreement when rocks are subjected to higher stresses (30,000 psi) so that the cracks are closed. The relationship of the in-situ-measured elastic moduli to those determined in the laboratory was investigated by Myung and Helander. “’ They made laboratory measurements of compressionaland shear-wave velociL ties on core samples under simulated subsurface pressure conditions and reported a close agreement between insitu and laboratory-determined values of dynamic elastic moduli.
pslm I
500
Mechanical Properties
Transit Time I
1 A0
, I 2
Cased Hole
Elastic
Fig. 51.93-Comparison
of digital-sonic logs in a well before and after casing.
have used Since then, many other investigators borehole acoustic measurements to determine elastic moduli. 89,‘37,‘38 Compressionaland shear-wave velocities obtained from the acoustic log measurements are used with values of density from a density log to calculate Young’s modulus, shear modulus, bulk modulus, and Poisson’s ratio by assuming an infinite, isotropic, homogeneous, and elastic medium (see Eqs. 3 through 6). Applications of these in-situ-determined values of moduli include predicting sand production and subsidence, and determining fracturing characteristics of formations. An application involving fracture characteristics is shown in Fig. 51.94.h” The core and log data are from a section of igneous and metamorphic rocks. The fracture characteristics of the core are shown graphically as well as plotted quantitatively as rock quality designation (RQD), which is the ratio of the cumulative length of unfractured core to the unit length of core. Elastic moduli curves are quite similar to the RQD curve.
PETROLEUM
R.Q.D.
Elastic Properties
ENGINEERING
HANDBOOK
3-D Velocity ,&ECINCREASING
mo4oobooaoomoonoouoo
Fig. 51.94-Comparison
I
91aJw
of rock quality designatton (R.Q.D.), elastic properties, and 3D velocity log
Fracturing. Fracturing of formations is a commonly used well stimulation technique. To detennine the best zoncb for fracturing. laboratory compressibility tests can be run on rock samples from the zones of interest. Fracture design requires a knowledge of elastic moduli. which can be obtained from borehole measurements. An earlier use of boreholc acoustic measurements was for the identification of zones favorable for fracturing. Hi@amplitude and high-velocity Lhear w;1vc\ have been associated with zonch that can be fractured suewhereas Tones with low-velocity and loww\fully. amplitudc S-waves wcrc found to be quite plastic. In the example shown in Fig. 51 .c)S. Anderson and Walker”” inclicatc 3 wcil-defined shear wave in the /lone from 4.600 to 4.54.5 ft and none ahovc this LOW. During drilling. control of hydrostatic prcssurc in the horeholc is nccc.shaQ to not cscccd fracturing prczsuro ot circulation 10~. thcrcby causing the formations.
However, a knowledge of fracture pressure is needed for proper design of fracturing operation to stimulate hydrocarbon production from tight formations. An estimate of fracture pressure (p/,.) is given by Hubbert and Willis: “”
where pressure. 1~0 = overburden 11, = pore-fluid pressure. p = Poisson’> ratio. and D = depth. Recent applications Atkinson. I41
of this relationship
are discusxcd
hy
ACOUSTIC LOGGING
51-45
an
Am&ude +
4500
4600
Comp. Fig. 51.95-Evaluation
Sand Control. Sand-production control has been a costly problem affecting the economics of oil and gas production in many areas. To avoid unnecessary sandvarious techniques have been control measures, developed that use borehole measurements of acoustic
propertics, 13X.IJ?~l4~
In the example shown in Fig. 5 I .96. the need for sand control is predicted by assuming that hydrocarbon effects on acoustic properties are predominant in poorly consolidated formations. “’ In the oil zones shown, transit times are significantly higher than the value in the water zone, and the amplitudes are reduced, thereby indicating poorly consolidated rocks. Fracture Evaluation Many of the important reservoirs in the world produce from naturally occurring fractures, yet evaluating the
1Shear
of fracturing prospects.
performance of these reservoirs is much less understood. Techniques for evaluating naturally fractured reservoirs are reviewed in the literature by Aguilera and van Poollen, IJ5 Suau and Gartner, ‘A6 and Aguilera. “’ Among these, techniques based on measurements of acoustic properties are prominent. Cycle skipping observed on the transit time curve has been associated with fracturing in certain formations. Also. reduction of signal amplitude has been correlated with fractures. More successful applications, however. involve the use of variable-density or waveform logs. ‘4x.‘4y For these logs, when fractures occur, anomalies also occur in the acoustic wave banding pattern. Sometimes these are diagonal patterns. but more often they occur as sudden breaks in the banding. Fig. 51.97 shows a variable-density log (3-D log) from a granite section in New Hampshire. “’ In Zone C.
PETROLEUM ENGINEERING
51-46
HANDBOOK
ohmmVm RESISTIWTY 0 18” Normal
125-130
5650.. t
Fig. 51.96-Hydrocarbon
Fig. 51.97-Variable
effects indicate the need for sand control.
density (3D) log in fractured granite.
the compressional wave is not attenuated, whereas the shear-wave amplitude is reduced significantly. A theoretical study by Knopoff and McDonald”’ would predict this to be due to a low-angle (or horizontal) fracture. High-amplitude compressional and shear energies indicate that Zone B has no fractures. High attenuation of the compressional and shear waves in Zone A is interpreted to be caused by an oblique fracture. The diagonal energy pattern below Zone C is caused by the presence of a reflector (fracture) near the borehole. In the foregoing analysis, fractures are considered to be thin reflectors causing distortion in wave propagation because of acoustic impedance mismatch with the surrounding rock. Since abrupt changes in lithology and impedance porosity also can cause similar acoustic mismatches, this simplified interpretation becomes much more complex. When the hole conditions are favorable and there is no mudcake or heavy muds in the hole, the borehole reflection method provides a more straightforward technique for the evaluation of fractures. A borehole televiewer sonde operating in a circular borehole intersectin a vertical fracture is shown on the left in Fig. 51.98. 8(” The borehole televiewer log obtained in this configuration. shown on the right. clearly depicts the vertical fracture as two dark lines.
ACOUSTIC LOGGING
Fig. 51.98-Vertical fracture amplitude log
51-47
intersecting
a circular borehole
The amplitude image from the BHTV, however, cannot distinguish whether the fracture is open or filled. An open fracture produces an image on the amplitude log because little or no signal returns to the sonde. A filled fracture also can produce an image if there is sufficient acoustic impedance contrast between the filling material and the host rock to produce a weaker signal. Therefore, both open and filled fractures may produce similar dark images on the amplitude log. Transit time imaging, however, responds not to variations of signal amplitude but rather to the travel time (and, hence, the distance) from the borehole wall. On the transit time log, the distance to the borehole face is represented by a gray scale designating white for far, dark for near, and black for no signal. Therefore, an open fracture produces a black image on the transit time image, whereas a filled fracture does not. Fig. 51.99 shows a vertical fracture on the amplitude log on the left. The similar black outline on the transit time log on the right confirms that this is an open fracture. Permeability Theoretical studies by Biot45.46 have indicated that changes in acoustic attenuation may reflect the fluid mobility (the ratio of permeability to viscosity). Later studies by Wyllie et al. 24 and Gardner and Harris”’ considered the logarithmic decrement (Eq. 6) of acoustic energy to be a result of solid friction (“jostling” decrement) in the rock matrix and viscous drag (“sloshing” decrement) within the saturant fluid. The solid matrix losses (jostling losses) were studied experimentally by Gardner and Harris, ‘I5 with respect to the effects of overburden pressure and fluid saturation. The results of their investigation indicate the jostling decrement of a sandstone under overburden pressures to be almost independent of fluid saturation and signal frequency. Hence, changes in the logarithmic decrement can be attributed to sloshing loss, which, according to Biot,45.46 reflects changes in fluid mobility.
and its representation
on BHTV
Later, iv a theoretical study, RosenbaumM applied Biot’s theory to the investigation of propagation of acoustic pulses in a fluid-filled borehole surrounded by a porous medium. He predicted that permeability could be estimated from an analysis of tube wave data contained in the acoustic waveform recorded in a borehole. He suggested that, for a sealed interface between the borehole and formation, maximum sensitivity to permeability was obtained in the interval between S-wave arrival and the fluid wave. For the open interface (no mudcake), the entire signal following the S-wave arrival could be used. The P-wave arrival was least sensitive to permeability and could be used for normalization. Results of this study were first tested by Staai and Robinson 15’ in the Groningen gas field, The Netherlands. They recorded acoustic waveforms and analyzed them to obtain a permeability profile, which compared favorably with the core analysis data. More recently, Rosenbaum’s prediction@ of the relationship between the energy loss of the tube (Stoneley) wave and permeability was investigated more extensively by Williams et al. ‘52 Using a special long-spacing acoustic logging tool, they measured the tube wave transit time and energy ratio in wells located in different geographic locations with formations of varying lithology, permeability, saturating fluid, depth, and geological age. From these wells, they also obtained whole core samples for measurements of permeability. For these widely varying conditions, they report qualitative correlations between core-measured permeabilities and the tube wave data. An example shown in Fig. 5 1.100 for a Cretaceous carbonate section is highly promising as it indicates that both tube amplitude ratio, Am /AR’ , and transit time correlate well with a permeability increase of three orders of magnitude in the center zone.
Conclusions Borehole measurements of acoustic properties have a wide range of applications in exploration, production,
51-46
TRANSIT TIME AMPLITUDE Dark-Weak While-Strong
I
E
S
Slgnal SIgnal
W
N
Black-No Slgnal Dark-Near White-Far N
E
S
W
N
Fig. 51.100-Permeability
5210
correlation with tube wave data
Nomenclature 5220
A = area; or signal amplitude at the source h = intercept defined by Eq. 13 c = compressibility d = diameter Di = depth of investigation
A,, = signal amplitude
5230
E = Young’s
Fig. 51.99-Vertical
fracture of the BHTV amplitude log on the left, confirmed to be open by the BHTV transit time log on the right..
and formation evaluation. Theoretical and experimental studies have significantly improved our understanding of the relationships between acoustic wave propagation and formation evaluation parameters, such as porosity, fluid saturation, and lithology. This, in turn, has prompted the development of new and improved borehole acoustic measurement technology and sophisticated digital signal processing technology to analyze the large amount of data. Even then. current applications often use only a small fraction of the information available in acoustic waveforms. Advances in the understanding of acoustic wave propagation are interactively complementing improvements in downhole recording and transmission technology. and developments in signal processing. This should result not only in a broader and more quantitative use of the present applications, but also in the development of many new applications.
modulus
f‘ = frequency f(Kf) = function of incompressibility of a fluid in pore spaces F = force F,, = compaction correction factor F, = quality factor G = shear modulus I = intensity I,, = acoustic intensity at the source K = bulk modulus L = length m = slope n = number p = pressure pCi = differential pressure pf = internal (pore fluid) pressure pf/D = pore fluid pressure gradient. psiift (pf./D) ,I = normal hydrostatic pressure gradient (0.456 psiift for U.S. gulf coast) P.fr = fracture pressure PO = external (overburden) pressure p,,lD = overburden stress gradient. psiift P,l = P-wave modulus for the rock frame (or the dry rock)
ACOUSTIC LOGGING
r s S f t I( = I/Y,,)
= = = = = =
I~~(= I/Y~,) = ‘,I = I,,,( =1/t,,,,) = 1,, = 1oh = N = 1’= “f = I’,,
=
\‘r
=
\‘,,
=
\‘,
=
O!=
6= E= CL
=
t,
=
CT
=
0,
=
X= P”= P= 4=
51-49
borehole radius arbitrary point saturation travel time transit time transit time for the compressional waves for a liquid-saturated porous medium transit time for saturant liquid damaged zone transit time transit time for rock matrix that forms the solid frame of a porous medium transit time on the extrapolated normal curve at depth observed transit time at depth particle motion at s velocity compressional-wave velocity of drilling mud compressional-wave velocity pseudo-Rayleigh-wave velocity shear-wave velocity tube- or Stoneley-wave velocity coefficient of absorption; or attenuation coefficient logarithmic decrement strain longitudinal strain shearing strain transverse strain S-wave critical angle wave length Poisson’s ratio density porosity
C=
(1 = f= ,? = hc = L= /n = N= 0 = P= .s = S/l = 1\’ =
apparent corrected dry rock pore fluid gas hydrocarbon liquid matrix neutron overburden or oil pore volume; or P-wave S-wave modulus shale water
The first theoretical expression of elastic behavior of a saturated porous medium was given by Gassmann.U Later, Biot45,46 developed a more comprehensive theory of elastic wave propagation in a fluid-saturated, isotropic, porous solid over a wide frequency range. The predicted velocity dispersion by this theory is. in general, less than 3% ” ; therefore, the low-frequency approximation should be useful for most applications. Velocities predicted by this theory at the lower frequencies can be expressed simply by 7 P‘l +mf) \‘; =
.
(A-1)
Ph
and
Lj,,Z= -
G ....... ....
........ ..
. (A-2)
Pb
where Pd is the P-wave modulus for the rock frame (or the dry rock), and f(Kf) is the function of the incompressibility of the fluid in the pore spaces. The P-wave modulus for the dry rock can be expressed, in turn, by
Pd=Kd+;Gd:
.t..
and the functionf(Kf),
by
(1-K,,/K,,,)’ (I-K$K,,,M+(K,,, -K,,)K+K,,,’ ’
flKf.1=Kj
(A-3)
(A-4)
in which K is incompressibility (or bulk modulus), G is shear modulus, and the subscripts d, f, and m refer to the rock frame (or the dry rock), fluid, and rock matrix. For rocks containing both water and hydrocarbons, the bulk density is expressed as
Subscripts a=
APPENDIX
Theory of Elastic Wave Propagation in Rocks
p/,=$p,.+(l
-d)p,,,,
.
.(A-5)
where Pf=S,,P,,.+(l modulus
-S,,.)p,,(,,
.(A-6)
and the fluid incompressibility. K,, which is the inverse of compressibility, cf, is given by c, =S,,.c,,.+(l
-S,,,)C,,< ,
(A-7)
Acknowledgments I wish to thank A.A. Brown, G.S. De, and K.J. Dunn of Chevron Oil Field Research Co. and M.N. Toksoz of the Massachusetts Inst. of Technology for reviewing the manuscript. Debbie Ivey for typing. and. more importantly. the participants of the Chevron Formation Evaluation seminar durmg the past 20 years for many helpful suggestions toward the evolution of this chapter.
where S denotes saturation, and the subscript hc refers to hydrocarbon. Rock frame incompressibility, K,,. in Eq. A-3. which is the inverse of compressibility of dry rock, (‘,I, is related to PV compressibility, c,, . by c,,=&.,~
+c,,$.
(A-X)
51-50
PETROLEUM
on the basis of Van der Knaap’s” tion of this equation into Eq. A-l, tion, results in
3
CL
1-p -=
Ph”‘,i 2 1 +!J
definitions. Substituafter some manipula-
(cf-CJ’
fc ,,,.
(A-9)
SC, -’
Further substitutions into this equation for density from Eq. A\5 and rearranging yields a quadratic equation in p. Negleciing terms involving I”2 (since p is a fraction) and assuming p to be independent of porosity yields an equation expressing l/v,,2 as a linear function of porosity. For lower porosities.
i=mt$+b. vP
.
.
.
(A-10)
If the Poisson ratios for the saturated rock and the rock matrix are assumed to be close in value, then b becomes approximately equal to l/v,,,. The parameter m in Eq. A- IO, however, is a strong function of c,, . As the foregoing discussion indicates, Eq. A-10 is an approximation of Eq. A-9. Therefore, the commonly used time-average equation, ‘8.‘9 which is of the same form as Eq. A-10,
(A-11)
(where vf is the velocity of saturant liquid) also may be considered to be an approximation of the more general theory.
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ENGINEERING
HANDBOOK
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ACOUSTIC
51-51
LOGGING
41. Robinson. F.M.:
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96. Zemanek, J. ei a/. : “The Borehole T&viewer-A New Loggmg Concept for Fracture Location and Other Types of Borehole Inspection,” J. Pet. Tech. (June 1969) 762-74: Trans., AIME. 246. 91. Wiley, R.: “Borehole T&viewer-Revisited.” Trans., SPWLA (1980)21, paper HH. 98. “Seisviewer Logging,” Birdwell, Div. of Seismograph Service Corp., technical pamphlet (198 I). 99. Broding, R.A.: “Volumetric Scanning Well Logging,” Trans., SPWLA (1981) 22, paper B. T.J.: “Interpretation and Application of Borehole loo. Taylor, Televiewer Surveys,” Trans., SPWLA (1983) 24, paper QQ. 101. Pastemack, ES. and Goodwill. W.P.: “Applications of Digltal Borehole Televiewer Logging,” Trans. 1 SPWLA (1983) 24, paper X. 102. Peterson. R.A., Fillipone, W.R., and Coker. F.B.: “The Synthesis of Seismograms from Well Log Data,” Geophy.~ic.~ (July 1955) 20, No. 3, 516-38. 103. Ausbum, B.E., Nath, A.K., and Wittick. T.R.: “Modem Seismic Methods-An Aid for the Petroleum Engineer.” J. Pet. Tech. (Nov. 1978) 1519-30. 104. Omnes, G.: “Exploring with SH-Waves.” paper presented at the 1978 CSEG Natl. Convention, Calgary. Canada, May. 105. “Log Interpretation Charts,” Schlumberger (1979). 106. Clark, S.P.: “Handbook of Physical Constants,” Geological Sot. of America, memoir 97 (1966) 587. 107. Simmons, G. and Wang, H.: Single Crystal Elastic Constants and Calculated Aggregute Properties: A Handbook, MIT Press, Cambridge. MA (1971) 370. 108. Wells, L-E., Sanyal, SK., and Mathews, M.A.: “Matrix and Response Characteristics for Sonic. Density and Neutron,” Tmns., SPWLA (1979) 20, paper Z. 109. Carmichael, R.S.: Handbook of Physical Properties of Rocks, CRC Press (1982) 2, 345. 110. “Evaluaci6n de Formaclones en la Argentina,” Schlumberger (1973) 94-95. 111. Raymer, L.L., Hunt, E.R., and Gardner, J.S.: “An lmpmved Sonic Transit Time-To-Porosity Transform,” Trans., SPWLA (1980) paper P. 112. Hartley, K.B.: “Factors Affecting Sandstone Acoustic Compressional Velocities and An Examination of Empirical Correlations Between Velocities and Porosities.” Tram:, SPWLA (1981) paper PP. 113. Minear, J.W.: “Clay Models and Acoustic Velocities,” paper SPE I I031 presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 26-29. 114. Kuster, G.T. and Toksiiz, M.N.: “Velocity and Attenuation of Seismic Waves in Two-Phase Media: Part 1: Theoretical Formulations.” Geophysics (1974) 39, 587-606. 115. Gardner, G.H.F. and Harris, M.H.: “Velocity and Attenuation of Elastic Waves in Sands,” Trans., SPWLA (1968) 9, paper M. 116. Domenico, S.N.: “Effect of Brine-Gas Mixture on Velocity in an Unconsolidated Sand Reservoir,” 77~ Log Anulyst (1977) 18, 38-46. 117. Kithas, B.A.: “Lithology, Gas Detection, and Rock Properties from Acoustic Logging Systems,” Trans., SPWLA (1976) 17, paper R. 118. Laws, W.R., Edwards, C.A.M., and Wichmann, P.A.: “A Study of the Acoustic and Density Changes Associated with High-Amplitude Events on Seismic Data,” Trans., SPWLA (1974) IS, paper D. 119. Hottman, d.& and Johnson, R.K.: “Estimation of Formation Pressures from Log-Derived Shale Properties,” J. Pvt. Tech. (June 1965) 717-22: Trans.. AIME, 23b. 120. Herring, E-A.: “North Sea Abnormal Pressures Determined from Logs,” Pet. Erg. (1973) 45. 72-84. 121. Fertl, W.H.: Abnormal F&motion Pressure, Elsevier Scientific Publishing Co., New York City (1976) 382. 12’2. Eaton, B.A.: “The Equation for Geopressure Prediction from Well Logs,” paper SPE 5544 presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 2X-Oct. 1. 123. Grosmangin, M., Kokesh, F.P., and Majani, P.: “A Sonic Method for Analyzing the Quality of Cementation of Borehole Casings,” J. Pet. Tech. (Feb. 1961) 165-71; Trms.. AIME. 222. 124. Walker, T.: “A Full-Wave Display of Acoustic Signal in Cased Holes,” J. Pet. Tech. (Aug. 1968) 81 l-24.
PETROLEUM ENGINEERING
HANDBOOK
125. Brown, H.D., Grijalva, V.E., and Raymer, L.L.: “New Developments in Sonic Wave Train Display and Analysis in Cased Holes,” Trans., SPWLA (1970) 11,paperF. 126. Pardue, G.H. et al.: “Cement Bond Log--k Study of Cement and Casing Variables,” J. Pet. Tech. (May 1963) 545-55; Trans.. AIME, 228. 127. “Acoustic Cement Bond Log,” Technical Pamphlet, Dresser Atlas (1979) 20. 128. “Cement Bond Evaluation in Cased Holes Through 3-D Velocity Logging,” Technical Pamphlet, Birdwell (1978) 12. 129. Fr&lich, B., Pittman, D., gnd Seeman. B.: “Cement Evaluation Tool-A New Approach to Cement Evaluation,” paper SPE 10207 presented at the 1981 SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 4-7. 130. “Cement Evaluation Tool,” Technical Pamphlet. Schlumberger (1983). 131. Fans, L.: “Acoustic Logging Through Casmg,” Trans., CWLS Formation Evaluation Symposium (1968) 2, paper J. 132. Chang, S.K. and Everhart, A.H.: “A Study of Some Loggmg in a Cased Borehole,” J. Pet. Tech. (Sept. 1983) 1745-50. 133. Simmons, G. and Brace, W.F.: “Comparison of Static and Dynamic Measurements of Compressibility of Rocks,” J.
Geophys. Res. (1965) 70, 5649-56. 134. King, M.S.: “Static and Dynamic Elastic Moduli of Rocks Under Pressure,” Rock Mechanics-Theory and Practice, Proc., Eleventh Symposium on Rock Mechanics (1970) 329-5 1. 13s. Walsh, J.B.: “The Effect of Cracks on the Uniaxial Elastic Compression of Rocks,” J. Geophw. Res. (1965) 70, 399-41 I, 136. Myung, J.1. and Helander, D.P.: “Correlation of Elastic Moduli Dynamically Measured by In Situ and Laboratory Techniques,”
The Log Analyst (1972) 13. 22-33. 137. McCann, D.M. and McCann, C.: “The Application of Borehole Acoustic Logging Techniques in Engineering Geology.” The Lag Analyst (1977) 18, No. 3. 30-37. 138. Coates, G.R. and Denoo, S.A.: “Mechanical Properties Program Using Borehole Analysis and Mohr’s Circle,” Trans., SPWLA (1981) 22. paDer DD. 139. Anderson. T. and Walier, T.: “Log Derived Rock Properties for use in Well Stimulation,” paper SPE 4095 presented at the 1972 SPE Annual Meeting, San Antonio, Oct. 8-11. 140. Hubbert, M.K. and Willis. D.G.: “Mechanics of Hydraulic Fracturing,” J. Pet. Tech. (June 1957) 153-66; Tuans...AIME, 210. 141. Atkinson, A.: “Fracture Pressure Gradients from Acoustic and Density Log Data: An Updated Approach,” Trans.. SPWLA (1977) 18. paper AA. 142. Walker, T.: “Acoustic Character of Unconsolidated Sands,” Welex paper (197 1). 143. Stein, N. and Hilchie, D.W.: “Estimating the Maximum Productlon Rate Possible from Friable Sandstones without Using Sand Control,” .I. Pet. Tech. (Sept. 1972) 1157-60; Trans., AIME, 253. 144. Tixier, M.P., Loveless, G.W,, and Anderson, R.A.: “Estimation of Formation Strength From the Mechanical Properties Log,” J. Pet. Tech. (March 1975) 283-93. 145. Aguilera, A. and van Poollen, H.K.: “Current Status on the Study of Naturally Fractured Reservoirs,” The Log Analyst (1977) 18, 3-23. 146. Suau, I. and Gartner, J.: “Fracture Detection from the Logs,” Trans., Sixth European Formation Evaluation Symposium of the SPWLA London Chapter (1979) paper L. 147. Aguilera, A. : Naturally Fractured Reservoirs, PennWell Publishing Co., Tulsa (1980) 703. 148. Walker, T.: “Progress Repon on Acoustic Amplitude Logging for Formation Evaluation,” paper SPE 45 I presented at the 1962 SPE Annual Meeting, Los Angeles, Oct. 7-10. 149. Myung, J.I. and Baltosser, R W.: “Fracture Evaluation by the Borehole Logging Method,” Stabilirq Rock Slopes, Thirteenth Symposium on Rock Mechanics (1972) 31-56. 150. Knopoff, L. and McDonald, G.H.F.: “Attenuation of Small Amplitude Stress Waves in Solids.” Gct>ph,wic.c(1958) 34. 151. Staal. J.J. and Robinson, J.D.: “Permeability Profiles from Acoustic Logging,” paper SPE 6821 presented it the 1977 SPE Annual Technical Conference and Exhibition, Denver, Oct. 9-12. 152. Williams, D.M. et al.: “The Long Spacing Acoustic Logging Tool,” Trans., SPWLA (1984) 25, paper T.
Chapter 52
Mud Logging Alun H. Whittaker, Exploration Logging IX.*
Introduction Conventional mud logging has been commercially available since 1939. The service involves extraction of gases from the returning mud stream and analysis of the gas for combustible hydrocarbons. Commonly, the resulting analyses are logged at drilled depth and plotted alongside a drill-time or rate of penetration log and a cuttings sample geological log. Although the mud log data cannot be related directly to undisturbed reservoir properties, they are important indicators of potentially productive horizons in the well. The conventional mud log continues to be the most important geological data source available before wireline logs are run. The mud logging unit offers a useful location for the operation of other wellsite analyses and services. It provides a clean, well-lighted laboratory area with a stable electrical supply and is continuously operated by geologists or geologically trained technicians. Many mud logging contractors have made use of these assets to augment conventional mud logging with an extensive range of geological and engineering services. Often unrelated to the traditional gas analysis function of the unit, these services nevertheless generally are considered aspects of mud logging now in the same manner as sonic, density, and neutron logs often are grouped with “electric logs.” The earliest expansion of mud logging services began in the 1960’s with the introduction of improved methods of geopressure detection. New techniques were added to the logging unit and it became common for a separate “pressure log” to be prepared alongside the mud log. The 24-hour activity of the mud logging unit allowed continuous operation of this service in which early detection was essential. In the 1970’s, the advent of rugged microelectronics allowed the introduction of more sophisticated and automated equipment into the logging unit. Most notably, the use of drilling rig data-acquisition systems
‘The chapter on this topic In the 1962 edibon was written by A.J. Pearson.
linked to minicomputers introduced a range of drilling optimization and control services. Unlike conventional mud logging and geopressure detection, these services are essentially nongeological. Generally, engineering personnel are added to the logging crew for these services. In the 1980’s three new aspects to mud logging services have been introduced. First, direct links between a wellsite minicomputer and an office data center allow centralized surveillance and control of several wells. The logging unit provides a wellsite access point to the central computer data base and analytical software. Second, there is the increasing use of the mud logging unit as the surface receiving and control center for downhole measurement-while-drilling (MWD) services. The mud logging unit provides both a convenient working environment and support data (e.g., total depth measurement) for this service. Additionally, the ability to integrate mud logging and MWD data in a single computer adds economy and speed to the well evaluation process. Third, the 1980’s have brought the first fundamental changes in the methods of hydrocation and geological analysis, which continue to be the common denominator of all mud logging services. Improved sampling techniques, pyrolysis, chromatography, and other geochemical techniques have enhanced the diagnostic and quantitative value of mud logging. Wellsire geochemical screening for reservoir and source-bed type may now be performed in the mud logging unit.
Service Types The number and range of mud logging contractors is possibly greater than that of any other oilfield service. The logging services offered by any single contractor may range from basic hydrocarbon logging, using equipment barely more sophisticated than that introduced 40 years ago, to complex chemical and physical analyses and a complete engineering surveillance and control center.
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Similarly, logging personnel may be graduate geologists or engineers, or technicians of various levels of expertise. In specifying the mud log service for a well, the operator’s engineer, geologist, and the logging contractor should define the objectives and problems anticipated and select those aspects of the service required. Since extra service usually implies extra cost, economics must play a part in the decision. In engineering monitoring, it is relatively easy to compute the saving in drilling time or cost required to justify some addition to logging service day rate. This is discussed in detail at the end of this chapter. Although overlaps occur, the services provided in mud logging may be grouped in line with the traditional oilfield disciplines: (1) formation evaluation services ’-hydrocarbon analysis, geological analysis, and geochemical analysis; (2) petroleum engineering services-geopressure evaluation and petrophysical measurements; (3) drilling en@neering services-data acquisition and data analysis. This order is convenient for the following discussion of logging services since it closely parallels the historical development of mud logging and the level of sophistication of logging units used today.
Formation Evaluation Services Gas Extraction Methods Although the modem mud logging unit may perform many different services, probably its most critical one is the analysis of hydrocarbon gases. 2 Before this analysis can be performed, a sample of gas must be extracted from the drilling mud. This is performed by the gas trap (Fig. 52.1). The gas trap is a square or cylindrical metal box immersed in the shale shaker ditch, preferably in a location
Fig. Cl-Gas
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of maximum mud flow rate. Ports in the lower part of the trap allow mud to enter and leave the trap. An electric or pneumatic agitator motor provides both pumping and degassing of mud passing through the trap. Gas evolved from the mud is mixed with ambient air in the upper part of the trap and drawn through a vacuum line to the logging unit for analysis. This device provides a relatively cheap and reliable method of obtaining a continuous gas sample. However, the efficiency of the device is somewhat affected by drilling practice. Pump rate and ditch mud level will influence mud flow rate through the trap; mud rheology will be a factor in the degassing efficiency of the trap; and mud and ambient air temperature around the trap and vacuum line will affect the relative efficiency with which light and heavy hydrocarbons are extracted and retained in the gas phase. This latter effect is most noticeable in areas of high diurnal temperature variation, where heavier alkane gases seen in daylight may condense and be lost in the cold of night. An alternative to the conventional gas trap is the steam, or vacuum, mud still. In this device, a small sample of drilling mud is collected at the ditch, returned to the logging unit, and distilled under vacuum. The method provides a relatively high and uniform extraction efficiency for all hydrocarbons. It is, however, a timeconsuming manual process. Analyses are noncontinuous and subject to human error; for example, light hydrocarbons can evaporate while the sample stands prior to analysis. While a useful addition to the conventional gas trap at times, the mud still does not provide a real alternative. The development of a continuous gas trap with good and consistent efficiency of extraction is a high priority in the improvement of mud logging technology.
extraction
at the ditch
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52-3
r PRESSURE :VACuUM PUMP 1 REGULATOR
Hydrocarbon Analysis The basic form of gas analysis involves the analysis by combustion of the bulk sample. Although commonly called “total gas analysis,” it is, in reality, analysis for total combustible gases and primarily detects the lowmolecular-weight alkanes (paraffins) such as methane, ethane, propane, butane, and pentane (with partial concentrations of hexane and heptane at higher ambient temperatures). Catalytic Combustion Detector (CCD). After filtration and drying, the gas stream is injected at constant pressure and flowrate into a detector chamber (Fig. 52.2). The original type of mud logging gas detector, and probably still the most widely used, is the catalytic combustion, or “hot wire” detector (Fig. 52.3). The hot wire detector is a Wheatstone bridge circuit consisting of four resistances: a fixed resistor, Rf; a rheostat, R,, used to trim or balance the bridge; and a matched pair of coiled platinum wire filaments, Rd and R,. The two filaments are enclosed in an analysis cell with the detector filament, Rd, exposed to the flow of gas sample and the reference filament, R,, isolated in pure air. When a bridge voltage, V, is applied, the filaments become heated. A voltage between two and three volts is commonly selected to give a high enough filament temperature for hydrocarbon combustion at the filament surface (actual voltage used depends on the particular detector design). Combustion heat causes the temperature and hence resistance of the detector filament to rise relative to the reference filament. The bridge is unbalanced and current flows between the two sides of the bridge. Using a galvanometer of resistance R, , this current, I,, can be measured. Since combustion occurs at the filament surface only, the galvanometer current is quite sensitive and linear with changing gas concentration. Obviously, detector response will depend on both the concentration and composition of the sample gas phase, since each hydrocarbon species will have its own particular heat of combustion. Table 52.1 shows these for the low-molecular-weight alkanes. Since gas composition is unknown, the total gas detector cannot be calibrated for tme compositional response. The detector is calibrated with a mixture of a single alkane, usually methane, in air. Detector response is then reported in percentage “equivalent methane in air” or EMA. Using a variable resistance, R,, in the bridge it is possible to adjust the bridge current, I,, and graduate the galvanometer directly in percentage EMA. An older practice, which is now becoming obsolete, was to take the galvanometer reading in milliamps and relabel it as “gas units.” Such units are obviously equipment specific although some company or regional standards have been enforced. Where this practice continues, confusion can be avoided by requiring the logging contractor to report calibration data on the mud log heading. For example, the contractor would report “ 100 total gas units=2% EMA.” Fig. 52.4 shows the response of a typical CCD to commonly occurring combustible gases. Notice that a response of 1% EMA, or 50 total gas units, may indicate a concentration of 1% methane or a somewhat lower
Fig. 52.2-Gas
analysis system.
ZERO ADJUST POTENTIOMETER
L
SPAN
ADJUST
POTENTIOMETER
Fig. 52.3-Catalytic
TABLE 52.1-HEATS
Cn
+2n+2)
combustion detector.
OF COMBUSTION OF THE SIMPLE ALKANES
(3n + 1) +-O,-nCO,+(n+l) 2
H,O+E
n=1 1
Molecular Weight 16
E (kcallmol) 191
kcallgm 11.9
Structure i
Ethane
2
30
342
11.4
u”
Propane
3
44
493
11.2
tit
Iso-butane
4
56
648
11.2
A
Butane
4
58
650
11.2
Methane
j-c+4
52-4
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+ Ii20
HYDROGEN
SAMPLE
+1 +-J
7+
Fig. 52.5-Flame
ZERO 0 AO.JvsT
0.2
0.4
0.6
0.8
PERCENT
Fig. 52.4-Catalytic
1.0
x2
““DROt.aRBON
I.4
16
, 8
20
IN AIR
combustion detector response.
concentration of a mixture of methane and heavier alkanes. Total gas response may be thought of as a “gas richness indicator,” increasing both with gas concentration and with addition of heavier fractions. To assist in discriminating light alkanes from heavy ones, a second identical detector may be used. By setting a lower bridge voltage (1 to 1.4 V) and filament temperature, the detector is no longer capable of inducing combustion of methane. The resulting detector output, still reported in percentage EMA, is commonly labeled petroleum vapors, wet gas, or heavies, although only qualitative comparison of the two detector responses allows recognition of dry and oil-associated gas shows. Response of the CCD can be maintained linearly up to the stoichiometric, or ideal, combustion composition of hydrocarbon in air. Above this composition, approximately 9.5% EMA, the detector “saturates,” incomplete combustion occurs, and response becomes nonlinear. At higher concentrations, the sample must be diluted with air before it is introduced into the sample chamber to maintain a combustible gas mixture. Theoretically, by using progressive sample dilution, a CCD can be maintained linearly up to concentrations of 100% EMA. In reality, each dilution stage requires a reduction in gas sample volume and an increasing mixing error. It is generally accepted that 40% EMA is the maximum limit of reliability of a CCD. As an alternative to progressive dilution, where high gas concentrations are regularly expected, the detector can be reconfigured to operate as a thermal conductivity detector (TCD). Though the detector circuit remains essentially unchanged, it is operated at a lower voltage such that no gas combustion occurs. Bridge current now is reversed, responding to the cooling effect of the gas stream passing over the detector filament. Methane, which has a substantially greater thermal conductivity than air, will produce a large cooling effect, which may be linearly calibrated up to very high concentrations. The device is, however, poorly responsive to the heavier alkanes, CO2 and hydrogen sulfide (HzS), which have thermal conductivities close to that of air. The high conductivity gases, hydrogen and helium, will give responses even greater than that of methane. The CCD is quite selective for hydrocarbons. Carbon dioxide (COZ) and hydrogen sulfide (HzS) will not bum at the detector filament. They will marginally reduce the
*In ionization detector.
thermal conductivity of the gas mixture and induce a small heating effect at the detector filament. This positive response is commonly so small as to be insignificant when compared with the greater hydrocarbon response. However, if the concentration of noncombustible gases becomes so high as to prevent complete combustion of hydrocarbon with air, a much larger negative response will occur. Hydrogen will bum in the detector, even at low voltage, giving a concentration response similar to methane. Although free hydrogen does occur as an intermediate product of petroleum maturation, it is extremely reactive and diffusive. Occurrence of hydrogen in a petroleum gas show is therefore most uncommon. Significant concentrations of hydrogen have been shown to result from deep-seated structural movement, but the most common origin is from the corrosion of aluminum drillpipe or of steel drillpipe in extremely low pH drilling fluids. A serious disadvantage of the CCD is the tendency of the catalyst surface to become poisoned by the accumulation of impurities and partial combustion products. This may result in a slow, progressive degradation of performance or a sudden, catastrophic loss, when, for example, silicon compounds are present in the mud. Regular detector calibration is essential to maintain reliable operation. Flame Ionization Detector. The inherent limitations of the CCD resulted in a search for a more reliable detector technology. The most accepted and increasingly used is the flame ionization, or “hydrogen flame,” detector (FID) (Fig. 52.5). One important difference between the flame ionization and the catalytic combustion principles is that the flame ionization method involves complete combustion of the sample. A small quantity of sample is introduced into a hydrogen/oxygen mixture that is continuously burning in a combustion chamber. The heat generated by the hydrogen flame is sufficient to initiate complete combustion of all hydrocarbons in the sample. A large oxygen excess is maintained relative to the small sample volume and saturation never occurs. The heat output of the hydrogen flame is the sum of the heats of combustion of hydrogen and the sample hydrocarbons. Unfortunately, most of the heat produced is from the large volume flow of pure hydrogen. The small, dilute flow of hydrocarbons produces such a small proportion of the total heat of combustion that it cannot be measured accurately. Combustion heat then cannot be used as a measure of hydrocarbon concentration. Detection of the hydrocarbons instead relies upon an unusual in-
MUD LOGGING
termediate stage in combustion that only occurs in hydrocarbons burning at high temperatures. This involves the creation of unstable electrically charged anions and cations. By placing a positive electrode, or anode, in the form of a cylindrical chimney above the hydrogen flame, the negative anions may be collected and the resultant electric current used to determine hydrocarbon concentration. The ionization/combustion sequence is a complex one that involves many intermediate and alternate reaction steps. The number of ions created, and therefore the current flowing, is in direct proportion to the concentration of the alkanes and to the number of carbon atoms in the alkanes (Fig. 52.6). The FID response in percentage EMA is, therefore, like the CCD, a richness indicator showing increases with increasing concentration and increasing alkane molecular weight. The FID is totally selective for compounds containing carbon-to-hydrogen (C-H) bonds. Other gases and impurities in the sample stream produce zero or negligible response and do not degrade detector performance. Although the detector response is effectively linear throughout all concentrations, the electrometer used to monitor and amplify the detector current has performance limits of linearity. Since mud log gas shows may vary from tens of parts per million (ppm) to tens of percent, both electrical signal attenuation and sample splitting are required to ensure low-range sensitivity and high-range linearity of FID response. In most modem instruments this is handled automatically, ensuring a higher degree of accuracy than manual sample dilution. Gas Chromatography. In addition to a total gas detector, most modem logging units will also contain a gas chromatograph. This device allows the separation of the individual alkanes and their separated detection, giving a gas analysis of composition and concentration. While this analysis is of greater value than the total gas response in EMA, the chromatograph does not provide a continuous analysis but processes batch samples separated by a number of minutes. In drilling terms, this translates into separate analyses several feet apart. The chromatograph does not replace the total gas recorder in showing the fine detail and progressive changes in a gas show. In gas chromatography, a fixed volume gas sample is carried through a separating column by a carrier gas, usually air. The column contains liquid solvent surface or a fine molecular sieve solid. By difference in gas solubility or by differential diffusion, the gas mixture becomes separated into its components, the lightest traveling most quickly through the column and the heaviest most slowly. Depending on the nature of the column, each component will pass through and exit the column in a characteristic time. From the column, the components pass in turn to a detector, which may be a CCD, TCD, or FID. The detector is calibrated with a gas mixture of known composition and concentrations. A separate calibration factor for each component can be used for detector response as the components occur in turn. Since heavier components take longer to traverse the column, the time and depth interval between samples is governed by the number of components to be analyzed.
52-5
0
0.2
0:4
HYDROCARBON
Fig. 52.6-Flame
0.6 CONCENTRATION
0.8
1 :o
% IN AIR
ionization detector response.
In routine logging, a chromatograph usually will be set to cycle through continuous automatic analyses for methane, ethane, propane, isobutane and n-butane. This requires approximately 3 to 5 minutes. If heavier alkanes (e.g., pentanes) need to be detected, the automatic control is disengaged and the analysis allowed to continue for a longer period of time. Infrared Absorption Detector. The third, and least used, form of detector is the infrared absorption detector. This instrument uses the principle that any chemical bond will absorb infrared energy of a specific frequency governed by the chemical nature and geometry of that bond. For example, methane contains four identical carbon-to-hydrogen (C-H) bonds. If a gas sample is irradiated with infrared energy at a frequency characteristic of this bond, the energy absorbed by the sample will be in proportion to the number of C-H bonds and hence to the concentration of methane in the sample. All other alkanes contain C-H and carbon-to-carbon (C-C) bonds. Although these bonds are chemically identical, they vary in geometry and hence characteristic infrared frequency, depending on their position within the alkane molecule. Theoretically it should be possible to pass the gas sample through a series of test cells, testing for infrared absorption at a series of characteristic infrared frequencies. Combination of the results would provide a continuous analysis of both alkane type and concentration-i.e., the equivalent of a continuous chromatogmph. Unfortunately, the C-H and C-C bonds show such a large number of minutely varying geometries that, instead of a series of discrete characteristic frequencies, a continuous band of overlapping absorptions occurs. At best, using a two-absorption cell system, it is possible to provide an estimate of methane concentration and total hydrocarbon concentration, in EMA. This result is comparable to the result obtainable from a dual CCD system and inferior to the results from an FID-equipped gas chromatograph. Detection of Nonhydrocarbon Gases. ’ The most commonly occurring nonhydrocarbon gases in petroleum exploration are CO*, HzS, helium, nitrogen, and hydrogen. As discussed previously, the occurrence of naturally produced hydrogen is rare. Helium and nitrogen also tend to have regionally or geologically
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52-6
specific occurrences. CO2 and H2 S arc common trace or significant components of natural gases and equipment for their detection should be used on any exploration well. Chromatograph-Thermal Conductivity Detector. The most versatile device for detection of nonhydrocarbons is a chromatograph equipped with a TCD. By selecting an appropriate column material and length, any single component or combination may be separated. The TCD will provide a response to any gas that has a thermal conductivity different from that of the carrier gas. This response will differ for each sample gas/carrier gas combination but, by using gas mixtures of known composition, calibration curves for each component can be developed. Best response and sensitivity is achieved when the maximum difference exists between the thermal conductivities of the sample gas and the carrier gas. Thermal conductivity generally declines exponentially with increasing molecular weight. Thus the light gases (hydrogen and helium) may be readily detected by use of air as the carrier gas. For the heavier gases (nitrogen, CO;, , and HzS) that have thermal conductivities closer to that of air, a lighter and higher thermal conductivity carrier gas must be used. Helium is a common choice but hydrogen also may be used if available. An important consideration when assessing the reliability of analyses for nitrogen and CO2 is their presence in the sample caused by the introduction of air into the gas trap and the aeration of drilling fluid. Air of normal atmospheric composition, dissolved and entrained in drilling fluid, will be introduced continuously into the borehole. In the hot downhole environment, corrosion and other oxidation reactions will deplete oxygen from this air resulting in a relative increase in nitrogen and CO* concentration. Oxidation of carbonaceous material will further add to CO2 enrichment. Alternatively, the presence of corrosion inhibitors in the mud may deplete both oxygen and CO*. Regardless of the mechanism involved, oxygen depletion will increase with temperature and length of circulation time through the downhole system. At the surface, this oxygen-depleted air and any gas recovered from the formation is mixed with ambient air at the gas trap. This air will vary in composition with the surrounding atmosphere-e.g., emissions from rig motors, vehicles, and others. Any show of nitrogen or CO2 from the formation must be recognized above background concentrations, which will show some random variation and a progressive increase as the hole is deepened and mud circulation becomes hotter and of longer duration. Regardless of the analytical method used, precision of the ppm level cannot be provided by the analysis. When only trace quantities of gas are expected or when a precise compositional analysis is required, mud logging analysis of CO2 or nitrogen cannot be relied upon. Of the nonhydrocarbon petroleum gases, HIS and CO? are the most significant. They are the most commonly occurring gases in high concentrations and because of their polar nature pose serious problems of corrosion of drilling and production equipment. H2S is
HANDBOOK
also toxic in relatively low concentrations. In many areas, detectors specific to these gases are considered standard mud logging equipment. Infrared Absorption Detector. Continuous CO2 detection is best handled with infrared absorption. An infrared analyzer is used that is responsive to the characteristic frequency of the carbon-to-oxygen (C-O) bond unique to COz. Correction of atmospheric CO2 concentration is performed by alternately scanning two sample cells. One contains a sample from the gas trap and the other contains ambient air. Differential output provides a measure of CO2 concentration above atmospheric. Tube-Type Detector. Several types of H2S detectors are used, all of which monitor a change resulting from the chemical oxidation of the gas. The simplest detector is the tube-type device in which the sample gas mixture is drawn at a controlled flow rate through a glass tube containing reactive lead acetate. The lead acetate, which is deposited on a substrate of high-surface-area silica gel granules, reacts with HzS to produce lead sulfide and changes from white to dark brown or black in the process: Pb(CH3C00)2
+H2S-‘2CH3COOH+PbS.
Since the amount of lead acetate in any unit length of tube is constant, the tube may be graduated in terms of concentration of H2S in a fixed volume of sample. The panel-mounted instrument has two tubes installed. Flow of sample from the ditch is constant through one of the tubes, and, if H2 S is present in the gas being evolved at the ditch, the lead acetate begins to discolor progressively from bottom to top (the direction of sample flow). Since the sample, and hence the discoloration, is continuous, this response is qualitative only. The discoloration indicates that H2S is present in only trace or in enriched quantities, but no estimate of actual concentration can be made. As soon as this discoloration is seen, a warning must be given since even trace quantities of gas can be dangerous. A quantitative analysis can be made by switching flow to the second tube and introducing a timed sample. In this case, a fixed amount of discoloration occurs and the scale allows reading of the H2S concentration. An alternative configuration for the tube indicator is in a small handbellows, often called a “puffer” or “sniffer,” which can be used to sample the atmosphere in various locations around the rig. Since the lead acetate reaction is not reversible, once the tube is used it must be replaced. The instrument cannot keep a continuous record of HzS concentration but only a series of individual measurements. This is a drawback, but not a serious one since any quantity of H 2 S in the atmosphere is both a health hazard and an indication that the mud system is totally saturated. Once HzS is detected, mud treatment to remove it must begin. Gas measurement is required to ensure that it is removed and does not reappear. The tube indicator may be used to detect CO2 or any other gas for which a discoloring reactant is available. For CO*, hydrazine is used in place of lead acetate.
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MUD LOGGING
Presence of CO2 is indicated by a purple coloration of the chemical in the tube: CO2 +N2H4 -‘NH2NHCOOH. The tube method, however, is poorly suited to continuous monitoring since there will be a uniform rate of discoloration by atmospheric CO2 Paper-Tape-Type Detector. A more sophisticated version of this detection principle uses continuous paper tape, impregnated with lead acetate, to allow continuous analysis and a quantitative electrical output for chart recording and activation of alarms. The detector mechanism is similar in appearance to an open-reel tape recorder. Its operation and operating components are analogous to that of tape recording. Paper tape, a porous filter paper coated with an even concentration of lead acetate, is wound from reel to reel at a constant speed. The tape passes through a sample chamber through which gas from the ditch passes continuously. The tape will be discolored by an amount proportional to the concentration of lead acetate on the tape, the speed at which the tape is moving (both of which are constant), and the concentration of H2S in the sample. From the sample cell the tape passes to a detector where light from a collimated source is reflected from the tape to a photoelectric cell. The output of the photoelectric cell is readily calibrated in terms of H2S concentrations by passing through the system test paper strips with zones of different color that correspond to a range of known concentrations. The paper-tape-type detector may be used for the detection of COz or other gases if a suitably impregnated paper tape is available. Unlike the tube indicator, it is possible to discriminate between a baseline of atmospheric discoloration and a true “show” above baseline. Although the paper-tape-type is superior to the tube indicator, both suffer the disadvantage of requiring periodic replacement of the reactive material, lead acetate, and the possible degradation of the product in storage. Indicator tubes and rolls of paper tape are supplied in sealed, dated packages and should never be used if the seal is broken or the package is beyond its expiration date. Solid-State Electrical Detector. The most modem Hz S analyzers involve use of a solid-state electrical detector. This device depends on the reversible reduction of metallic oxides by HzS as its means of detection. A semiconductor sensor element is exposed to a flow of gas drawn from the ditch. The surface of this element consists of a proprietary metallic oxide layer. In the presence of HzS, this layer will be partly reduced to metallic sulfides, and its electrical resistance will change: (metal) O+HzS-+(metal)
S+HzO.
This is an equilibrium reaction. If Hz S ceases to be present, the reaction reverses with the reoxidation of sulfides to oxides. At all times, the sulfide-to-oxide ratio (and
hence the electrical resistance) of the layer is a direct function of the concentration of H2S in the sample present in the vicinity of the sensor. Alternative configurations of this device involve multiple installations with either samples being drawn from, or sensor elements located in, various locations around the rig with centralized monitoring and alarm functions. Locating the sensor in a remote location may cause problems if the sensor is exposed to potential damage or mistreatment. It does, however, remove the risk of loss of response resulting from gas dissolving in condensation in long vacuum lines. The device has high reliability and accuracy and is widely used in the industry. There are, however, two deficiencies that should always be considered. The first and most important is that if the sensor is operated for a period of time without any H2S present, it tends to lose reaction speed. (It is important to note here that the sensor does not lose sensitivity! It will respond, within calibration, to the presence of H2S, but will respond somewhat sluggishly to the first appearance.) For safety reasons, the sensor must be reactivated regularly by using a sample of H2S to maintain its reaction speed. Second, the sensor will respond to certain organic sulfides that may be present in oil or result from mud additive decomposition. The response to these compounds is low but may result in a false H2 S show. Soluble Sulfide Analyzer. One disadvantage common to all Hz S gas analyzers results from the high solubility of the gas in water. H2.S will not be liberated from the drilling fluid and will not be seen by a gas analyzer until a saturated solution of the gas exists. Since serious corrosion problems may be caused by low concentrations of the gas in mud and even a few ppm of the gas in air is a health hazard, it can be seen that by the time that HzS gas is detected at the surface, a major problem already has developed. Early detection of H2 S requites analysis of the drilling mud. This can be accomplished by regular sampling and wet chemical analysis, but the mud logging service can provide continuous soluble sulfide analysis by using a selective ion electrode measurement system. With this device, a sensor probe, which is immersed in the drilling fluid, contains pH (hydrogen ion) and pS (sulfide ion) specific electrodes and a temperature sensor. When HzS dissolves in water it will in part dissociate into bisulfide (HS -) ions and sulfide (S ~ -) ions. The solubility of H2S and the degree of dissociation are controlled by the pH and temperature of the solution If these two parameters and the concentration of a single dissolved sulfide species are measured it is possible to deduce the concentration of all other species. In the soluble sulfide analyzer this is done automatically by a microprocessor. By using this device it is possible to detect H2 S and begin treatment to remove it from the mud without concentrations ever becoming high enough for gas detectors to be effective or for personnel to be placed at risk. Geological Analysis After gas analysis, the most important function of mud logging is the sampling and evaluation of drill cuttings.
52-a
PETROLEUM ENGINEERING
Even when the mud logging unit operator is not a professional geologist, the minimum requirement is for identification and brief description of sample lithology, estimation of reservoir properties (amount and type of porosity and permeability), and description of oil staining. Sample Lag Time. Hydrocarbon and geological analysis depend on the representative sampling of drill cuttings and gases liberated by the cutting action of the drillbit. In interpreting the analytical results, it is necessary to account for the lag time and physical effects of the gas and cuttings travel from the bottom of the hole to the surface. ’ Lagging of samples is essential so that results may be reported or logged at the depth from which the sample originated (at the time the sample arrives at surface, the depth, of course, will be somewhat greater). Lag time may be obtained simply by calculating the time necessary to displace the total annular volume of drilling fluid as given by van=v,
van=-
-VP, qP v
)
,..,.....,.....,...........(l)
. . . . .. . . . . . . . . . .. . . . . .. . . . . . . .
(2)
an
and
I/=-,
D
...
.. . .......... ..... .
. .(3)
VCWI where V = annular volume, m3/m, VT = hole capacity, m3/m, VP = pipe capacity and displacement, V, = annular velocity, m/s, = pump output, m3/s, qP tl = lag time, s, and D = depth, m.
m3/m,
Separate calculations must be performed for each annular section (drillpipe in casing, drillpipe in open hole, drill collars in open hole, etc.). Calculated lag times ate used when first drilling out of casing or in hard rock areas where an in-gauge hole is expected. However, a calculated lag time cannot take into account capacity variation in out-of-gauge holes or variation in pump rate or efficiency (for example, when the pump is stopped to make a connection). Determining and using lag in terms of pump strokes has distinct advantages over lag determined on a time basis. The counters tracking the cuttings up the hole stop automatically when the pump is stopped. Clocks would continue to run, and some subtractive factor would have to be introduced. The most important advantage, however, lies in accuracy. A lag determined in terms of an interval of time is correct for only one speed of the circulating pump (that speed at which the lag determination was run), whereas the lag in pump cycles is accurate for any pump rate.
HANDBOOK
The lag can be determined by placing a tracer in the drillpipe at the surface when the kelly bushing is “broken off,” allowing the tracer to be pumped through the hole and back to the surface, and counting the number of strokes requited of the circulating pump to make this circulation. From this total pump stroke count, the number of strokes required to pump the tracer down through the pipe to the bottom of the hole is subtracted. This figure is calculated on the basis of the capacity of the drillpipe and the displacement of the circulating pump. The result is the “lag stroke.” Various materials (such as whole oats, barley, or strips of colored cellophane) may be used as tracers and picked up on the shaker screen for approximating the lag. Under ordinary circumstances, however, calcium carbide placed in the drillpipe will react with the mud to form acetylene. This gas will be picked up by the mud gas detector and is the most convenient and reliable method for determining the lag. Acetylene gas appears as wet gas on the gas detector and is easily distinguished from methane produced from the formation. Representative Cuttings Samples. There is no substitute for representative cuttings samples accurately correlated to the depth from which they came. They are the required supportive data for the evaluation of any mud logging, geological, geophysical, or engineering data. Every rig has a shaker screen for separating the cuttings from the mud as they reach the surface. The shaker screen may or may not be a good place from which to take cuttings samples. 3-5 If the shaker screen is used, a board or catching box should be placed at the foot of the screen for collecting composite samples. This becomes especially important where drill rate is low, to ensure that the sample collected is representative of the whole interval drilled and not just the final few inches. Where a traditional “rhumba” shaker is used, differences in flow through the possum belly (ditch at the rear of the shale shaker) will result in density and size sortings of cuttings across the various screens. This sorting can be of assistance to the logging geologist in partially separating large cavings from the smaller bottomhole cuttings. However, great care must be taken to ensure that a representative sample is caught. Where a modem “doubledeck” shaker is used, cuttings on both the upper and lower screens should be sampled. A sampling depth interval should be set that thz mud logger can be expected to maintain while keeping up with other responsibilities. Sample intervals can be shortened as the hole is deepened and drill rate falls. The mud logger should never allow more than 15 minutes to pass between catching samples. For example, if the sample interval is 10 ff and the drill rate is 10 ft/hr, the mud logger should take four scoops of samples over the hour to fill the sample bag for the interval. Special samples should always be taken whenever background gas changes are seen or the lag time after drilling breaks occur. If a board or catcher box is used, it must be cleaned off after each sample is taken. Samples should be taken from the desilter or desander outlets whenever these are running. In this way, the logging geologist can establish the quantity and appearance of sand and line solids commonly contaminating the mud system. If an unconsolidated formation is penetrated,
MUD LOGGING
sample from the desander will contain both formation sand and mud solids. The logging geologist must be able to discriminate between these. Washing and preparing the cuttings to be examined are probably as important as the examination itself. In hard rock areas, the cuttings are usually quite easily cleaned, in which case washing is a matter of merely hosing the sample in a container of water to remove the mud film. Washing the cuttings in many areas, however, partitularly areas and zones of tertiary sands and shales, is more difficult and requires several precautions. The clays and shales present are often soft and of a consjstency which goes into solution and makes mud. Care must be taken to wash away as little of the shale as possible, and, in determining the sample composition, to take into account that which is washed away. After washing the cuttings to remove the mud, they are washed through a 5-mm sieve unless doing so will further cause excessive loss of shale or clay. It is generally considered that the cuttings will pass through the S-mm sieve, and that the material that does not is cavings and may be discarded. However, the material that does not pass through should be examined for sand cuttings. If they should be present, these afford an excellent opportunity for study of larger-than-normal cuttings chips. Cuttings from wells drilled with oil-based or oilemulsion muds are usually more representative of the drilled formation than cuttings drilled with water-based mud because the oil emulsion prevents sloughing and dispersion of clays and shales into the mud. At the same time, washing and handling cuttings drilled with this type mud poses somewhat of a problem; they cannot be cleaned by washing in water alone. It is usually necessary to wash the cuttings first in a detergent solution to remove the mud. Some of the liquid commercial detergents available may be used. In extreme cases, it may be necessary to wash the cuttings first with a nonfluorescent solvent such as naptha, and then wash them in a detergent solution to remove the solvent. Use of a solvent is not advisable unless absolutely necessary because of the risk of removing any oil staining present. An oven mounted on the wall of the logging unit can be used to dry a portion of the cuttings sample after it has been washed, but some of the washed cuttings are examined wet under the microscope. A sample of unwashed cuttings also is required for cuttings analysis in the blender. Although these cuttings should not be rigorously washed, a light rinsing to remove surface drilling mud film is advisable. The logging geologist should extract a small amount of sample from each stage of the sample preparation process. From examination of all samples, an accurate estimate of sample composition can be produced. 3 Once the percentages of the various constituents have been estimated, the sample description in logical order should contain (1) rock type, (2) color, (3) hardness (induration), (4) grain size, (5) grain shape, (6) sorting, (7) luster, (8) cementation or matrix, (9) structure, (10) porosity, (11) accessories, and (12) inclusions. Only a visual sample examination usually is required at the wellsite in elastic (sand/shale) formations. In carbonates, other tests may be required to determine the chemical and physical nature of the rock. The simplest of these is to test cuttings with dilute hydrochloric acid; the
52-9
rate of reaction, which is rapid for calcite and slow for dolomite, provides a guide to relative composition. This test can be made more quantitative by use of a calcimeter. In this device a weighed sample is treated with acid in a sealed reaction chamber. Reaction is monitored by measuring either the volume or pressure of evolved CO;! over time until reaction is complete. Output is percentage of calcite and dolomite in the rock sample. In more complex mixed carbonates and sulfates (e.g., anhydrite and gypsum), a chemical stain kit may be used. Small samples of washed drill cuttings are spottested with a series of chemical test solutions. Characteristic coloration of a test solution is indicative of the presence of a particular mineral in the sample. Many excellent texts are available that discuss the geological aspects of mud logging. These include Low, 6 Maher, 7 and McNeal. * Since this chapter deals primarily with the technology of mud logging, they are not discussed further here.
Hydrocarbon
Content of Samples
In addition to a geological evaluation, cuttings samples must be tested for hydrocarbon content. A blender or cuttings gas analysis must be performed on every sample caught. This involves disintegration of a sample of cuttings in a blender, extraction of a sample of liberated gas, and injection into a total gas analyzer. This can be performed by manual extraction with syringe and injection into the unit’s online gas analyzer. However, for speed and continuity of operation, modem logging units use automatic extraction and injection into an independent catalytic combustion cuttings gas analyzer. As soon as a representative cuttings sample has been taken, a measured amount (100 cm3 in a measuring cup) of unwashed sample is placed in the blender jar and covered by 600 cm3 of water, then blended for 30 seconds and left to stand for another 30 seconds before taking a gas sample. If the hole is caving badly, the amount of cuttings may be increased but should be consistent-especially before and through a show. With hard carbonates, low-porosity sandstones, or similar reservoir rocks that cannot be efficiently pulverized by the cutter blades (40 to 60 seconds’ blending is recommended), the blender jar should be allowed to stand for 2 or 3 minutes before taking any gas readings. After the gas analysis is performed, the water should be inspected for oil signs or petroleum odor. Any droplets can be skimmed off for examination. The crushed rock material also may be of value in clarifying lithological evaluation. The blender is a good evaluation tool because it gives some indication of the quality of the reservoir with respect to the porosity and the GOR. A good porosity sandstone generally will be well-flushed by the time it reaches the surface, so the amount of cuttings gas obtained will increase proportionately to the decreasing porosity. This is also true with a sucrosic dolomite or high-porosity limestone such as chalk. However, if the reservoir is a fractured carbonate, etc., with all the oil and/or gas in the fractures, little or no cuttings gas will be recorded and the use of the blender as a porosity indicator is of limited value, because future production is
PETROLEUM ENGINEERING
52-10
going to be more dependent on the complexity of the reservoir fracturing than the inherent porosity and permeability of the rock itself. In oil reservoirs, gas is normally in solution with the oil, and the agitation of a covered sample provides an excellent index of the amount of gas with the oil, which is significant in view of the gas already recorded from the ditch. A high cuttings gas with an oil show should be treated as a very significant show and should be one of the more important factors to consider in the overall evaluation. When large intervals of reservoir rock are cored, the blender readings obtained are not likely to be as informative as those obtained if the section had been drilled normally. Generally, the amount of sample is reduced because the center is still in the core barrel. With the often slower drill rate, the percentage of cavings may be increased. Also, if a diamond head is being used, the rock will be coming back in a very ground-up and often badly altered state. Thus, if the geologist is agreeable, representative loo-cm3 samples from the more brokenup parts of the recovered cores may be blended with water, and any readings can be used to supplement the readings obtained during the actual coring. Inspection for liquid hydrocarbons should be made at the microscope (oil-stained cuttings), the blender jar (petroleum sheen and odor after blending), and in an ultraviolet light inspection box (fluorescent oil droplets on cuttings and diluted mud samples). Visible oil stain and color is an important indication of oil presence and type as are ultraviolet fluorescence intensity and color, grading from dull brown for the heaviest (residual or wet) oil to bright blue-white for light oils and condensate. However, crosschecking of observations is essential to confirm the presence of oil. Many mud additives, contaminants, minerals, or rig floor debris will have an oily appearance or odor and may fluoresce under ultraviolet light. Only if visible stain and ultraviolet fluorescence yield the same conclusion is oil confirmed. For example, samples contaminated with pipe-dope will have a dark oily ap-
Fig. 52.7-Comparative
results of REII, OSA, and THA
HANDBOOK
pearance suggesting heavy oil. However, the same cuttings examined under ultraviolet light will show a bright blue-white fluorescence characteristic of the highest gravity. This incompatability allows the identification of a contaminant and avoids the logging of a false show. A good mud logger should examine all mud additives stocked at the wellsite and determine, before their use, their characteristic properties and appearance when mixed with drilling mud or cuttings. If a true oil stain is identified, a single, representative cutting should be tested with an organic solvent. This is the “cut test.” Solvent cut is valuable in assessing fluorescence and allows deductions to be made of oil mobility and permeability of the reservoir. By removing the oil from the colored background of the cutting, the solvent allows a better estimate of fluorescence. The way in which the solvent cut occurs (e.g., instantly for highgravity oils, more slowly for more viscous lower-gravity oils, or irregularly streaming from limited permeability) also yields useful information. If no cut can be obtained from a washed cutting, the test should be repeated on a dried cutting, a crushed cutting, or after application of dilute hydrochloric acid. This will produce the required cut and yield further evidence on permeability or effective porosity. After the cut solvent has evaporated, a residue of oil remains in the cut dish, displaying the oil’s natural color. Finally, if sufficient oil is present, it may be possible to determine its refractive index. Just as oil stain color and fluorescence progressively change with oil type, refractive index correlates well with oil gravity. Portable refractometers that require only a small droplet of sample are available for use in the mud logging unit. By using a small quantity of oil (skimmed from the surface of the blender jar or a diluted mud sample), a very reliable estimate of oil gravity can be obtained. Geochemical
Analysis
More sophisticated analyses of hydrocarbon and hydrocarbon source material involve the principle of pyrolysis-thermal decomposition of a sample in an inert atmosphere. Three such devices are presently available: the Rock-Eva1 II*” (RE), the Oil Show Analyzer’” (OSA), and the Therrnalytic Hydrocarbon Analyzer’” (THA). All these devices use variations of the lnstitut FranGais du Pitrole-Centre de Recherches du Groupe Petrofina (IFP-FINA) temperature-programmed pyroanalysis method developed by Espitalie. 3,9 The process involves the heating of a weighed rock sample through an increasing temperature program in an inert helium stream. Since combustion cannot occur, the helium carries away from the sample hydrocarbons and CO2 resulting from the thermal volatilization of petroleum and organic source material in the rock. These evolved gases may be analyzed by flame ionization and thermal conductivity detectors. The amount of gas expressed as milligrams per gram of rock, the evolved gas, and the time and temperature of evolution may be used to characterize the richness and type of a reservoir or source rock. The differences between the three devices are shown in Fig. 52.7. The RE 11uses a uniform temperature ramp of 25”Umin up to 550°C. The helium stream carrying evolved gases passes to a CO2 trap and then to an FID.
MUD LOGGING
On completion of the pyrolysis the trapped CO2 is passed to a TCD. The output showing temperature, FID and TCD response is called a “pyrogram.” The RE II pyrogram characteristically shows two distinct peaks in FID response. The first, SI , represents true hydrocarbons, oil and gas, volatilized from the sample. The second, 52, represents hydrocarbons generated by the thermal cracking of hydrogen-rich organic source material, kerogen, in the sample. The temperature, Tmaxi at which the peak of S2 occurs is indicative of the maturity of the kerogen. Mature kerogen, capable of generating oil or gas, will have a T,,, in the range of 435 to 470°C. A lower T,,, indicates immature kerogen and a T,,, above 470°C indicates postmature material that has already yielded the majority of its hydrocarbon product. The TCD response, S3, represents the yield of CO2 from the thermal cracking of oxygen-rich kerogen in the sample. A comparison of S2 and S3 provides the relative hydrogen/oxygen richness of the kerogen. This is useful in estimating source type. Hydrogen-rich kerogen is prone to rich oil yields, whereas oxygen richness gives more gas-prone and lower-yield kerogen. The oil show analyzer (OSA) differs from the RE II in that it uses a nonuniform temperature consisting of two temperature steps followed by a temperature ramp. Following completion of pyrolysis the sample is further heated in an oxygen atmosphere causing the complete combustion of all remaining organic carbon in the sample. The OSA pyrogram generally shows three characteristic peaks in FID response with SO and Sl corresponding to the two temperature steps and representing the splitting of the RE II Sl peak into a lowertemperature (gas-indicating) peak and a highertemperature (oil-indicating) peak. The S2 peak and T,,, are the same as those seen in RE II. S4 represents CO2 produced by pyrolysis (S3 equivalent) and by combustion. Combination of the pyrolysis and combustion gas products provides a measure of the total organic carbon content or the gross organic richness of the rock. RE II has become widely used as a laboratory instru ment and both it and the OSA have seen use in the mud logging unit in frontier exploration. The restriction on their wider implementation in mud logging has been the high complexity (and price) of these instruments, which has limited their use to the most advanced logging units and demanding exploration environments. The THA, a much simpler device, is better suited to routine mud logging services. It uses only an FID and a temperature program similar to the OSA pyrolysis phase (without the final combustion phase). The THA pyrogram provides SO, Sl, S2 and T,,, . Neither CO;! analysis, S3, nor S4 is available from the THA.
The Modern Mud Logging Unit There are six basic requirements for a modem mud logging unit* based on the previous discussions. 1. A total combustible gas analyzer using catalytic combustion or flame ionization detector. 2. A gas sample dilution system, allowing maintenance of linear detector response at high gas concentrations or a backup thermal conductivity detector. 3. An automatic cycling chromatograph capable of
52-11
isolating
and
detecting
methane,
ethane,
propane,
butane, and isobutane or a second, low-voltage catalytic
combustion detector, allowing discrimination of “total gas” from “petroleum vapors.” 4. A separate cuttings gas analyzer, allowing gas analysis from blended cuttings samples. 5. A microscope and ultraviolet light inspection chamber for the identification and description of lithology and liquid hydrocarbons. 6. A pumpstroke counter, which, in conjunction with calcium carbide lag tests, allows gas readings and cuttings samples to be lagged back to correct drilled depth. In addition, the unit requires a drilling depth and time recorder for the determination of sample depth and the calculation of rate of penetration, an important rock strength/porosity indicator. Ideally, this should be independent of the driller’s depth recorder. Since mud logging samples (gas, oil, and cuttings) are extracted from the mudstream, changes in mud chemistry and rheology must be considered when evaluating mud log results. The logging unit should be equipped to perform basic mud tests-e.g., mud balance, Marsh funnel, sand test kit, and filter press. Laboratory glassware and chemicals are required to perform chemical tests and titrations on cuttings and mud filtrate samples. Although pressure control is not a standard function of mud logging (see Petroleum Engineering Services), the mud logger, by continuously monitoring mud gas content, should be aware of situations of potential drilling hazard. It is therefore usual for the mud logging unit to be equipped with a level monitor for the active mud pit. This allows the mud logger to be a second line of defense, after the driller, in detecting a well kick or loss of circulation.
The Mud Log Format ’ Fig. 52.8 shows a typical modem mud log. There are currently no industry standards for mud logs, and presentation varies among operators. However, the track order commonly follows that shown in the example. Truck I is used for rate of penetration (ROP). Also included in this column are items of drilling data that may affect interpretation of the log (bit types, changes in drilling parameters, circulation breaks, etc.). Track 2 is for depth notation and for symbolic representation of special evaluations (for example, cored or tested intervals). Truck 3 is a graphical representation of formations penetrated. Usually the column is subdivided into 10 equal columns and graphic symbols are used to represent 10% increments of lithology types seen in cuttings. Unlike other tracks on the log, the lithology track is not a calibrated physical measurement but a subjective assessment. Care should be taken to establish rules of drafting acceptable to the preparer and user of the log. Even after removal of cavings and contaminants, a cuttings sample is not truly representative of a single depth interval. Variation in particle size and density cause differences in annular recovery rate and mixing of cuttings in the annulus. A true cuttings percentage will never show sharp formation boundaries as a result of this mixing. For example, a thin sandstone within a massive
PETROLEUM ENGINEERING
52-12
IOLE
XL MUD LOGGING COMPANY COMPANY WELL
ABC OIL COMPANY NETHERLANDS
OF THE
COORDINATES
9”aAT
20’AT
7
x
735 *T
2995
5’ 02
ELEVATION
\EBREVIATIONS 4185 A,
5340’
AT
IUD TYPES
‘0’ 50” N 1530’E
SEAWATER GEL
TV
2300’
KCL POLYMER
TO
5345’
TO ~
API WELL INDEX NO SPUD DATE 514!78
.ITHOLOGY
SYMBOLS
AKBlo MSL 84 5 RKB lo SF 174 2
TOTAL DEPTH CONTRACTOR ,q,G , TYPE
5345 DEEPER DRILLING CO
CHARLIE JONES’JACKUP
LOG INTERVAL DEPTH FROM 400 SCALE
:ASING RECORD 30 AT 400
DESMOND Xl
F,ELD ANDORRA REG,ON DUTCH NORTH SEA
DATE
SIZE
FROM5478 -UNIT 1 500
LOG PREPARED
TO TO
5345 20 5 78
69, STANDARD BY
A EVANS,G
JONES
f3 EDWARDS
FORMATION EVALUATION LOG
Fig. 52.8-Mud
log formal
HANDBOOK
MUD LOGGING
shale with sharp boundaries shown clearly by ROP and total gas analysis may appear from cuttings to be a sandy shale horizon of much greater vertical extent. A geologist may use all available data to prepare an interpretive lithological log. That is, in the previous example, to sharply show the sandstone boundaries as indicated by ROP. Sometimes a mud logger will attempt to add some degree of interpretation to a cuttings log. Again, in the example the mud logger would show the presence of sand in all the cuttings samples but exaggerate the percent sand in the sample coinciding with the higher ROP. This “semi-interpretation” may result in confusion when later sample examinations are compared with the mud log and, in my opinion, mud loggers should be instructed to prepare a true cuttings log representing the percentages of lithologies actually seen in the sample. If the mud logger is geologically qualified and the operator’s geologist requires geological interpretation, then an interpretive lithological log should be prepared as an additional track on the mud log. Track 4 presents the results of hydrocarbon analyses. It may consist of one single width track but most often is subdivided into two or more separate tracks, as in the example. Track 4 will include the results of total gas, cuttings gas, and chromatographic analyses and when oil shows occur, an estimate of oil show quality and oil cut will be added. Supplementary gas analyses (helium, hydrogen, CO 2, or H 1 S) also may be added to this track or plotted on a supplementary log. Track 5 primarily is used for brief sample descriptions. Also included in this track are mud test results, casing and cementation records, hole deviations, carbide test results, and many other operating data used in interpretation of the mud log. On wider format logs, Track 5 also may be subdivided to add an interpretive lithology and an extra data track to be used for the results of special analyses or calculations. Interpretation The object of logging drilling-mud gas shows is to identify potentially productive oil and gas horizons. While such zones often may be indicated by major events-e.g., large gas and fluorescence shows-more critical interpretation is required to avoid false alarms or missed opportunities. Total Gas shows The magnitude of a total gas show is not in itself a conclusive indication of show quality. Gas detected at the surface originates in three ways: (1) from the disintegration of a cylinder of rock by the drill bit as the hole is deepened, (2) from the influx of gas from previously drilled formations exposed in the borehole wall, and (3) from the drilling mud itself in the form of recycled oil and gas and decomposition of mud additives. In extreme cases (for example, in long, geopressured shale sections or when using oil-based drilling fluids) influx or contamination may constitute the majority of gas seen at the surface. In such circumstances the magnitude of a gas show from a potential reservoir must be evaluated against the established background gas level from overlying sediments. Gas shows from relatively
52-13
thin horizons may be submerged in a high background and not identified from total gas alone (Fig. 52.9). Even gas reliably identified as resulting from a drilled interval may be misleading as a show-quality indicator. Factors that affect the magnitude of a gas show include the volume of the rock cylinder crushed in the drilling process, controlled by bit diameter and ROP and dilution of liberated gas in mud (i.e., the flow rate of drilling mud passing bottom as the hole is cut). Thus, gas show magnitude will be expected to increase in larger diameter holes, at higher ROP’s, or at reduced mud flow rate (Fig. 52.10). A simple technique is available to remove these factors from evaluation by normalizing gas show magnitude to a standard or “normal” set of drilling conditions:
R, lR OB ’ ”
(4)
where G pOs = observed total gas, %, G,, = normalized total gas, %, 4oB = observed mud flow rate, m”/s, 9n = “normal” mud flow rate, m’/s, d OB = observed bit diameter, m, d, = “normal” bit diameter, m, R = observed ROP, m/s, and it = “normal” ROP, m/s. Once a “normal” set of conditions are selected, the equation can be readily simplified giving
0.010
G,, = Gpo~
R OB -
and 0.0126 Gpos90B G,, =
(d,B)2
RoB
)
. .
.
. .
. ..
. (5)
where 9n = 0.050 m3/s (793 galimin), d, = 0.251 m (9.875 in.), and R, = 0.010 m/s (118 ft/hr). Normalization can be very useful in correlation of gas shows between wells drilled with very different programs. However, it should be remembered that normalization cannot remove the effect of influx and contamination; nor does it account for varying gas trap efficiency with ambient conditions. Finally, remember that the gas produced by drilling is liberated by the crushing of material at the bottom of the hole and is representative of the fluid composition within the rock pore space at the time of impact. Remember that oil and gas flow from a producing well; they are not mined. The presence of a fluid within a rock is not
52-14
PETROLEUM ENGINEERING
Fig. 52.9-Mud
Fig. 52.10-Variation
of total gas with drilling parameters.
necessarily indicative of productivity of that fluid ,fram that rock. Comparison of total gas analyses from mud and cuttings and chromatography can yield useful clues as to the productivity of a hydrocarbon-containing formation. Total gas from the cuttings blender test is a good indicator of fluid mobility. As the crushed rock cuttings are carried to surface and relieved of formation
HANDBOOK
log total gas shows.
hydrostatic pressure, exsolution and expansion of gas should effectively flush the cuttings, leaving only a small volume of residual fluid at the surface. When higher cuttings total gas, relative to ditch total gas, is observed, this is an indication that this flushing has been impeded. An obvious explanation is that the rock lacks sufficient permeability to allow gas expansion and flushing. However, residual low-gravity oil or tar will have a similar effect in impeding gas exsolution and escape. Inspection of cuttings lithology, fluorescence, and the cut test should provide confirming evidence (Fig. 52.1 I). For example, strong cementation or shaliness in the cuttings would be indicative of low permeability, whereas dark or dull oil stain and fluorescence with a slow cut or absence of cut is more indicative of heavy oil. At the opposite extreme of mobility, a formation may be so permeable that it is flushed effectively with mud filtrate even before being drilled. On recovery to surface neither mud nor cuttings will contain hydrocarbons. Indeed, no cuttings may be seen since such formations are commonly unconsolidated and disintegrate on recovery. In this circumstance the first observations will be a sharp increase in rate of penetration followed, after the lag time, by a “negative” gas show; total gas declines below the original background. Testing the desander effluent or a mud sampling probably will show an increase in loose sand grains. The negative gas shows confirms only the excellent permeability, and for this reason alone the zone deserves closer inspection when a resistivity log is available. No evidence is available of the formation’s fluid content from the mud log. Most potential reservoirs fall between these two extremes: producing (1) a positive gas show and (2) cuttings blender gas, depending on permeability and oil
52-l 5
MUD LOGGING
ss. LT GRI-B”FF. sue *NG. GO POR. S-iAlN. GO PL IEL ~LT,~L~u~H CUT
PLAS:OCC ss.
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IEL YEL-
--I . ,.... .
r !:-I. ;:!:{.‘.: ..I.. . ,/. / , .:,.. . . :. :... ‘. “ ::” ::: I:..:: I‘I ;:: : : --f-e++ ,:I; 1;: i : : i i , *. ,. ::._...::. :;I,:;’ j .: : :, :.,: r:;.:l: : ; p-’ ..& I ,./.
SS. BRN, NEO-CRS, W/RN0 OTL. W SRT. OL BRN OIL STN. EVEN 0”LL *EL-BRN FLOR, YE0 STRAW CUT. BRT “EL CUT FLOR
5% LT GRY-ERW. YE0 GR. SUB RNO. W SRT. FRI. WI S1L CUT. DULL ORNG BRN FLOR. SLO BRT LT YEL CUT FLOR
PETROLEUM ENGINEERING
52-16
gravity. Color and fluorescence of the oil stain and results of the cut test are indicative of oil type. However, note again that presence of hydrocarbons in the rock and even presence of porosity and permeability are not conclusive evidence of hydrocarbon productivity. Chromatogram
Interpretation
The hydrocarbon chromatogram is often a useful guide to reservoir productivity. It is not the actual amount of any one alkane that is significant but the relative amounts of light and heavy components characteristic of the overall reservoir fluid. Such characteristics normally can be recognized on the mud log itself. An aid to this can be the calculation and plotting of the numerical ratios of the values of the various hydrocarbons (e.g., C2/C I) C3/C1, etc.). Such gas-ratio plots will often yield distinctive “character” or “events” not always immediately evident from the chromatogram itself. However, interpretation of the plots depends on the same logical procedures. Most petroleum hydrocarbons originate from a similar organic source and proceed in their maturation by a similar temperature- and pressure-controlled physicochemical process. For this reason, petroleum accumulations, although markedly different in composition, tend to show a spectral relationship to each other in terms of the type and amount of hydrocarbon species present. Therefore, although two crude oils of 30”API gravity may be extremely different in total composition, they will contain some similar components in similar compositional relationships to each other. Since petroleum maturation continues by the continuous “cracking” of complex branch molecules into simpler straight chain molecules, these significant relationships are readily seen in the petroleum gases methane through butane. Thus, study of chromatographic analysis of these gases often may lead to a gross estimate of the type and quality of the reservoir. At low temperatures and shallow burial, biological and catalytic decomposition of organic debris results in a low-yield production of methane and CO2 Though the CO2 will dissolve in and migrate with pore waters, the methane will accumulate in porous zones either as free gas or in solution in water. Such zones will yield impressive gas shows when drilled, but with few exceptions will produce only gas-cut water. It is a reasonable general rule that a gas show containing methane as the only significant component is not commercially productive and is unworthy of further evaluation. However, it also should be remembered that exceptional cases do occur, including the southern North Sea nonassociated gas reservoirs that produce +94% methane. At higher temperatures, organic material first polymerizes to form kerogen, which is then hydrogenated and cracked with increasing temperature to form bitumens, tars, and progressively higher-gravity oil and gas. Associated petroleum gases are fragments of this cracking process and as cracking continues, the proportion of light to heavy gases increases in a manner similar to the lightening of the liquid hydrocarbon. This fractionation of gases and liquids continues during the migration of the hydrocarbons from source to reservoir.
HANDBOOK
The end result of this process is reflected in a gas show chromatogram. A gas-productive interval will show predominantly methane and ethane with only traces of the heavier alkanes. Oil productivity is signaled by the enrichment of the heavier alkanes, especially propane. Decreasing oil gravity is reflected by progressively greater proportions of propane and the butanes. In lowergravity oils, the concentration of these gases may exceed that of ethane. But all productive horizons will contain methane as the dominant alkane. Zones in which methane represents at least half of the total gas usually contain heavy residual oil from which the lighter gas and liquid fractions have migrated, leaving an immovable, nonproductive fluid. These general rules of chromatograph evaluation can prove useful in reservoir evaluation but of course should not be used in isolation. Conclusions regarding oil gravity and mobility should be compared with the results of blender tests, cuttings examination, fluorescence, and cut tests. Furthermore, evaluation should proceed from the prior-show baseline values and throughout the show interval. Considering the variables inherent in the drilling, transportation, and extractions of samples, no conclusion may be drawn from a single sample or analysis. Conventional
Mud Log
The conventional mud log offers more drilling and formation evaluation data in a single form than any other data source. Many of these data are subject to uncontrolled variables in the measurement technology and by the very nature of borehole environment. As a result, no simple conclusive rules of quantitative log evaluation are available. However, integration of all the data on the log with geological and regional experience can make the conventional mud log a most powerful exploration tool.
Petroleum Engineering Services Geopressure Evaluation The petroleum engineering functions of mud logging developed from the introduction of a number of pressure evaluation techniques during the 1960’s. These techniques are practiced conveniently in the logging unit and in some cases use data or equipment already available in the unit. Also, interpretation of the resultant data rcquires the same integrative approach, using drilling data and geological evaluation, as required in mud log interpretation. Unlike mud log evaluation, however, pressure evaluation techniques are able to provide reliable quantitative estimates of formation parameters, such as pressures and porosity. lo Drilling into a geopressured zone causes a change in a number of basic formation/drilling relationships. This change is usually a reversal of a gradual de th-related trend in a lithologically uniform formation. IP Compaction increases uniformly with depth in a normal pressured clay rock. A geopressured zone may be poorly compacted relative to those zones overlying it. Porosity and water content decrease uniformly with depth in a normal pressured clay rock. A geopressured zone in which dewatering has been slowed will show a reversal in the trend, with increased water content and increased porosity. Other factors relating to fluid movement, such as ionic concentrations, hydrocarbon saturations, etc.,
MUD LOGGING
52-17
may be different in geopressured zones. Differential pressure across bottom is the difference between the drilling mud hydrostatic pressure and the fluid pressure in pores of the undrilled formation at the bottom of the hole. Since drilling mud usually is denser than formation fluids, this difference will be positive and will increase with depth. In a geopressured zone, the formation pore pressure is abnormally high and the differential pressure across bottom will decline or even become negative. Thus, any measureable parameter that reflects any or all of these factors may be used as a means of interpreting changes in formation pressure and eventually as a means of evaluating and obtaining quantitative estimates of formation pore pressures.
Gas Analysis. The incursion of formation fluids into the borehole may result from a number of causes, some but not all of which result from an underbalanced condition-either temporary or permanent. ‘* If an underbalanced condition exists, there will be a natural tendency for fluid to flow from the formation into the borehole. With a formation having good porosity and permeability, this flow will be massive and a kick will occur. Such a kick will be indicated by the incursion of formation fluid downhole, causing the expulsion of mud from the borehole at surface. Were this to continue, a blowout would result. It is the logging geologist’s responsibility (other duties permitting) to monitor the mud pit level and to report any unpredicted or unexplained level changes. A massive incursion of fluid resulting in a well kick is unlikely to be misinterpreted as a gas show. In fact, if the hole is full, the kick should be recognized by a rise in pit level long before the fluid causing it has time to appear at surface. However, minor incursions caused by slight or temporary underbalance, or where insufficient permeability to provide a sustained kick exists, do occur and must be interpreted correctly. When an underbalance sufficient to cause a kick exists but there is insufficient permeability to sustain a massive fluid influx, a steady fluid “feed-in” may result. If this minor flow is from a discrete formation already cut, it will be noticeable - producing a sustained minimum gas background even when circulating but not drilling. If this is the case, the logging geologist should make a note of this sustained circulating gas on the mud log. If the feed-in is from the formation currently being drilled, then as a greater and greater area of formation in the borehole wall is exposed by drilling, increasing flow will take place. If this is the case, the mud gas will exhibit a sustained minimum when circulating but will consistently rise as drilling proceeds. Cuttings gas will inevitably be high relative to mud gas since it is only the lack of permeability that is preventing the feed-in from becoming a kick. Where permeability is effectively absent (e.g., in clays or shales) even a minor feed-in cannot take place. Fluid pressure in the rock will gain access to the borehole by the opening of pre-existent microfractures and partings in the rock. The result will be the caving or sloughing of rock fragments into the borehole, accompanied by a small amount of gas. A minimum gas background and, in this case, cavings recovery exist when circulating without drilling.
Fig. 52.12-Connection
gas indicating underbalance.
Circulating bottomhole pressure is higher than when the mud is static. This is caused by annular pressure losses when circulating. It is therefore possible for a feed-in, caving, or even a kick to result because of a resultant underbalance when circulation is stopped. Furthermore, pressure is further reduced because of the swabbing effect when pipe is moved upward-e.g., when making a connection. The literal meaning of “swabbing” is the pulling of a full-gauge tool from the hole, acting like the plunger in a syringe and initiating fluid flow into the borehole. Swabbing by moving the drillstring does not work in this way. When pipe is pulled upward, the high-viscosity gelled mud will attempt to move with the pipe, thus reducing the effective hydrostatic pressure acting on the borehole wall. Pressure reduction is a function of pulling speed, mud rheology, and annular diameter. The important consideration is that pressure reduction takes place not just below the bit but at all points in the open hole. Downtime gas or connection gas is a gas show resulting from the momentary underbalance caused by pump shutdown and/or pipe movement. It can be recognized by the occurrence of discrete gas show appearance at, or slightly less than, the lag time after circulation recommences. This is gas actually being produced by the formation and, while not being plotted on the mud log, the value should be reported on the log because it is indicative of formation permeability and fluid content. When a connection gas occurs, the logging geologist also should check a flowline mud sample for evidence of produced oil or salt water with the gas. The incidence of connection gas should be reported to the
PETROLEUM ENGINEERING
52-18
TOTAL GAS
I
NORMALIZED
HANDBOOK
I
:ONNEiC GA:SE
Fig. 52.13-Normalized
drilling supervisor, who may choose to increase mud density in response to the indicated underbalance. It is important to remember that the entire openhole section will be underbalanced by swabbing. The connection gas may not come from the bottom of the hole but from some horizon above. In fact, two or even more connection gases may result from a connection. For this reason it is important that lag time and annular velocities should be identified accurately by the logging geologist so that connection gases can be identified with the producing formation and the mud log annotated accordingly. Drilling into a permeable reservoir with an underbalance is potentially dangerous because a kick may result. Even if a kick does not occur immediately, the hazardous situation will be marked by an increasing feed-in as more formation is drilled, accompanied by progressively larger connection gases (Fig. 52.12). The condition should be reported by the logging geologist and noted on the mud log. If increases in mud density alleviate or remove the effect, this should also be noted on the mud log in explanation of the consequent reduction in gas. Fig. 52.13 demonstrates the effect of varying differential pressure on gas show magnitude. The total gas curves for two wells drilled through a similar section are shown. The data for both wells have been normalized to reduce the effects of hole diameter, ROP, mud pump output, and surface extraction efficiency. Well A was
total gas.
drilled with a constant mud density, whereas in Well B mud density was controlled to maintain a constant positive differential pressure (overbalance). In the upper portion of the section, the two gas curves are similar and the normalized gas curves coincide almost exactly. In the lower portion a progressive deviation between the two wells is seen that is somewhat reduced but remains evident even in the normalized curves. We can interpret this as being caused by the penetration of a transition zone into a geopressured zone. In Well A, maintaining a constant mud density results in a decreasing overbalance and eventually an underbalance or increasing negative differential pressure. Connection gases occur and become larger with deeper penetration. Additionally, feed-in of gas from the underbalanced borehole wall causes an increase in background gas that, since it is not a product of freshly cut formation, cannot be accounted for in the normalization calculation. Well B, on which a constant overbalance was maintained by increases in mud density, did not show increases in gas background or connection gases. Indeed, if any zone showed good permeability, the overbalance may have resulted in flushing gas away from the borehole and a reduction in observed total gas. By careful observation of these phenomena, a fairly accurate log of differential pressure (and hence pore pressure) may be obtained. This information should be used in conjunction with the other techniques described in the following paragraphs.
52-19
MUD LOGGING
Cuttings Evaluation. During the normal mud-logging process, cuttings are sieved and graded to a size assumed to be representative of drilled cuttings. The larger fragments are cavings from the walls of the borehole and play no part in the compilation of a lithological log. In geopressure evaluation, these cavings play a major role. The presence of cavings in the sample indicates that the borehole wall is unstable. The most noticeable and usually most predominant cavings are those of clay, shale, or calcareous lithologies. Coal, however, will cave as a matter of course, hence interpretations should not include coal cavings. The amount of cavings in the bulk sample is an indication of the degree of instability of the borehole walls. Simply watching the cuttings traverse the shaker screens will give a reasonable indication of the amount and size of the cavings in relation to the bulk sample. Cavings are produced by underbalanced drilling and stress relief. Abrasion of the walls by the drillpipe will also cause cavings, but generally these will not be discernible from cuttings because of their small size. If the pore pressure is higher than the hydrostatic pressure in the borehole, the hydrostatic pressure differential will cause the pore fluids to move toward the borehole. In an impermeable formation, the resultant pressure gradient adjacent to the borehole wall may become great enough to overcome the tensile strength of the rock. When this occurs, the rock fails in tension and cavings are formed. All parts of the earth’s crust contain stresses that change with depth, area, lithology, history, etc. Drilling a hole in the ground relieves some stresses other than those in the vertical plane, and the hole geometry in relation to some stresses acts to concentrate them. If the borehole wall is not supported sufficiently by the mud column, it may fail either (1) in compression from the vertical stress or (2) in tension from the horizontal stress, or both. The drilling process causes the formation of microcracks and fractures, and these act as areas of stress concentration and potential initial failure points. Thus it is sometimes noticed that part of a borehole may cave copiously for a short time and then become stable. This is because of the removal of the damaged zone (i.e., cavings) adjacent to the bore/formation interface. Formation is exposed that is more coherent and lacks concentrations of stress, thus it absorbs the extra energy without failing. Cavings produced by underbalanced drilling are typically long, splintery, concave, and delicate (Fig. 52.14a). Cavings produced by stress relief tend to be more blocky and can vary in size tremendously, depending on the formation characteristics. Examples are shown in Fig. 52.14b. Remember that if the cavings are clays, they may react with the mud and lose their distinctive morphology. Interpretations based on reactive clays should be pursued with caution. The quantity and nature of cavings should be regularly reported on the mud log or on a supplementary data log if pressure evaluation services are being performed. Shale Bulk Density. Shale density determination can be of great value since it provides information on the compaction of the shale. Under normal conditions, shale
FRONT hQ. L11 PLAN
‘ACE
Fig. 52.14-Cavings
resulting from underbalance
and stress
relief.
density should increase with depth. Any deviation from this consistent trend may indicate that geopressures exist. The magnitude of the bulk density change will vary with the type and magnitude of the geopressure. Often, the bulk density will decrease, but in other cases it may remain constant or continue to increase but at a lower rate than the previously established trend. Several methods are used for measurement of shale bulk density. Pycnometer Method. By using a container with repeatable volume, this method involves measuring change of weight resulting from displacement of fluid by the sample. The most practical application of this method at the wellsite is to use a mud balance. Place enough cuttings in the cup so that the balance indicates 8.34 lbm/gal (i.e., density of fresh water) with the cap on. Fill the cup with water and weigh again. The new reading is W2 in the following equation.
8.34 -Ys= 16.68-w2
,
. ...
.
where ys is the specific gravity of sample and Wz is the “mud weight” of sample and water, lbmigal. Mercury Pump Method. The bulk volume of a known weight of sample is measured. The bulk weight of a prepared sample is first established using an accurate chemical balance. The bulk volume of selected cuttings is then determined using a high-pressure mercury pump by the Kobe system (Boyle’s law principle) at a pressure of about 24 psi, which is recorded on the attached pressure gauge. Mercury is used to compress the air around the cuttings but does not contact the sample material. The high accuracy of the instrument and large amount of sample used (approximately 25 g = 2,000 individual shale cuttings) give good consistency of results. Because of the accuracy and convenience in operation, this method should be used whenever possible; however, very careful and consistent sample handling is necessary for best results. Buoyancy Method. The sample is weighed in air and in a liquid of known density. This is an alternative version of the pycnometer method. Theoretically, it should be a more accurate method if an accurate laboratory balance
52-20
PETROLEUM
DATA
HANDBOOK
trap air and water and result in low apparent densities. In addition, the fluids used have unpleasant odors and some of them may be hazardous to health. Toxicity labels should be checked for specific mixtures but it is a good general rule to use these fluids in a fume hood or with a vapor extraction system. It is commonly observed that shale density may decrease as much as 0.5 g/cm3 or more. If this reduction occurs over a significant depth interval, the calculated overburden gradient may reverse. The low-density zone also may change in lithologic character. Fissility, plasticity, carbonate content, color change, and other differences may not be apparent. Measurements from cuttings from water-based muds usually are too low, simply because of the adsorption characteristics of clays. Likewise, measurements taken from wireline logs can also give false indications. Specifically, the formation density log can be affected by a rugose hole and the shallow depth of investigation may not read beyond the hydrated zone. The result is erroneously low readings, causing excessive calculated porosities. The sonic log will be affected greatly by hydrated clays, resulting in very high transit times, high porosities, and too low densities. Values may be successfully obtained from these logs when water-based muds are used, but caution should be exercised as errors may exist, as explained earlier.
is used. In practice, it is most inaccurate since the density of the liquid will vary with ambient temperature. Density Comparison Methods. The simplest of these is the “float-and-sink” method. Shale cuttings are immersed in fluid mixtures of different densities in which they will either float or sink, depending on relative densities. This method is inexpensive and quick but is limited in sensitivity because of large difference in the densities of available fluids (approximately 0.1 to 0.05 g/cm3 and easy contamination of calibrated fluids. Density Gradient Method. This consists of a fluid column in which density varies uniformly with depth. This is prepared by the partial mixing of a light fluid (neothene) and a heavy fluid (tetrabromoethane) in which beads of known density are suspended. A calibration curve of density vs. depth is prepared. Shale cuttings immersed in the column will sink to the level at which their density is the same as the fluid. Depth is recorded and density read off from the calibration curve. Both of the heavy liquid methods (density comparison and density gradients), while being quick and simple, have the disadvantage of determining the density of individual cuttings. Special care must be taken to ensure that cuttings are true bottomhole cuttings, and several determinations should be made for each interval to avoid anomalous results. Six or eight cuttings should be chosen that are representative and free of dust or cracks that may
SHALE
ENGINEERING
PRESSURE
Fig. 52.15-Shale
LOG
data log.
I
52-21
MUD LOGGING
The best densities are those obtained from wells drilled with less reactive muds, such as oil- or potash-based fluids. Both actual cutting densities and log densities should be accurate because the clay remains in its virgin state. Increases in density beyond the normal trend because of decreased porosity or calcification should be noted carefully since these may constitute caprocks above geopressures. Precipitation of pyrite or high iron concentration results in abnormally high bulk densities in clays and shales. It has been proposed that in some wells the occurrence of pyrite in shales masked the density reduction caused by porosity increase. Careful microscopic examination of clays may indicate the occurrence of very fine pyrite, and high iron concentration is indicated by a red/brown color cast. Pore pressure interpretations cannot be accomplished by using shale density if heavy minerals are present; however, since shale density is mainly used for qualitative purposes in geopressure evaluation, the role of the other geopressure indicators remains unchanged. Any decrease in density (without change in clay character) may be recognized as a pressure transition zone. Recognition of a normal bulk density trend line may be difficult because of degree of scatter in the rectangular coordinate plot. A semilog plot considerably reduces this scatter, but the normal bulk density range (approximately 1.6 to 2.7 g/cm3) results in a more distorted trend line and difficulty in recognizing deviations (Fig. 52.15). Shale Factor. Ion-exchange reactions take place between an adsorbent solid and a solution. Ions bound to the solid surface are released into the solution and other ions from the solution become fixed at the surface. Ion exchange can proceed by the exchange of positive ions (cations) or negative ions (anions) but not both. The reactivity of a solid compound in ion exchange reactions is governed by its specific surface (surface area per unit volume) and by the surface density of ion exchange sites (points on the surface where ions may be bound). Reactivity is expressed as cation or anion exchange capacity (CEC or AEC) using units of milliequivalents (of a suitable ion) per hundred grams (of the compound). Various clay types have different CEC’s and consequently different adsorption capacities. A smectite-rich clay will undergo diagenesis to illite with increasing temperature and ionic exchange. For diagenesis to proceed, water must be flushed from the clays. If potassium exchange cations are not available, a montmorillonite clay will lose its water but will not convert to illite. Thus, if this type of clay is drilled with a water-based mud, the clay will immediately rehydrate and cause severe drilling problems. Shale factor is a measure of clay CEC. CEC will decrease as clays convert from montmorillonite-rich to illite-rich with temperature (and thus with depth). Pure montmorillonite clays have a CEC of approximately 100 meq/lOO g. Pure illites show no swelling characteristics, but their CEC is generally between 10 and 40 meqilO0 g. Kaolinites have a CEC of approximately 10 meq/lOO g. Of the most common clay types, it is only the smectite group (including montmorillonite) that has an affinity for water. Thus, any clay zone that contains montmorillonite
Fig. 52.16-Shale
factor response.
will have an affinity for water in an amount proportional to the montmorillonite content, and this will be shown by a proportional value of shale factor. Note that the shale factor as measured at the wellsite will not give values corresponding to actual chemical CEC. This is because of impurities in the sample, methodology, experimental error, and the fact that the methylene blue dye (used in the titration) is a very large molecule and thus cannot be adsorbed in interlayer sites. If the clay is calcareous, and calcimetty is also being performed, then the shale factor may be corrected for carbonate content as given by 100 Fstu =
xFsha,
......
..... . ..
100 - Cca*
where F $ht = true shale factor, meq/lOO g, F sha = apparent shale factor, meq/lOO g, and c cart, = carbonate content, %. For example, a calcareous clay has a carbonate content of 37 % , and an apparent shale factor of 16: 100 Fsht = -1oo-37(16)=25
meq/lOO g.
Theoretically, shale factor should indicate whether montmorillonite dehydration or compaction disequilibrium was the major mechanism in generating an apparent geopressure. Geopressures caused by compaction disequilibrium indicate that the pressured zone is immature with respect to shallower, normally pressured sediments. This implies that diagenesis has been restricted by the inefficiency of the dewarering mechanism, resulting in clays containing a larger proportion of montmorillonite within the geopressured zone. Shale factor would thus decrease to the top of the geopressured zone, increase within the zone, and then decrease as the pore pressure gradients decline (Fig. 52.16). Any overall increase in shale factor within a geopressured zone indicates that compaction disequilibrium has played a part in its formation.
52-22
PETROLEUM ENGINEERING
EARTH’S
-
HEATFLOW
LINES
SURFACE
---
EQUITEMPERATURE
Fig. 52.17-Distortion of heat flow geopressured zone.
around
LlNES
an insulating
If, however, a geopressured zone was caused by montmorillonite dehydration, then upon entering the interval a sharp decrease in montmorillonite content will be observed. Hence the geopressured zone will contain less montmorillonite, because it has been converted to illite, which releases to the pore spaces water that has been unable to escape fast enough and results in a pore pressure increase. Shale factor thus will decrease in the pressured zone (Fig. 52.16). Shale factor cannot be a geopressure indicator. The differing responses described are not definitive, and geopressure has to be indicated from other sources before an interpretation by use of shale factor can be achieved. Geoprcssures caused by montmorillonite dehydration and compaction disequilibrium may cause no change in shale factor; also, if geopressures were caused by another process (e.g., aquathermal pressuring that results when trapped pore fluids are heated but are unable to expand and is therefore independent of matrix composition), a change may not be reflected in shale factor with depth. In the past, the consensus was that shale factor should increase in geopressured zones and could thus act as an indicator. Re-evaluation of the various geopressure mechanisms show that this is not necessarily the case. However, shale factor should be capable of delineating between compaction disequilibrium and montmorillonite dehydration as the major geopressure mechanism. Flowline Temperature. The geothermal gradient, the rate at which subsurface temperature increases with depth, can be calculated from ‘2-11
gG=
D -D 2
(loo),
.
.. . .....
. .
I
where gG = geothermal gradient, “C/100 m, T, = temperature, “C (at depth D, , m), and T2 = temperature, “C (at depth D2, m). For any given area, the geothermal gradient is usually assumed constant. While the average gradient across
HANDBOOK
normally pressured formations may be constant, geopressured formations exhibit abnormally high geothermal gradients. l3 Since a constant flow of heat occurs radially from the earth’s core to the surface, the total flow of heat across any depth increment will be constant. However, the temperature differential across an increment depends on the thermal conductivity of the material. Since overall heat flow from the earth’s surface is generally constant within any particular area, the heat flux through the various formations with depth is in equilibrium. The rate of change of temperature across a formation with a low thermal conductivity (caused mainly by high porosity) will be high; conversely, a low geothermal gradient is indicative of high thermal conductivity formations-i.e., lower porosity. Water and hydrocarbon migration to shallower depths may also affect the geothermal gradient. Pore fluids, as insulators, retain heat so that on migration these hot fluids modify the temperatures of the formations that they pass through and ultimately become trapped. Fowler14 cited examples from the Middle East, Canada, and U.S. oil fields of geothermal gradient bulges that indicated possible entrapment of hot fluids from greater depths. The mechanism also may be related to montmorillonite dehydration, because the huge volume of water squeezed from the clay provides the impetus for migration. “Dead” basins (i.e., no source rocks) have been shown to exhibit normal geothermal gradients, hence on initial exploration wells the geothermal gradient may indicate the potential of the whole area. An insulating zone produces a distortion in the isothermal lines that normally run perpendicular to the lines of heat flow (Fig. 52.17; Ref. 15). Because of the high geothermal gradient, these are more closely spaced in the insulating zone. In the zones above and below, the isothermal lines are more widely spaced in compensation and the zones exhibit a reduced geothermal gradient. The converse occurs in beds of high thermal conductivity (i.e., sands and some limestones) Since water has a thermal conductivity of about onethird to one-sixth that of most rock matrix materials, it can be seen that thermal conductivity is directly related to the degree of compaction of a formation. The higherthan-normal water content of geopressured shales reduces the thermal conductivity. Therefore, the top of a geopressured zone is marked by a sharp increase in geothermal gradient. The temperature of the mud at the flowline may reflect the geotemperature, and recording of flowline temperature is a practical method to determine temperature gradient, provided variable factors such as pump rate, lag time, ambient temperature, lithology, and temperature changes at the surface that are caused by mud mixing and chemical treatments can be accounted for. In areas where large annual temperature variations occur, considerable differences may be noted in flowline temperatures; even diurnal temperature fluctuations may cause a 10°C variation in flowline temperature while drilling. Prior to reaching a geopressured zone, a temperature transition zone will be encountered in which, because of distortion of the isothermal lines, there will be a reduction in geothermal gradient. In practice, this effect is
MUD LOGGING
52-23
TEMPERATURE
Fig. 52.18-Flowline
reflected in the flowline temperature gradient, even to the extent of a fall in flowline temperature (i.e., a negative gradient), followed by an extremely large increase in flowline temperature as the geopressured zone is penetrated (Fig. 52.18). A dual temperature probe system with sensors at the flowline and suction pit is effective in removing surface effect, if lagged differential temperature is plotted. It is normally sufficient for the points to be plotted at 30-e intervals unless more frequent temperature variation is noticed, but points plotted at 104 intervals allow more accurate data and better resolution for improved interpretation. Circulations, mud additions, water additions, and other significant events should be noted. It is found that the resultant temperature curve is broken when the bit is changed, or during short trips or other downtime, and a certain time is necessary for the mud system to re-establish a temperature equilibrium upon circulation. The rate at which this thermal equilibrium is re-established may be significant. as a more rapid re-establishment may indicate an increased geothermal gradient. Drilling variables that affect the
DATA
LOG
I
temperature log.
rate of re-establishment of equilibrium include total mud volume. The practice of reducing active pit volume to a minimum, dictated by hole size, aids in reducing the time required to attain equilibrium after tripping and reduces the circulation time needed to stabilize flowline temperature. A discontinuity in the plot also occurs at each casing depth and corresponds to a change in hole size. A higher annular velocity in open hole reduces the amount of heat gained from exposed formations, and a lower annular velocity in the marine riser increases the amount of heat lost to the sea. However, these factors only lead to a change in measured temperature; the rate of change of temperature should remain unchanged. Since pressure predictions can be based on temperature gradient rather than on temperature magnitude, each depth segment between discontinuities can be analyzed separately for gradient trends. It is also helpful to replot a smoothed curve of segments end to end without regard for absolute temperature values. In certain cases it has been found that, instead of plotting the individual segments as an end-to-end smoothed curve, end-to-end plotting of the individual segment trend lines may be of
52-24
PETROLEUM
ENGINEERING
HANDBOOK
removing the need to derive empirical matrix strength constants, but making d-exponent lithology-specific as in
d=
where d = drilling exponent (dimensionless), R = ROP, ft/hr,
N = rotary speed, rev/min, W = WOB, lbm, and db = bit diameter, in. IIFFERENTIAL PRESSURE ,CROSS BOTTOM (PSI)
RATE OF PENETR*T,ON (CONSTANT N.W.0.EC0)
Fig. 52.19~-Response
0°C
of drilling rate to geopressure.
value. This trend-to-trend smoothed curve is merely a graphical method of removing irrelevant scatter from the plot. The reduction in temperature gradient caused by distortion of isothermal lines may be noticed before the geopressured zone is encountered; that is, an advance warning of geopressure may be given. Thus a fall in flowline temperature gradient followed by a sharp rise when the geopressure transition zone is drilled provides a warning that even closer attention must be paid to other drilling parameters to achieve confirmation of possible geopressures. However, like other methods of pressure evaluation, flowline temperature reflects a varying physical parameter in an assumed constant rock type; therefore, changes in lithology must be closely monitored to avoid false indications.
Drilling Models. Bingham I6 proposed that the relationship between ROP, weight on bit (WOB), rotary speed, and bit diameter may be expressed in the general form
R
-= N
,.......................
(9)
where R = ROP, ft/min, N = rotary speed, rev/min, db = bit diameter, ft, W = WOB, lbm, Kn = matrix strength constant (dimensionless), and d = formation “drillability” exponent (dimensionless).
Jorden and Shirley ” solved Eq. 9 ford, inserted constants to allow common oilfield units to be used and to produce values of d-exponent in a convenient workable range. Most important, however, they let KD be unity,
In a constant lithology, d-exponent will increase as the depth, compaction, and differential pressure across bottom increase. Upon penetration of a geopressured zone, compaction and differential pressure will decrease and be reflected by a decrease in d-exponent (Fig. 52.19). Differential pressure is dependent on mud density as well as formation pore pressure. Therefore, any change in the mud density used promotes an unwanted change in d-exponent. Rehm and McClendon” proposed a “mud weight corrected” drilling exponent of the form
dxc = where d,, = corrected d-exponent (dimensionless), R = ROP, ftlhr,
N = rotary speed, revimin, dh = bit diameter, in.,
g+, = normal formation balance gradient, lbm/gal, Pet = effective circulating density, lbm/gal, and W = WOB, 1,000 lbm, or in the metric form
. . (12)
with R in m/hr, N in rpm, Win tonnes (1,000 kg), db in cm, and g,p and ,oec in gicm3. This correction was empirically derived but has been applied worldwide with much success. The use of actual mud density in place of effective circulating density (ECD) has been found to be acceptable within normal limits of accuracy. ECD should, however, be used when available. Factors not considered by d-exponent in its basic form are drilling hydraulics, tooth efficiency, and matrix strength.
MUD LOGGING
52-25
, J
I SEMlLOG
SCALE
0°C
Fig. 52.20-Example of formation pore pressure gradients for d, plot.
Drilling hydraulics become important in large holes where efficient hole cleaning is impossible and in soft formation where jetting will make a large contribution to drilling. Matrix strength controls both magnitude and rate of change of d-exponent with depth. Tooth efficiency can affect d-exponent in two ways: (1) tooth wear will cause a gradual increase in dexponent (i.e., decrease in ROP), and (2) a change of bit type may produce a change in d-exponent, especially if the change is a radical one (e.g., from milled-tooth bit to an insert or diamond bit). If differential pressure becomes large, the simple ratio correction to the d-exponent will not eradicate the effect on ROP. Furthermore, the relationships among force applied, Wldb,rotary speed, N, differential pressure, g,,~,/p~(., and ROP, R,are more complex than the d-exponent formulation would imply. While working well within certain normal working ranges, radical changes in any of these parameters (for example, change in hole size after setting casing) may result in a shift in d-exponent trend. When plotted on a logarithmic scale against depth, the d-exponent will exhibit an approximately linear increasing trend through “normal,” hydrostatically pressured formations. Where geopressure, abnormally high formation fluid pressure is encountered, d-exponent values will fall consistently below the extrapolation of this normal trend. It has been shown empirically that d-exponent deviation may be related to formation pore pressure anomaly by the simple ratio --Ppa -
dxcn )
Ppn
d.xco
.
. .
.. .
..
.(13)
Fig. 52.21-Logging
unit systems.
where PPa
PPn
pore pressure at depth of interest, psi, or formation balance gradient, lbmlgal equivalent mud density (EMD), normal pore pressure, psi, or formation balance gradient, lbmlgal (EMD), observed corrected d-exponent at depth of interest, and expected corrected d-exponent on normal trend line at depth of interest.
= actual
=
dxc-0 = dx-n=
Using this relationship, it is possible to calculate pore pressure or formation balance gradient (equivalent mud density to balance pore pressure) from d-exponent. Alternatively, the relationship may be used to prepare an overlay allowing direct reading of formation balance gradient from the d-exponent plot (Fig. 52.20). Drilling exponents may be calculated from driller’s data using a simple calculator and manual plotting and trend recognition. However, quality of the data is greatly improved when a data-acquisition system provides WOB, rotary speed, and mud density directly to the logging unit and a minicomputer is used to read these sensors automatically, to perform the calculations, and to print or plot the results. Computer-equipped mud log-
52-26
PETROLEUM ENGINEERING
it :, :::::t::::i::::l::1:i:Xt
Fig. 52.22-Formation
ging units were introduced to provide pressure evaluation services in areas of known geopressured problems (e.g., offshore U.S. gulf coast) and high-risk, hazardous exploration areas (e.g., the North Sea). Fig. 52.21 shows the available equipment configurations of a computerized logging unit. In addition to pore pressure, this type of unit commonly provides a pressure log including supplementary calculations of fracture pressure, overburden pressure, and kick tolerance (Fig. 52.22). Petrophysical Measurements Mud Log Data. As discussed previously, mud log data are qualitative in nature. It is not possible with conventional mud log measurements to obtain quantitative values of such parameters as porosity, permeability, hydrocarbon saturations, etc. However, the mud logging unit may provide special equipment or services, allowing more quantitative evaluations. For example, while a mud log gas analysis cannot be truly representative of gas production composition, gas analysis of recovered fluids from a well test can be. Using conventional gas analyzers and chromatograph, a quantitative analysis of recovered natural gas may be obtained. For more complex fluids, special chromatographs, pyrolyzers, or analyzers can give complete analysis of oils or sour gas. The logging unit also may provide ionic analysis of recovered waters and, by use of tritium ( 3H) or nitrate (NO3) tracers, provide discrimination between recovery of mud filtrate and true formation water. These types of service can be of special
HANDBOOK
I
pressure log.
value in remote locations where logistics or distance prevent rapid transport of samples to an analytical laboratory. Core Analysis. In addition to gas and fluid analysis, conventional core analyses I9 (porosity, bulk density, permeability, and saturations) also may be performed in the logging unit when the drilling operation is remote from the laboratory. Wellsite core analysis offers the advantages of rapid evaluation and high-quality samples from fresh core but is rarely of the high quality to be expected from the specialized equipment and personnel in a core laboratory. A new technique, which is suitable to the logging unit, uses a pulsed nuclear magnetic resonance analyzer to determine fluid content, total and free-fluid porosity, and permeability. This device, working on a principle analogous to the nuclear magnetic logging tool (NML), provides accurate, repeatable data from minimal quantities of sample and without complex sample preparation. Samples may be obtained without causing core or sidewall core destruction and the test may be performed on cuttings. Drilling Porosity The d-exponent (Fig. 52.20) develops a consistent trend with depth controlled by increasing overburden loading and compaction. Changes in formation pore pressure gradient will result in major, consistent deviations from this trend. The d-exponent data also will exhibit minor,
52-27
MUD LOGGING
POROSITY
PERMEABILITY [MILLIDARCIES]
ROCK
PROPERTIE
FORMATION DENSITY
I
Fig. 52.23-Drilling
inconsistent scatter about the prevailing trend, reflecting continuous variation in rock mineralogy, cohesion, and porosity. More sophisticated, second-generation drilling exponents are able to isolate the major pore pressure and minor rock character variations. With this type of analysis it is possible to provide a continuous log of pore pressure and “drilling porosity.” It is important to remember that drilling porosity, although scaled in percentage units, is not a true porosity measurement. It is primarily a rock strength indicator, reflecting both porosity and intergrain cohesion. As such, its response is very similar to that of the sonic log, and the two logs correlate extremely well (Fig. 52.23). Unlike the d-exponent, the second generation drilling exponents require complex manipulations and iterations, limiting their use to logging units equipped with a computer. Also, unlike the d-exponent, they do not involve a widely published and used single method. Although based on similar drilling response models, all mud logging contractors offer drilling porosity logs involving their own unique mathematical methods that are commonly held as proprietary secrets. While understandable from a commercial view, this policy places the user in the position of being able to judge the value and reliability of a particular log only on the bases of his or her own experience and limited published results. It is hoped that, with the maturation of this type of service, wider publication and discussion of methods will begin.
1~~~ PSEUD(
)-SON1
porosity log.
Drilling Engineering
Services
The mud logging unit can provide two levels of service of value to the drilling engineer-data acquisition and data analysis. Data Acquisition An automatic data acquisition system located in the logging unit will monitor sensors installed on equipment, flowline, mud pits, pumps, etc. Simple calculations are performed on the data (e.g., calculation of total depth and ROP, summation of pit volumes, comparison of current values with high- and low-alarm setpoints). Results then are displayed on TV monitors at various locations around the rig and may be recorded on a printer or magnetic tape. By use of a dedicated land line or satellite link, data can be transmitted to a remote location, allowing several rigs to be monitored from a single central control room. This type of equipment was introduced by mud logging service companies as a means of obtaining drilling and mud data more reliably and rapidly than could be expected from standard rig instrumentation. While these data were required initially for pressure evaluation analyses, the data acquisition system provided an important secondary function as a rig monitoring service by supplying the drilling engineer accurate, up-to-date drilling information while away from the rig floor and a complete foot-by-foot record of drilling progress and performance on paper or magnetic tape.
PETROLEUM
52-28
Since that time. several conventional rig instrumentation manufacturers have upgraded their product lines to include similar data acquisition systems that operate in an unmanned, or “stand-alone,” mode. While this offers the operator the advantage of flexibility in selecting services (i.e., the mud logging service best suited to the geologist and the data acquisition service best suited to the engineer), it does have drawbacks. Reliability of a data acquisition system is primarily controlled by the operation of its sensors. In the rigorous environment of the rig this requires regular attention. The success of a stand-alone data acquisition system is related entirely to the training and motivation of the rig crew or the availability of manufacturer’s service personnel. The mud logging unit is manned at all times. Trained personnel are available at all times to calibrate, maintain, and service the data acquisition system and its sensors. Since these personnel are already at the wellsite as part of the mud logging service, this extra margin of reliability is achieved without extra cost beyond the similar cost of the data acquisition hardware.
Data
Analysis
Beyond simple data acquisition, the mud logging service also may supply computers, software, and specialized wellsite personnel for drilling data analysis. The desirability of such services depends on the difficulty and cost of the drilling operation, availability of oil company expertise at the wellsite, and quality of communication with the exploration headquarters. For example, infill drilling in an established domestic field using a well-developed drilling program, experienced wellsite supervisors, and close communication with home office requires data acquisition only as a means of monitoring optimal and safe adherence to the drilling program. On the other hand, on an offshore wildcat, the availability of data analysis and expertise at the wellsite can be very cost effective. *O An increase in drilling efficiency or a decrease in downtime sufficient to save a single day of rig time can, in these circumstances, produce sufficient savings to pay for data analysis services for the whole well. Data analysis services offered include: (1) bit optimization-selection of bit type and operating parameters to optimize bit ROP and bit life; (2) bit economics-cost per unit depth and breakeven calculation between bit types; (3) drilling hydraulics2’ -optimization of drillstring, nozzle, and annulus hydraulics; (4) directional analysis-determination of well path, bottomhole position, and intersection points for deviated wells; (5) trip monitoring-calculation of string weights, swab pressures and fillup requirements for tripping, monitoring of pit level deviations, and overpull (frictional drag in the borehole); (6) casing calculations-assembly of casing tally, calculation of cement volumes and mixing requirements, and monitoring of displacement; (7) pressure control-calculation of mud weight, volume and pressure requirements for safe well control lo; and (8) logistics-usage and inventory control of well expandables, equipment maintenance scheduling, well progress data base, and report generation.
ENGINEERING
HANDBOOK
Selecting a Mud Logging Service Mud logging contractors commonly offer three levels of standard service: (1) standard mud logging; (2) mud logging and data acquisition, and (3) mud logging and data analysis (including pressure evaluation). For the most basic level of mud logging, a single operator may tje responsible for 24-hour operation. More sophisticated services and data acquisition usually require two geologists working 12-hour tours. Data analysis services require two people, a geologist and an engineer. on each tour. Each of these services may be augmented with extra equipment such as sensors, special gas detectors, pyroanalyzers, more powerful computers or peripherals and specialist personnel at extra day rate as the drilling program demands. 2,10 At least two mud logging contractors now offer an additional, fourth level of service in which mud logging and data analysis are combined with an MWD service. Very little of the information gathered by a mud logging unit is not obtainable from some other source. For example, stand-alone instrumentation can monitor gas, mud, and drilling parameters; rig crews can catch samples; porosity is available from wireline logs; and oil company geologists and engineers may perform geological evaluation and drilling data analysis. Why then is mud logging such a widely used service? The advantage of mud logging service is that all these data may be derived from a single source, the mud logging unit, located at the wellsite and continuously manned with dedicated, specially trained personnel. Therefore the data are obtained more reliably, more quickly, and usually more economically than from any other combination of sources. Reliability and speed therefore are the tests required in selecting a mud logging contractor. The equipment must be designed and maintained adequately to provide reliable and safe operation in the rigorous wellsite environment. The wellsite crew must be trained to operate, maintain, and troubleshoot the equipment and to understand its output. The contractor must maintain adequate service personnel and inventory to allow rapid repair or changeout in the event of major malfunctions. The logging crew must be trained in geological and engineering theory, be experienced in practical drilling operations, and have a thorough knowledge of the geological section, drilling program, and operational procedures of the particular well and operator. Once a contractor is selected, economy becomes the prime consideration in choosing a level of service. In day-rate drilling, time and money may be directly equated. Any service that speeds well progress, reduces downtime, or promotes decision-making is potentially a cost saver. Even on footage drilling, personnel, communications, etc., are cost-generating factors which may be reduced by improved drilling efficiency. On rank wildcat exploration wells, the “bird in the hand” philosophy may be desirable to obtain data at the earliest possible time as a hedge against the risk of it being unavailable later. For example, to obtain porosity measurements from the mud logging unit while drilling is an investment against later borehole loss or damage that may prevent later wireline logging.
MUD LOGGING
52-29
Quantification of cost saving is possible by using the same methods used to calculate drilling cost per foot. In its simplest form this is
Cd=
Cbe
+
D,
Crr/
For cost effectiveness (i.e., for the additional service to save its own cost or more), overall well cost must be unchanged or reduced. Thus,
A(cdXD,)=(cd )
.
...
.
A(CdXD,)= where Cd = C, = Cbp = 11 = D, =
XD,)‘-(cd
XD,)Io,
-Acml
-[E(c,,),
+AC,, x[C(t,),
drilling cost, $/m, rig cost, $/D, cost of bits and expendables, time on location, days, total well depth, m.
-At,,],
+.
~CFn)+(Cdrl
X(t,+tt+t,+t,+td)];D,
AC,, I
+CdR.. . .
AC,,
+
[~(c,,>,
+Af,,
1
.
. . . . .
.cdrn) .(15)
’ . ’’’’
Onshore
CdxD,=C(CF),, +C(C,,), xc(t),,.. I..... (16) where CF = individual fixed cost items or footage charges services, $, Cdr = individual day rate services, rentals, salaries, etc., $, t, = rotating time, days, t, = tripping time, days, to = off-bottom time (reaming, conditioning, well control, etc.), days, t, = evaluation time (logging, testing, coring, etc.), days, and td = downtime (breakdowns, weather, decision making, etc.), days. Using this formulation, it is possible to calculate the decrease in one cost category required to offset an increase in any other. For example, consider the use of drilling optimization. Let us assume, conservatively, that regional statistics indicate that by upgrading a mud logging unit to include data acquisition equipment no overall ROP improvement is obtained but that a well can be completed using one less bit. Well cost as a result of this is given by xD,)‘=[C(c~)n
+WC,,), where ACFbl AC,, (f,),? At,, (Cd xD,)’
= = = = =
ACFbl z(cdr) n Ar,l C(AZ[)~
AC,, I
cost of one bit saved, dollars, extra cost of mud logging, dollars/D, total time on location, days time for one trip saved, day, and well cost. dollars,
= = = =
$l,ooo $6,000/D 12 hours=0.5 30 days
Offshore
day
ACF~I E(c&)n Atrj E(Afl),
= = = =
$1,000 $19,OlWD 12 houn=O.S 35 days
day
1,000+(6,000)(0.5) (30 -0.5)
=$135.59/D. The extra equipment will result in an overall cost saving on the well so long as it does not increase the mud logging daily rate by more than $135/D. We obtain for offshore: 1,000+(19,000)(0.5) AC,, 5
(35 -0.5)
=$304.35/D. Using these same figures, let us now assume that, in addition to saving one bit, an overall decrease of 5% in drilling time is also achieved. If I, =21 days, saving in rotating time=21 ~5% = 1.05 days, then for onshore: I 1,000+[6,000 XT
--Art, I, . (17)
(20)
we obtain for onshore:
Ac
-AcFbll
+Ac,,l[W,),
(19)
If this is evaluated as true, that the day rate for the extra equipment is in fact less than the evaluated expression, then the service is cost effective on the particular well. In this case, substituting some reasonable figures such as:
and
(cd
....
$,
For optimization of services and products this can be expanded to the form +CF2
(18)
xAt,,l
[E(t,), -At,,]
Cd=[(CFI
.
. (14)
(0.5+1.05)]
(30-0.5-1.05) =$362.04/D.
For offshore: 1,000+[19,000
(0.5+1.05)]
AC,, = (35-0.5-1.05) =$910.31/D.
PETROLEUM
52-30
These cost justifications, or cost savings, refer only to the extra cost of data acquisition above that of standard mud logging and include only those benefits resulting from drilling optimization. Other cost savings resulting from better rig and mud monitoring and well control may also be quantifiable from a study of regional drilling statistics. A cost benefit analysis of this type is a worthwhile approach to all aspects of drilling cost reduction. Cost saving resulting from advanced evaluation and monitoring commonly is appreciated in expensive offshore exploration. As the above examples show, such techniques may be equally successful in comparatively cheaper onshore development drilling, especially where problems such as geopressure or crooked holes occur.
Standards
Nomenclature = C carh = Cd = C dr =
cost of bits and expendables, dollars carbonate content, % drilling cost, dollars/m individual day rate services, rentals, salaries, etc., dollars Cf = individual fixed cost items or footage charges services, dollars C, = rig cost, dollars/D d = formation “drillability” exponent (dimensionless) db = bit diameter, ft or in. d, = “normal” bit diameter (m) d0~ = observed bit diameter (m) d,,. = corrected d-exponent (dimensionless) d,,.,, = expected corrected d-exponent on normal trend line at depth of interest d,,, = observed corrected d-exponent at depth of interest = apparent shale factor, meq/lOO g Fh F h = true shale factor, meq/lOO g G P” = normalized total gas (%) G poB = observed total gas (R) Cbr
= =
KD = N= Ppu =
P/m = 4n = qoB = q/J= R= R, = R
For and Status of Services
The terms “mud logging” covers a diverse range of services and qualities of service. It is regrettable that, in the U.S. especially, the whole industry is accorded a status reflecting its lowest level. Field employees of the higher quality and more reputable contractors commonly eschew the term “mud logger,” preferring the title “logging geologist” or “logging engineer,” depending on their educational background. The wide range of equipment and techniques used by such companies commonly results in their personnel being the best educated and trained service personnel present on any wellsite. In 1980, the Sot. of Professional Well Log Analysts (SPWLA) established a Hydrocarbon Well Log Standards Committee comprising members of both the service company and exploration company sides of the field. The efforts of the committee have done much toward establishing standards and status representative of the best of the industy. 22,23 I express my gratitude to this committee and its members for these efforts and for assistance in the development of this chapter.
gc gq%
OS
=
td
=
t,
=
fl
=
Ol),
= I,
=
t,
=
t, v
= =
;;
=
VP
=
varl
= w=
(CdXD,)’
=
AC Fbl = AC,, = At,, = Per =
ENGINEERING
HANDBOOK
geothermal gradient, “C/100 m normal formation balance gradient, lbm/gal matrix strength constant (dimensionless) rotary-speed, rev/min actual pore pressure at depth of interest, psi, or formation balance gradient, lbm/gal equivalent mud density @MD) normal pore pressure, psi, or formation balance gradient, lbm/gal (EMD) “normal” mud flow rate (m3/s) observed mud flow rate (m3/s) pump output, m3/s) ROP, ft/min “normal” ROP (m/s) observed ROP (m/s) downtime (breakdowns, weather, decision making, etc.), days evaluation time (logging, testing, corm ing, etc.), days lag time, seconds total time on location, days off-bottom time (reaming, conditioning, well control, etc.), days rotating time, days tripping time, days annular volume, m 3/m hole capacity, m3/m pipe capacity and displacement, m3/m annular velocity, m/s WOB, Ibm well cost, dollars cost of one bit saved, dollars extra cost of mud logging, dollars/D time for one trip saved, day effective circulating density, Ibm/gal
References 1. “Field Geologists Training Guide.” Exploration Logging Inc., Sacramento, CA (Jan. 1979). 2. “Mud Logging: Principles and Interpretation,” Exploration Logging Inc., Sacramento, CA (Aug. 1979). 3. “Formation Evaluation-Part I: Geological Procedures.” Exploration Logging Inc., Sacramento, CA (Feb. 1981). 4. Hopkins, EA.: -“ Factors Affecting Cuttings Removal During Rotary Drilling,” .I. Pet. Tech. (June 1967) 807-14; Trans.. AIME, 240. 5. Sifferman, T.R. et al.: “Drill Cuttmg Transport m Full Scale Vertical Annuli,” J. Pet. Tech. (Nov. 1974) 1295-1302. 6. Low, J.W.: “Examination of Well Cuttings,” Quarterly cjj r/w Colorado School ofMines (1951) 46, No. 4. l-48. 7. Maher, J.C.: Guide book V/I/: Lqging Drill Curtings, Oklahoma Geological Survey, Norman (1959). 8. McNeil, R.P.: “Lithologic Analysis of Sedimentary Rocks.” Eu[(., AAPG (April 1959) 43, No. 4, 854-79. 9. Clementr, D.M., Demaison, G.J., and Daly, A.R.: “Wellsite Geochemistry by Programmed Pyrolysis.” paper OTC 3410 presented at the 1979 Offshore Technology &if&-ence. Houston, April 30-May 3. 10. “Theory and Evaluation of Formation Pressures: The Pressure Log Reference Manual.” Exploration Logging Inc., Sacramento, CA (Sept. 1981). I I. Hottman, C.E. and Johnson, R.K.: “Estimation of Formation Pressures from Log-Derived Shale Properties,” .I. Per. Tech. (June 1965) 717-22: Trans.. AIME. 234.
MUD LOGGING
12. Goldsmith. R.G.: “Why Gas-Cut Mud is Not Always a Serums Problem,” Work! Oil (Oct. 1972) 175, No. 5, 51-54, 101. 13. Dawdle, W.L. and Cobb, W.M.: “Statrc Formation Temperature From Well Logs,” J. Per. Tech. (Nov. 1975) 1326-30. 14. Fowler. P.T.: “Telling Live Basms from Dead Ones by Temperature,” World Oil (May 1980) 190, No. 6, 107-22. 15. Lewis, C.R. and Rose, S.C.: “A Theory Relating High Temnerature and Ovemressures.” J. Pet. Tech. (Jan. 1970) ll-lb. 16. Bineham. M.G.: A New Amroach to lnfemretinn Rock Dnllabiii” ry, Fetroieum Publishing i3b., Tulsa (1965). 17. J&en, J.R. and Shirley, O.J.: “Applicatmn of Drillmg Performance Data to Overpressure Detection,” J. Per. Tech. (Nov. 1966) 1387-94. 18. Rehm. B. and McClendon, R.: “Measurement of Formation Pressure From Drilling Data,” Dn’llin~, Reprint Series, SPE. Dallas (1973) 6a, 49-60.
52-31
19. Anderson, G.: Corin,q und Core AnaI~~sisHundbook. Petroleum Publishing Co., Tulsa (1975). 20. Bellottt, P. and Giacca, D.: “Pressure Evaluation Improves Drilling Programs,” Oil and Gus J. (Sept. 11, 1978) 76-85. 21. “Drilling Hydraulics Manual,” Exploration Loggmg Inc., Sacramento, CA (July 1983) 8. l-8; 9, l-10; 10, 1-7: D, l-4. 22. “SPWLA Standard No. 1: Standard Hydrocarbon Well Log Form.” SPWLA. Houston (June 1981). 23. “SPWLA Standard No. 2: Hydrocarbon Well Log Calibration Standards,” SPWLA, Houston (June 1981).
General Reference Jorden, J.R. and Campbell, F.L.: Well Log,& Borehole Environmenf,
Mud and Temperarure
Series, SPE, Dallas (1984) 9.
I-Rock Logging.
Prupenies,
Monograph
Chapter 53
Other Well Logs Richard M. Bateman,
vizibg
IK.
*
Introduction Many well logs generally are not classified as electrical, nuclear, or acoustic logs. The most important of these are discussed in this chapter. Included as miscellaneous well logs are: (1) measurements taken while drilling (MWD), (2) directional surveys, (3) dipmeter logs, (4) caliper logs, and (5) casing inspection logs. All of these are used by the petroleum engineer on occasions. The logs are discussed in the order listed, which was selected for convenience only and is unrelated to the importance of the logs.
MWD plays an increasingly important role in modem drilling practices. It allows an operator almost immediate feedback on both the geometry of the hole being drilled and the characteristics of the formations penetrated. Without MWD this kind of information is available only from conventional sources such as deviation surveys and logs that, a priori, must be run after the drilling has taken place. Of particular benefit, MWD can be applied when drilling directional wells and/or when overpressured formations are of concern. By having the kind of information MWD can supply more or less in real time, the driller may take appropriate action, such as changing the weight on bit (WOB), increasing the mud weight, or pulling out of the hole for a conventional logging run once the desired formation has been reached. Many different MWD measuring systems are in commercial use today. However, they all have common characteristics: (1) a downhole sensor sub, (2) a power source, (3) a telemetry system, and (4) surface equipment. The downhole sensor subs may contain instrumentation capable of measuring parameters such as torque, *Aulhor of the OrIginal chap!er on this topic. enblled “Miscellaneous Well Logs.” I” the 1962 edilion was A.J. Pearson
WOB, borehole pressure, borehole temperature, tool face angle, natural formation gamma ray activity, formation acoustic travel time, formation resistivity, hole deviation from vertical, and hole azimuth with respect to geographic coordinates. The sensors and the telemetry system can be activated by a surface power source, a downhole turbine, or downhole batteries. In the case of a surface power source it is necessary to make electrical connections between the surface and the downhole sensors, which, in turn, requires either special drillpipe or an electric cable. With a downhole turbine the circulating mud itself drives an electric generator located in the MWD drill collar. This, in turn, leads to an increase in the hydraulic horsepower required of the mud pumps to maintain circulation. In the case of batteries no special cabling or additional mud pumping is required, but the MWD system is limited by the life of the batteries used. Once they are discharged no fmther measurements can be made and the MWD sub must be retrieved and redressed with fresh batteries. The telemetry system most commonly used is that of coded mud pressure pulses. The output from a specific sensor is converted from analog to a digital form and encoded as a series of pressure pulses, which are detected and decoded at the surface. The pressure pulses may be in the form of overpressure or underpressure anomalies introduced, respectively, by either a relief valve “shorting” the mud circulation or a check valve “choking” it. However, coded mud pressure pulses are not the only means available for telemetry. Other methods, either in use or under experimentation, include: (1) electromagnetic e-mode (electric current) or h-mode (magnetic field); (2) acoustic telemetry through drillpipe and/or tubing in straight hole, or through the earth by seismic waves; (3) hardwire systems; (4) systems with self-energizing repeaters; and (5) hybrid systems that combine various transmission methods. ’
PETROLEUM
53-2
-
Mud Flow
-
Transmitter
._
Generator
-
Turbine
.-
Electrical Cable
.-
Sensor Package
-
Drill Collar
Fig.53.1-Typical MWD
ENGINEERING
HANDBOOK
The surface equipment consists of a decoder of the mud pulses (or other parameter, depending on the telemetry system in use) together with signal processing hardware and software that together produce the data that the drilling engineer needs. Output may be in the form of a visual display, either on the rig floor or at a remote site, or as a hard copy listing, or log, of the parameters recorded. Data also may be recorded on magnetic tape for future use. In most systems, the transmission of data to the surface is selective. For example, a measurement of hole deviation and azimuth may require that the drilling process be suspended temporarily and the drillstring held motionless for a short period. Readings then are accumulated in a “buffer’ ’and only transmitted to the surface when mud circulation recommences. Fig. 53.1 illustrates an MWD downhole assembly with its mud pulse transmitter, turbine generator, and sensor sub. Fig. 53.2 shows a data transmission schematic for MWD. Typically, each measurement or “word” is transmitted as part of a data frame, which in turn consists of a synchronization word and 15 measurement words. Some measurements are transmitted more than once in each frame. Current telemetry systems are capable of transmitting a complete frame in a matter of 1 or 2 minutes. The actual sampling rate in terms of measurements per unit of depth is inversely proportional to the rate of penetration (unit of depth/ unit of time). * Fig. 53.3 shows a complete MWD logging system schematic and integrates surface and downhole sensors, the telemetry system, the surface hardware and software (for computer processing of the data), and the final product in the form of a log. 3 Fig. 53.4 shows an MWD log on which is displayed gamma-ray, short normal resistivity, annular temperature, downhole WOB, surface WOB, and computed directional data (drift and azimuth).
downhole assembly.
-
M ” L r , P L E x E R
-
Fig. 53.2-MWD
data transmissionschematic.
OTHER
WELL
53-3
LOGS
Fig. 53.3-MWD
logging system schematic
Fig. 53.5 shows a comparison between an MWDgenerated computed directional survey and a multishot run in the same well. Table 53.1 illustrates a directional survey listing corresponding to the plan view shown in Fig. 53.5.
Directional Surveys Directional surveys4T5 are used to determine the location of the hole path with respect to the surface location. This information is used (1) to prove legally that the bottomhole location is under the correct surface property, (2) to ascertain the bottomhole location in purposely deviated wells, (3) to determine the radius of curvature of the hole as it affects the ability to run casing or tools, and (4) to differentiate between measured depth and true vertical depth (TVD) when using formation elevations for structural mapping. Available
Tools
The two basic types of directional surveys are continuous surveys and station surveys. The station surveys can be either single shot or multishot. Single or multi refers to the number of stations recorded. Single shot surveys normally are recorded during the drilling operation and are
recorded at given depth or time intervals. These singleshot records are accumulated and used to plot the hole path. Multishot surveys are the result of several shots run at given depth intervals after the hole has been drilled. Continuous surveys are run after a portion of the hole has been drilled. These are recorded continuously over the selected interval. Although continuous, multishot, and single-shot instruments are all different, there is another classification of instruments that must be considered when choosing a survey. Surveys run inside metal casing cannot use the magnetic compass for hole direction. Gyroscopes normally are used whenever a survey is needed inside casing. These gyroscopes must be aligned on the surface before proceeding with the survey. They also should have their alignment verified as part of the after-survey checks. The openhole directional surveys normally use magnetic compass orientation to fix the hole direction. This requires the input of the deviation between magnetic and true north. All devices use a pendulum system for determining the angle of hole deviation. All continuous dipmeter surveys measure data that can yield a directional survey. This directional survey is available either as part of the dipmeter or as a separate
PETROLEUM
ENGINEERING
HANDBOOK
Fig. 53.4-An MWDrotary drilling log.
survey over portions of the hole where formation dips are not desired. At present, this instrument does not work in a cased hole, so the survey must be tied in to known coordinates at the bottom of the casing. Any device that uses a magnetic compass to fix direction will be affected by metal in or near the borehole. This effect must be considered when a survey is run in an open hole that has been whipstocked past abandoned drillpipe or may be near a cased wellbore. Fig. 53.6 illustrates a gyroscopic survey tool incorporating an accelerometer. Legal Requirements Each state has a separate definition of what constitutes a “legal” directional survey. These definitions may include specifications such as (I) length of downhole sensor, (2) whether or not such assembly is centered, (3)
method of calculating station-type surveys, (4) professional qualifications of person supervising or certifying the results, and (5) documentation, presentation, and distribution of results. These criteria must be considered when choosing a service company and a type of survey. Computation of Results Directional surveys are available in any area where directional drilling is done or where dtpmeters are available. The field log may be a series of station readings or a continuous curve showing hole direction and deviation. The computed results will include a well plat that shows the vertical projection of the wellbore. Additional plots may show wellbore projections on a vertical plane passing through the surface location. A tabulated listing will show the wellbore coordinates and deviation angle,
OTHER
-100 1500
WELL
LOGS
100
T
53-5
300
500
700
I
I
NORT” I100 I
900 j
1300
IS00
1700
I
,
1900
SOjIO bR$HEO 1100
I 1 opo
LINE LXNE
ORTR
/ rFpO?l YSl?
FTI
I
1
900
e :3 6
100
‘ij 5 8 so0 j
300
100
-100
-300
Fig. 53.5-Comparison
of MWD
Methods of Calculation. There are many methods of calculating directional surveys. 6 Most companies use one of the following five basic methods. 1. Tangential Method. This method uses the inclination and azimuth angles at the bottom of each course length (distance between readings or stations). This is usually the most common and least accurate method. The error introduced increases with the inclination angle and the course length. This method is not recommended. 2. Balanced Tangential Method. This method uses the inclination and azimuth angles at both the top and bottom of each course length to tangentially balance the two sets of measurements over the course length. This method is more accurate than the tangential method but is still sensitive to the course length.
directional with multishotdirectional
3. Angle Averaging Method. This method uses a simple mathematical average of the inclination and azimuth angles at the top and bottom of the course length to compute the survey using the tangential method. This is more accurate than the tangential method but still simple enough for hand calculations in the field. Course length should be kept as short as feasible. 4. Radius of Curvature Method. This method uses the inclination and azimuth angles at the top and bottom of the course length to generate a space curve representing the curve path. This space curve passes through the measured angles at the top and the bottom of the course length. This method usually is considered the most accurate but is still sensitive to course length.
PETROLEUM
53-6
TABLE
53.1~MWD
DATA
LISTING FOR
DIRECTIONAL
Readings Course Length
Survey Number
Deoth
90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 133 134
5425.0 5457.5 5,478.0 5.509.0 5.540.0 5571.0 5.589.0 5,605.O 5,631.0 5.695.0 5,735.0 5,756.0 5,821.0 5,852.0 5,949.0 6932.7 6,090.O 6,117.0 6,150.2 6,216.2 6,241.8 6,272.0 6,302.O 6,337.0 6,402.O 6,455.8 6,553.3 6,600.3 6,678.3 6,708.3 6.740.3 8,771.3 6838.3 6,893.g 6,926.7 6,989.4 7,020.O 7,054.o 73084.4 7,114.2 7,153.g 7,184.8 7,240.l 73272.7 79285.8 7,316.g 7,346.0
m 30.0 32.5 20.5 31.0 31.0 31.0 18.0 16.0 26.0 64.0 40.0 21.0 65.0 31.0 97.0 83.7 57.3 27.0 33.2 66.0 25.6 30.2 30.0 35.0 65.0 53.8 97.5 47.0 78.0 30.0 32.0 31.0 67.0 55.6 32.8 62.7 30.6 34.0 30.4 29.8 39.7 30.9 55.3 32.6 13.1 31.1 29.1
ENGINEERING
HANDBOOK
SURVEY
Analysis(confidencelevel=99.0%) Angle (degrees) 37.80 37.67 36.53 35.73 35.72 35.08 35.08 34.35 33.90 32.17 31.28 30.97 28.87 27.88 26.52 24.65 23.63 22.80 22.45 21.27 20.93 19.68 19.78 19.30 18.28 17.17 15.87 14.92 14.62 14.78 14.32 13.85 1318 12.63 12.87 12.55 12.58 12.60 12.40 11.50 10.90 10.00 7.90 7.40 7.00 7.40 5.90
Azimuth Angle (degrees) ~41.80 43.50 43.50 44.00 41.80 42.40 42.40 42.80 43.30 46.30 47.40 46.60 45.10 47.20 45.40 46.10 48.90 47.00 46.10 46.80 46.00 48.20 44.80 46.10 41.80 49.50 50.10 59.50 47.20 53.50 5590 59.50 57.90 57.60 63.30 67.80 66.30 65.70 67.10 66.90 66.90 68.60 68.90 63.00 66.90 58.70 58.40
Dogleg 1100 ft 2.34 3.22 5.52 2.75 4.14 2.33 0.00 4.79 2.03 3.72 2.64 2.47 3.43 4.52 1.64 2.26 2.67 4.15 1.48 1.83 1.71 4.85 3.84 1.85 2.64 4.82 1.34 5.67 4.03 5.35 2.38 3.20 1.14 0.99 3.90 1.66 1.06 0.35 1.18 3.02 1.51 3.08 3.80 2.85 4.81 3.54 5.15
5. Mercury Methods. This method is used by the U.S. Government at the Mercury Test Site in Nevada. This is a combination of the tangential and balanced tangential methods. The portion of the course length defined by the length of the surveying instrument is treated by the tangential method. The remainder of the course length is treated by the balanced tangential method. All these methods are critical to the course length or separation between stations. As the course length increases, their inaccuracies and deviations from each other increase. As the course length decreases, they all become more accurate. On very short course lengths (10 ft or less) there is very little to choose between the methods. For this reason, directionals computed from
Vertical Depth (fi) 5,180.4 5.206.1 5,222.5 5,247.5 5,272.7 5.298.0 5,312.7 5,325.a 5,347.4 5,401.o 5,435.0 5,453.0 5,509.3 5,536.6 5,622.g 5,698.4 5,750.7 5,775.5 5,806.i 5,867.4 5,891.2 5,919.6 5,947.8 5,980.a 6,042.3 6,093.6 6,187.0 6,232.3 6,307.8 6,336.8 6,367.8 6,397.8 6,463.0 6,517.2 6,549.2 6,610.3 6,640.2 6,673.4 6,703.l 6,732.2 69771.1 6,801.5 6,856.2 6,888.5 6,901.5 6,932.3 6,961.Z
UncertaintyRange North
East
696 710 719 732 746 759 767 773 784 809 823 831 853 863 894 919 935 942 951 968 974 981 988 997 1,012 1,023 1,041 1,048 1,060 1,065 1,069 1,073 1.082 1,088 1,092 1,097 1,100 1,103 1,106 1,108 1,111 1,113 1,116 1,118 1,119 1,121 1,122
559 573 581 594 606 618 625 631 641 666 681 689 712 723 755 781 798 806 815 833 840 840 855 863 878 889 911 921 937 942 949 955 969 979 986 998 1,004 1,011 1,017 1,023 1,030 1,035 1,043 1,047 1,048 1,052 1,055
Vertical Maior 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.4 1.4 1.4 1.4 1.4 1.4 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6
10.0 10.0 10.0 10.0 10.0 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.3 10.3 10.3 10.3 10.3 10.3 10.3 10.3 10.3 10.3 10.3 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4
Axis 9.5 9.5 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.7 9.7 9.7 9.7 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9
343 344 344 345 346 347 347 347 348 351 352 353 356 357 3 6 8 8 9 10 10 11 11 11 12 13 14 14 15 15 15 15 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16
continuously measuring devices, such as dipmeter tools, may be more accurate than station reading devices. Dipmeter devices normally compute every 1 or 2 ft although data listings may be accumulated and listed only every 50 ft. Presentations. Directional data are normally presented both in well sketches and tabulated data. Well sketches include two elements. 1. Plunar View. This is a vertical projection of the wellbore path on a horizontal plane. Such a projection shows the separation between the wellbore and the surface location. The wellbore path is marked with measured depths.
OTHER
WELL
LOGS
53-7
2. Vertical Sections. These are of two types. The first is a projection of the wellbore on a vertical plane through the surface location and aligned at various azimuths. The second is plot of depth against closure where closure is the horizontal distance of the wellbore from the surface location. The tabulated data listing will show the measured depth, vertical depth, hole azimuth, deviation angle, x and y distances, and closure distance.
Field Examples.
Fig. 53.7 shows a number of
tions of deviation survey
computations
TO ELECTRONIC5
SECTION TOP
4
presenta-
including: (.A)
SLIP
RINGS
plan view,(R) vertical section, and (C)depth vs. closure. The deviation survey listing is also shown in Table 53.2.
Dipmeter Logging Introduction The dipmeter tools arc run to determine the direction and angle of formation dip from the survey of one borehole. This information is of obvious importance in the study of structural and stratigraphic problems. 7 As illustrated in Fig. 53.8, the angle of formation dip is the angle between a horizontal plane and the bedding plane of the formation. The strike of a formation is the direction of the horizontal line formed by the intersection of these two planes. Although strike is a common geologic term (particularly in surface geology), it is more convenient to use “dip azimuth” in discussing the dipmeter. The direction of dip is perpendicular to the strike. In the remainder of this section dip azimuth will be used instead of strike. Dipmeter tools are in a class by themselves. The technique, the purpose, and the intemretation of dipmeter logs arc entirely different from those of other logging tools. The dipmeter’s purpose is to measure the dips of formations. To do this, the tool must simultaneously and continuously do two separate jobs: first, it must orient itself in space, normally with respect to magnetic north and vertical, and second, it must react to formation bedding planes. All present dipmeter tools go about this job in the same way. An inclinometer section supplies continuous measurements of deviation, both the amount and the direction, and of the orientations of the tool’s electrode array, either with respect to the borehole direction or magnetic north (a few specialized tools for far north operations use gyroscopic orientation, nominally with true north). At the same time, an electrode array is maintained in contact with the borehole wall by pressured linkages. The electrodes respond to resistivity variations, while the expanding linkages activate a caliper recording. These pads, normally numbering four, are identical, and so mounted as to remain in a plane normal to the tool axis. When an anomaly is detected by at least three pads, these deflections plus the caliper reading identify three points in what is assumed to be a plane, the plane of deposition of the formation. This identification is then referred to vertical and true north, giving the true dip of the formation. Recording correct data with a dipmeter tool is a straightforward, more or less mechanical process, though the tools used to do it are some of the most sophisticated in the industry. Interpreting the data draws heavily on computer technology.
‘ACCELEROMETER
INPUT
KATE
tiYH0
SPIN
AXIS-
\
INPUT
AXIS
AXIS
WY~IMBAL
rVRCjIJl.
MOTVK.
-RESOLVER
c Fig. .53.6-Eastman Whipstock Seeker-l.
PETROLEUM
Fig. 53.7C-
ENGINEERING
HANDBOOK
Deviationsurvey depth vs. closure.
Fig.53.7A-Deviation survey plan view
c I
T
Calibration. The dipmeter is essentially a physical tool, and its calibration is physical. The inclinometer section is adjusted to read correctly in a special test jig. Special care is given to ensure that the deviation sensor registers zero with the tool held vertical. The operation of the inclinometer is checked before and after each log run, first by allowing the tool to hang vertical in the derrick, then by rotating the tool manually through at least one full revolution. The calipers are checked as usual, by calibration jigs of known diameter. Four-arm dipmeters record a separate caliper with each opposing pair of pads, which can thus flex independently of each other while remaining in the same plane. Finally, the sensitivity of the electrodes is checked by shorting them out in sequence; this also verities the correct wiring of the electrode array.
L
Fig. 53.78-Deviation survey
Tools Available. All major service companies use fourarm dipmeter tools. Fig. 53.9 shows a typical dipmeter tool’s mechanical section with the four pads, the electrodes, and the caliper assembly visible. Most of these tools will operate to 20,000 psi and 350°F in holes between 6 and 16 in. in diameter. Different varieties of tools handle low- and high-deviation holes by using different methods of measuring hole deviation and hole azimuth angles. Fig. 53.10 illustrates a monitor log and a computer-answer log.
vertical section.
Oil-Base Muds. Dipmeters run in oil-base muds present a special problem. Because the oil-base mud will not connect the resistivity electrodes to the formation electrically it is necessary to use special knife-edge blade
OTHER
WELL
LOGS
53-9
TABLE
Measured Depth (W
electrodes. These blades mechanically cut into the formation and make contact with the water in the formation. This method does not give the quality of data that is obtained with the conventional system in water-base mud. The reason for this is the considerable amount of noise introduced into the resistivity recording caused by the knife blade sliding along the borehole wall. The better the contact made between the knife edge and the formation, the better the quality of the resistivity measurements. Two important things can be done to improve this contact. 1. Make sure that the knife-edge blade is sharp Demanding new blades is the best way to ensure sharp edges. New blades are also less likely to have electrical insulation problems. 2. Have the logging company dress and adjust their dipmeter tool to apply the maximum arm pressure. This will force the knife edge electrodes into the formation mechanically. This adjustment may be made with different spring mechanisms or by applying greater pad pressure through a hydraulic linkage. Either way this is very important to obtain good resistivity data. Because the oil-base mud dipmeter is a low-usage tool, the service company should be given maximum notice so they can prepare for the job. All special instructions and stipulations should be given at the same time. When recording the log, it should be remembered that the final data can be expected to be only 10 to 20% as good as an ordinary dipmeter. Therefore, it is advisable to consider multiple repeats over critical zones. The data usually will be valid only for general structural use so particular attention should be paid to shale zones. All resistivity curves should have good character, although their similarity will not extend down to small details. A slow or dead curve usually indicates a faulty knife-edge electrode. The orientation curves are unchanged from an ordinary dipmeter so the same comments apply to both. The Computed Dipmeter Log The computation of dipmeter surveys8 requires sophisticated software and a substantial computer. The task requires that the anomalies recorded on the resistivity traces at bed boundaries be correlated and the displacement of each with respect to the others along the borehole be determined. Once this step has been taken then any two pairs of displacements are sufficient to define a plane. Where more than three resistivity curves are recorded, as with most modem dipmeter tools (4-, 6-, and 8-pad tools are in use), then multiple pairs of
35000 40000 45000 500 00 550 00 600 00 65000 70000 75000 800 00 85000 900.00 950 00 1,000 00 1.050 00 1.10000 1.15000 1.200 00 1,250 00 1.300 00 1.35000 1.40000 1.45000 1.50000 1.550 00 1.600 00 1.650.00 1,700.00 1.75000 1,800 1.850 1,900 1.950 2.000 2.050 2.100 2.150 2.200 2,250 2,300
Vertical Depth (W
5000 10000 15000 200 00 25000 300 00
Fig. 53.8~Illustration of dip,strike, and dip azimuth
53.2-DEVIATION
00 00 00 00 00 00 00 00 00 00 00
2.350 00 2,400 00 2.450 2.500 2.550 2,600
00 00 00 00
2.650 2.700 2.750 2.800 2.850 2.900 2.950
00 00 00 00 00 00 00
3.000.00 3 050 00
5000 10000 15000 20000 25000 30000 350.00 40000 450.00 500.00 550.00 599 99 649 99 699 99 749 99 799 99 a49 98 899 98 949 98 993 97 1.049 37 1,099 96 1.14996 I.19995 1,249 94 1,299 94 1.349 93 1.399 92 1.449 91 1.499 90 1.549 1.599 1.649 1.699 1,749 1.799 1.849 1,899 1,949 1.999 2,049
a9 aa 87 86 a4 83 82 a0 79 77 75
2.099 2,149 2.199 2.249 2,299 2,349 2,399 2,449 2.499 2.549 2.599 2.649 2.699 2.749 2.793 2.849
73 71 69 67 65 62 60 57 55 52 49 46 43 40 37 33
2.899 29 2,949 26 2.999 22 3.049 18
HOk Dlrectlon 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 35 95 95 95 95 95 95 95 95 95 95 95 95 95 95 55 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95
SURVEY
Deuatlon Angle (degrees) 004 0 08 011 015 0 19 023 026 0 30 034 038 041 045 0 49 053 057 0 60 0 64 068 0 72 0 75 0 79 083 087 0 90 0 94 0 98 102 106 109 1 13 1 17 121 124 128 132 136 140 143 147 1 51 155 I 58 162 166 170 1 73 1 77 181 185 i a9 192 1 96 2 00 2 04 207 2 11 215 2 19 2 22 2 26 2 30
'Referencedfrom RKB=l5 ft.MSL=Otl Magneticdecl!nation 0.00 degrees went of north
LISTING’
North DUfi
East Dllfl
ClOSUF2
- 0 00 -001 -001 -002
0 02 0 07 0 15 0 26 041 0 59 081 105 1 33 1 64 199 2 36 2 77 322 365 420 4 74
002 007 0 15 0 26 041 0 59 081 1 06 134 165 199 2 37 2 78 323 371 422 4 76
5 32 5 92 6 56 7 23 7 94 868 345 1025 1109
5 34 595 659 726 797 8 71 948 1029 11 13 1200 1291 1384 1482 1582 1686 1793 1903 20 16 21 33 2253 2377 2503 2633 2767
-004 -005 -007 - 0 09 -012 -014 -017 -021 -024 -0 28 -0 32 -037 -041 -0 47 -052 -057 -063 -0 69 -076 -083 -090 -097 -105 -1 12 -1 21 -1 29 i 38 -147 -156 -166 -1 76
11 96 12 86 13 79 14 76 15 76 16 79 1786 1896 2009
-1 86 -196 -207 -218 -230 -241
2125 2245 2368 2494 2623 2756
-2 53 -265 -2 78 -290 -304 -317 -330
28 92 3032 31 74 3320 3463 3622 3777
-344 -359 -373 -388
3936 4099 4264 4433
-403 -418 -434 -450 -466 -482 -499 -5 16 -534
4605 4780 4959 5141 5326 5514 5706 5901 6099
2903 3043 31 86 3333 34.32 3635 3792 39 51 41 14 4280 4450 4623 4799 4978 51 60 5346 5536 5728 5924 61 23
PETROLEUM
53-10
Low Angle AZIMUTH *xxx OF REFERENCE
RELATIVE
BEAAINGx*X~ yDHD’ 4+--L-
HIGH SIDE OF TOOL
fN
-
NO 1 PAD REFERENCE ELECTRODE
High Angle RELATIVE xxx
\ NO 1 PAD
HIGH SIDE.
xx Az,m”th of hole dev,al,on-Clockwise angle fro”. ms3gnetlC North to DHD XLX Rmtive bearmg-Clockwse Electrode
angle from DHO
xxxx Arlmuth 01 Reference Electrode-Clockwse net~c North to Reference Electrode
Fig. 53.9-Four-arm
to Reference
angle from mag-
dipmeter tool.
HANDBOOK
displacements may be chosen and multiple apparent bedding planes defined. The correct choice of the most probable bedding plane is determined by the interpretation logic in the dipmeter program. The correlation of one resistivity curve to another is a more mechanical task and is controlled by the interpreter’s choice of three parameters-the correlation length, the search angle, and the step length-as illustrated in Fig. 53.11. A short interval of one curve is correlated to a second curve at discrete steps throughout a depth range defined by the search angle. At each step a correlation function is evaluated. When the value of the correlation function is determined at each step, then a correlogram can be built and a search made for a maximum value. This maximum indicates the displacement of the curve sector defined on the first curve by the correlation interval from a similar section on the second curve. Successive correlations are continued in the same correlation interval with other curves and then in the next correlation interval and so forth. Once a plane at any point in the well has been defined its orientation relative to vertical and geographic north also must be computed. This requires that the position of the tool in the hole and the deviation and azimuth of the hole itself be known. These data are supplied from the orientation section of the tool. The dipmeter log, as recorded, is not evaluated easily for quality, so an appraisal of the computed log should be included in dipmeter quality control. A computed dipmeter log may be available on location, if a computer logging unit is available, but it is normal to wait for days or even weeks for the results if processing is done at a central computer office. Working with the computed log, look for two distinct defects: undetected problems with the recorded data and problems with the computation. A computed dipmeter should model real-life geology; if it seems not to do that, an investigation is in order. If the problem is in the computation, it normally can be solved by repeating the computation job. Even if the problem is with log measurements, the logging company’s computer experts often can solve it by special handling. Application
NO 1 PAD
ENGINEERING
of Dipmeter
and Directional
Data
Dipmeter Patterns. Once a dipmeter log has been nm and computed then the results have to be interpreted in the light of known geological and geophysical facts. In general dipmeter results are used to find gross structural features, fine stratigraphic features, and true vertical and true stratigraphic thicknesses. The most common method of representing computed dipmeter results is by an “arrow” or “tadpole” plot. A series of special characters is plotted as a function of depth with their origin indicating the dip magnitude and a short line indicating the dip azimuth, as illustrated in Fig. 53.12A. For the purpose of reference the uphole direction on the plot is considered north and the clockwise direction the short line points from its base is the dip azimuth angle. When viewed together as patterns, these dip vectors or L‘tadpoles” can be interpreted in terms of gross geological structure or sedimentary detail as illustrated in Fig. 53.12B.
OTHER
WELL
53-l1
LOGS
RESISTIVITY INCREASES
-
,P
ARROW PLOT
L
Fig.53.10-Dipmeter
monitor log and computed dipmeter log
I 1 I I I I
CORRELATION INTERVAL
Fig. 53.1 l-Dipmeter
SEARCH ANGLE
NEXT CORRELATION INTERVAL
computation terms “correlation interval,” “step,” and “search,”
iu”
53-12
YETHOD 0’
PETROLEUM
OF
PLOTTfNG
a 20’
10’
+
IDIP S
I
L
I
J
EXAMPLE
10”
DIP
HANDBOOK
Folded Structure SP
MAGNlTUDE
ENGINEERING
fCross Section
N. S
/Dip Pan*m
DIRECTION
N45”E
b
/‘4I ie i BLUE
Unconformity SP
1Cross SIctlcn
SE NW
PAT,ERN
interpretation rules showing (a) method of plotting dips and (b)patternsof dips.
Fig. 53.12-Dipmeter
Fig. 53.13 shows three common structures: a folded structure (anticline), an unconformity, and a normal fault. Fig. 53.14 shows three common sedimentary features: a channel cut and fill, a buried bar with shale drape, and current bedding. Other complex patterns may develop, such as those related to: (1) missing and repeat sections (Fig. 53.15A), (2) stratigraphy of continental deposits (Fig. 53. lSB), (3) stratigraphy of continental shelf deltas (Fig. 53. IX), (4) stratigraphy of continental shelf tide/wave-dominated deposits (Figs. 53.15D and E), and (5) continental slope and abyssal environments (Fig. 53.1 SF). Other forms of representing dip data are also used to good effect, such as polar and stereographic plots and azimuth frequency diagrams. One of the main uses for dip data as far as the reservoir engineer is concerned is in computation of reservoir volumes, which require true vertical thickness measurements (TVT). For the geologist a related measure. the true stratigraphic thickness (TST) is of immediate concern. 9-‘3 In the simple case where the wells are vertical and the bedding is horizontal, correlations can be made directly between logs of neighboring wells. Reservoir volume is calculated by multiplying reservoir thickness (directly derived from the logs) by reservoir area (delimited by other means). However, this simple case is exceptional because (1) most reservoirs exist as the result of some structural event or accident, implying some formation dip at least at the reservoir periphery, and (2) most wells deviate to some extent from vertical, intentionally or not. As long
Fig. 53.13-Common
geologic structures and corresponding
dipmeter patterns.
OTHER
WELL
LOGS
Buried Bar with Shale Drape 1040 ?ml?mm c.ma.sadmuw-SE u 4 4 4 4 . --------\ .-L---d 4 4
. ,
Fig. 53.15A-Missing
and repeat sections.
,
Current Bedding @#-msrQnNE-SW Y II
Fig. 53.158-
Fig. 5X14-
Dipmeter patternsin sedimentary features
Stratigraphic interpretation, continentalenvironment.
53-14
PETROLEUM
Fig. 53.15(3- Stratigraphicinterpretation, continental shelf, deltadominated.
rz ,=
ENGINEERING
HANDBOOK
Fig. 53.15D- Stratigraphicinterpretation, continental shelf, tidalwave dominated.
I I D,,l “EFLEC,s,““cr”““‘
D,,
Fig. 53.15E- Stratigraphicinterpretation, continental shelf, tidalwave dominated.
Fig. 53,15F- Continentalslope and abyssal environments.
OTHER
WELL
LOGS
as dips and deviations do not exceed a few degrees, the simple vertical-horizontal case is approximated closely enough not to need corrections. But when deviations and dips exceed about 10 degrees, corrections are needed because apparent formation thicknesses measured on logs are greater than true stratigraphic thicknesses by different amounts in different wells. This adds to the difficulty of well-to-well log correlation. Also, if wells are deviated from vertical, and if formations have substantial dip, apparent thicknesses differ from the vertical thicknesses needed for reservoir volume calculation, and must be corrected. To achieve these corrections in a convenient manner, modem data processing affords three different computed log products: the true vertical depth (TVD), TST, and TVT plots. Proper interpretation of these plots requires considerable caution and may be quite difficult. Common Principles of TVD, TST, and TVT Plots. Figs. 53.16 through 53.18 illustrate the principles of thickness transformations. Formation parameters recorded by logging tools are reproduced without alteration, but their depths are altered to suit respective purposes. Depths should be thought of as summations of overlying formation thicknesses. Two methods exist for computation of altered depths: (1) common surj&e point, which assumes a hole drilled from the same surface point or formation top with a different course, and (2) common subsur&ace point, which assumes a hole drilled either vertically, or normal to the bed dip, from some point in the actual well course, such as a formation top, or a point of formation dip change. Depths may be reset arbitrarily at the common point. In this approach it is set to zero, thus representing only thickness as counted down from the common point. Z’VDPlot. This plot ignores formation dip and corrects for well deviation only. Thus, it represents formations as they would look in a vertically drilled well, provided the formations had zero dip. It is useful in areas of directional drilling where dip is low, for well-to-well correlations, and for reservoir volume calculations. It usually is run only in the common surface point mode. TST Plot. This plot accounts for formation dip, and requires knowledge of true well course, whether vertical or not. It displays formations as though the well had been drilled perpendicular to them. If a change of dip occurs, an equal and opposite change of deviation is assumed. If only one dip is present, the plot represents the logs that would have been obtained if the well had been drilled at the same location perpendicular to that dip. If more than one dip is present, the interpretation becomes At each dip change, some more complicated. stratigraphic column must either disappear, or thin, or thicken, or even repeat itself. 17/T Plot. This plot is closely related to the TST, and as such accounts for both well deviation and formation dip. It shows formation thickness as though the well had been drilled vertically through the dipping beds. Evidently, a TVT in a vertical hole would be identical to the original log. The TVT is meant to be used for reservoir volume calculations from deviated hole logs. Reductions in Special Cases. If the well is vertical and the formations are horizontal, all three transformed logs would be identical to the original log, and the processing
53-15
Frue Vertical Depths
Fig. 53.16-Principle of true vertical depth (TVD).
Fig. 53.17-Principle of true stratigraphic thickness(TST).
Fig. 53.16-Principle of true vertical thickness(TVT).
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53-16
would be a waste of computer time. If the well is deviated and the formations arc horizontal, the TST and the TVT are identical to the TVD, and running the latter is sufficient. If the well is vertical and the formations dip, the TVD and TVT plots would be wasted computer time, but the TST may be useful in well-to-well correlations. If the well is drilled perpendicular to the formation dip (as it often tends to be in hard rocks in particular) the TST would be a waste of computer time, but the TVT is needed for reservoir calculations, and the TVD may be of use if deviation is pronounced. Algorithms. The algorithms used for computing the TVD, TST, and TVT have been covered well in the literature. I4 Any implementation of these algorithms for computer applications should be approached with caution. Many programming languages differ in their treatment of trigonometric functions for angles exceeding 90”. Another area requiring care is in the matter of precision. When depth data are processed, a repetitive accumulation of depth increments is made. As many as IO4 or more additions must be made in a normal well. Thus the precision of each increment must be at least one part in IO6 or better. Depending on the computer used (16 bit, 32 bit, etc.) the programming of these algorithms should demand appropriate precision. By way of summary, all three plots perform valuable functions, but all three may be misleading if not used with the proper caution, in particular with respect to absolute depths. 1, The TVD is incorrect in both formation thicknesses and in absolute depths if formations have appreciable dip. 2. The TST is always correct in formation thicknesses. It should be run in the common subsurface point mode. If changes of dips are present, it should reset the subsurface point at each change of dip and make independent plots through each dip zone. This resetting may be made automatically if the program allows it, and manually otherwise. 3, The TVT may produce apparent thicknesses greater than measured thicknesses. Such thicknesses may be fittitious when beds are truncated in their vertical extension by unconformities or faults. It should be run in independent sections for each change of dip, in the common subsurface point mode, as for the TST.
Fig. 53.19-A typical borehole.
ENGINEERING
HANDBOOK
Caliper Logs Introduction The caliper log measures the diameter of the borehole. The first caliper logs were developed to determine borehole size in holes shot with nitroglycerin. These early logs showed large variations in hole size even in the portions of the hole that had not been shot. This illustrated the need for the caliper log over the entire hole. Methods of Recording Several types of caliper are currently in use. One type consists of three or four spring-driven arms, which contact the wall of the borehole. The instrument is lowered to the total depth (TD), and the arms are released either mechanically or electrically. The spring tension against the arms centers the tool in the well. The arms move in and out with the change in wellbore diameter. The arm motion is transmitted to a rheostat so that change in the resistance of an electric circuit is proportional to the hole diameter. The borehole diameter is recorded at the surface by measuring the potential across this resistance. Another instrument uses three flexible springs, which contact the wall of the borehole. These springs are connected to a plunger that moves up or down as the springs expand or contract with changes in borehole diameter. The plunger passes through two coils. When an alternating current is passed through one coil. an electromotive force (EMF) is induced in the other coil. The amount of this induced EMF is a function of the plunger position and is proportional to borehole diameter. Either of the preceding instruments may be adjusted so that they will record borehole area rather than hole diameter. If the caliper log is used to determine hole volume, area should be recorded on a linear scale. If the caliper log is used to determine hole configuration, the hole diameter is recorded on a linear scale. A third type of caliper log is the microcaliper, which is discussed in connection with the electrical-log microdevices. This instrument uses two pads rather than arms or flexible springs. Hole diameter is determined by the movement of these pads, which are held against the borehole wall by springs. Typical Borehole Configuration A schematic of a typical borehole is shown in Fig. 53.19. As illustrated in this figure, some formations cave considerably, causing enlarged holes. Other formations do not cave, and because of the presence of mudcake, the hole size actually may be reduced to less than bit size. Although not illustrated in Fig. 53.19. some fotmations may swell, causing reduction in hole size. The primary cause of formation caving is the action of the drilling fluid. Action of the bit and the drillpipe also have an effect. Most drilling muds are composed primarily of water. The chemical action of this water on shales (hydration of the shales) causes many shales to disintegrate and slough into the hole. The amount and rate of this sloughing depend on the nature of the mud and shale. Other shales (heaving shales) swell rather than disintegrate. If a freshwater mud is used to drill a salt section, it will dissolve salt until the mud becomes salt-saturated. The drilling fluid does not react with formations such as
OTHER
WELL
LOGS
53-17
limestone, dolomite, and sandstone. However, if those formations are permeable, a mudcake will be formed, as illustrated in Fig. 53.19. This mudcake forms rapidly. The character (density and thickness) of the mudcake varies with the mud used to drill the well. Of course, thickness of the mudcake is limited by erosion of the drilling fluid while circulating. In some areas the shallow portion of the hole is drilled with water. If loosely cemented sands are encountered, they may cave under this condition. The action of the bit is probably not too important. But if a thin sand is surrounded by shales that have caved, the bit probably knocks off part of the sand ledge with each round trip. Action of the-drillpipe against the side of the hole causes some enlargement even in sandstones and limestone. Usually this enlargement is not great enough to affect hole volume appreciably, but it may cause the drillpipe to become differentially pressure stuck, necessitating a fishing job. Formation wear by the drillpipe will cause the hole to be noncylindrical, in which case a four-arm caliper will display the long and short axes of the hole.
Interpretation
and Application
of Caliper Logs
Caliper logs usually are recorded on vertical scales from 1 in.= 100 ft to 5 in.= 100 ft. The horizontal scale is selected to show a detail picture of hole diameter and is usually on the order of 1 in. =4 in. Because of the difference in scales, it is easy to get the impression from caliper logs that tremendous cavities are created. When plotted on the same horizontal and vertical scales, it is evident that the normal borehole is quite regular. This should be remembered when using the caliper log. The primary uses of the caliper log are: (1) to compute hole volume to determine the amount of cement needed to fill up to a certain depth, (2) to determine hole diameter accurately for use in interpreting other logs, and (3) to locate permeable zones as evidenced by the presence of a filter cake. Other applications of the caliper log include proper location of casing centralizers, and packer seats for openhole drillstem tests. Caliper logs are also available in conjunction with hole deviation and hole azimuth measurements, in which case the log is referred to as a borehole geometry log. Fig. 53.20 is an example of a borehole geometry log using a standard three-track presentation. The borehole orientation is displayed in Track 1, while the two independent orthogonal caliper readings are recorded in Track 2 with a standard scaling. The caliper data are also available in Track 3 but with a reduced sensitivity. Together with the bit size and future casing size, this visual display, enhanced by the shading between the calipers and the bit size, quickly gives a clear impression of the borehole shape. Within the depth track the total hole volume integration is recorded along the edge of Track 1, and the cement volume (the difference between the total hole volume and the future casing volume) is presented along the edge of Track 2.
i
Fig. 53.20- Borehole geometry log.
Casing Inspection Logs Introduction Inspection of the mechanical state of the completion string is an important aspect of production logging. Many production (or injection) problems can be traced back to mechanical damage to, or corrosion of, the completion string. A number of casing inspection methods are available including: (1) multifingered caliper logs, (2) electrical potential logs, (3) electromagnetic inspection devices, and (4) borehole televiewers or borehole TV. Of these the majority measure the extent to which corrosion has taken place. Only the electrical potential log may indicate where corrosion is currently occurring. With the exception of the caliper logs, all the devices require that the tubing be pulled before running the survey, since most are designed to inspect casing rather than tubing, and all are large-diameter tools. Caliper Logs for Tubing
and Casing Inspection
Various arrangements of caliper mechanisms ate available to gauge the internal shape of a casing or tubing string. Fig. 53.21 illustrates three such tools. Table 53.3 lists the various sizes available, their respective number of feelers, and the appropriate casing size. Tubing Profile Calipers. Tubing profile calipers will determine the extent of wear and corrosion, and will detect holes in the tubing string-all in a single run into the well. The large number of feelers on each size of caliper ensures detection of even very small irregularities in the tubing wall. In pumping wells, the tubing caliper log may be run by one person and there is no need for a pulling unit crew to be present. A “pull sheet” showing the maximum percentage of wall loss of every joint of tubing in the well may be prepared. Before the well is pulled, a program of rearranging the tubing string can be provided. Moving partially worn joints nearer the surface and discarding thin-wall joints substantially prolongs the effective life of tubing strings and reduces pulling costs in pumping wells. In flowing or gas lift wells, the tubing profile caliper provides an economical method to check
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53-I8
TABLE
ENGINEERING
HANDBOOK
53.3-TUBING AND CASING PROFILE CALIPERS
Sizes of Tubing ProfileCalipers Tool Diameter (in.) 1% 1’/2 1% 2% 6
2’%6 3’h
Number of Feelers 20 20 26 32 44 44
OD (in.) 2
wl6
2% 27/s 3% 4
Sizes of Casing ProfileCalipers 3% 5% 7v? 7% 8’/4 9% 1 IS/l6 13% 17%
40 64 64 64 64 64 64 64 64
6 6% to 7510 8% lo 9 9% 10% 11% 133/e 16 20
4% t0
periodically for corrosion damage, to monitor the effectiveness of a corrosion inhibitor program, or to detect and remove damaged tubing joints when working over a well. Split Detector. This is an accessory tool that may be run in combination with the tubing profile caliper. This tool, functioning much like a magnetic collar locator, is designed to detect and log vertical splits or hairline cracks in the tubing that might be difficult to locate with the profile caliper. In practice, the split detector is used to log down the tubing, and the profile caliper to log up the tubing. This gives a complete inspection for wall thickness and splits in one run of the cable in the well.
Tubing
Profile
Caliper
Casing
Pmfrle
Caliper
Fig. 53.21-Casing
and tubing profile calipertools
Casing Profile Calipers. Casing profile calipers are available to log 4%in.- through 20-in.-OD casing. The tool is especially valuable where drilling operations have been carried on for an extended period of time through a string of casing. The determination of casing wear is of great importance when deciding if a liner can be hung safely, or if a full production string is required. In producing wells, the casing profile caliper will locate holes or areas of corrosion that may require remedial work. The tool is also valuable when abandoning wells because it permits grading of casing to be salvaged before it is pulled. Casing Minimum-ID Calipers. The minimum-ID caliper can pass through and accurately measure restrictions as small as 3% in. in casing with a nominal ID up to 13% in. This log is of particular value in determining areas of collapsed or deformed casing, identifying casing-weight change intervals, or detecting parted casing. Examples of these logs are given in Fig. 53.22.
OTHER
WELL
LOGS
TUBING
53-19
PROFILE
CASING
CALIPER
PROFILE
CASING
CALIPER
MINIMUM
I.D.
CALIPER
r
Fig. 53.22-Tubing
Electrical
Potential
Logs
An electrical potential log determines the galvanic current flow entering or leaving the casing. This will indicate not only where corrosion is taking place and the amount of iron being lost, but also where cathodic protection will be effective. The magnitude and direction of the current within and external to the casing is derived mathematically from electrical potential measurements made at fixed intervals throughout the casing string. To achieve reliable results from this kind of survey, the borehole fluid must be an electrical insulator (i.e., the hole must be either empty or filled with oil or gas). Mud or other aqueous solutions will provide a “short” that invalidates the measurements. The log itself is a recording vs. depth of the small galvanic voltages detected. Fig. 53.23 illustrates such a log with three different runs recorded, each with a differing level of cathodic protection applied to the casing. Figs. 53.24 and 53.25 show an interpretation of casing potential profile logs nm both with and without cathodic
and casing profile logs.
protection. Note that in Fig. 53.25 the metal loss has been reduced to practically zero by the application of an appropriate cathodic protection. Electromagnetic
Devices
The most commonly used casing corrosion inspection tools are of the electromagnetic type. They come in two versions, those that attempt to measure the remaining metal thickness in a casing string I5 and those that try to detect defects in the inner or outer wall of the casing. I6 Although frequently run together, these tools will be discussed separately. Electromagnetic Thickness Tools. The electromagnetic thickness tools are available under a variety of trade names such as ETT (Schlumberger), Magnelog (Dresser), and Electronic Casing Caliper Log (McCullough). They operate in a manner similar to openhole induction tools. Each consists of a transmitter coil and a receiver coil. An AC is sent through the transmitter coil.
53-20
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This sets up an alternating
ENGINEERING
magnetic
HANDBOOK
field, which
in-
teracts both with the casing and the receiver coil (see
Fig. 53.26). The coils are spaced about three casing diameters apart to ensure that the flux lines sensed by the receiver coil are those that have passed through the casing. The signal induced in the receiver coil will be out of phase with the transmitted signal. In general the phase difference is controlled by the thickness of the casing wall. Thus the raw log measurement is one of phase lag in degrees and the log is scaled in degrees. Fig. 53.27 illustrates an ETT log in severely corroded casing. Note that an increasing thickness corresponds to an increase in the phase shift angle and vice-versa. Some presentations of this log show a resealing in terms of actual pipe thickness. This requires that the operator make some calibration readings in the type of casing present in the well. It is quite common to see quite large differences in thickness between adjacent stands resulting from a number of variables, such as the drift diameter of the pipe, the weight per foot, the magnetic relative permeability of the steel used, etc. The ETT-type tool is good at finding vertical splits in pipe, since the magnetic flux lines pass perpendicular to the casing wall. A horizontal circumferential anomaly is less well defined.
Fig. 53.23-Casing
potentialprofile.
Fig. 53.24-Casing potential profile analysis-withoutcathodic protection.
Eddy Current and Flux leakage Tools (Pipe Analysis Log). Another closely related measurement uses a slightly different technique and forms the basis of the Pipe Analysis Log (PAL). I6 Two electromagnetic measurements are of interest in the context of the pipe analysis tool-magnetic flux leakage and eddy current distortion. ”
Fig. 53.25-Casing
potentialproflle-withcathodic protection.
OTHER
WELL
LOGS
53-21
I;2ux leakage. If the poles of a magnet are positioned near a sheet of steel, magnetic flux will flow through the sheet (Fig. 53.28). So long as the metal has no flaws the flux lines will be parallel to the surface. However, at the location of a cavity either on the surface of the sheet or inside it, the uniform flux pattern will be distorted. The flux lines will move away from the surface of the steel at the location of the anomaly, an effect known as flux leakage. The amount of flux distortion will depend on the size of the defect. If a coil is moved at a constant speed along the direction of magnetic flux parallel to the metal sheet, a voltage will be induced in the coil as it passes through the area of flux leakage. The larger the anomaly, the greater the flux leakage and, therefore, the greater the voltage. The magnetic flux is distorted on both faces of the sheet, regardless of the location of the
Fig. 53.26-Electromagnetic thicknesstool
PHASE SHIFT 3M
Fig. 53.27-Electromagnetic thickness log.
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53-22
Magnetic flux
1
Eddy Currents. When relatively high frequency AC is applied to a coil close to a sheet of steel, the resulting magnetic field induces eddy currents in the steel (Fig. 53.29). These eddy currents, in turn, produce a magnetic field that tends to cancel the original field, and the total magnetic field is the vector sum of the two fields. A measure voltage would be induced in a sensor (receiver) coil situated in the magnetic field. The generation of eddy currents is, at relatively high frequencies, a nearsurface effect. Therefore, if the surface of the steel adjacent to the coil is damaged then the magnitude of the eddy currents will be reduced, and, consequently, the total magnetic field will be increased. This will result in a variation in the sensor coil voltage. A flaw in the sheet of metal on the surface away from the coils will not be detected and, depending on its distance from the surface, a cavity within the sheet will not influence the eddy currents either.
J
FL
Flux f leakage
1 I
Fig. 53.28-Magnetic
Casing H
HANDBOOK
defect, and therefore the coil needs to be moved along only one surface to survey the sheet completely. Since the coil must be moved through a changing magnetic flux to produce a voltage, no signal is generated when it is moved parallel to the surface of an undamaged sheet of steel _
Sensor coil
/iagnet lole piece /’
ENGINEERING
.l
fluxleakage principle.
Tool Principle. The measuring sonde consists of an iron core with the pole pieces of an electromagnet at each end, and 12 sensor pads in two arrays between the pole pieces (Fig. 53.30). The two arrays are offset radially to ensure complete coverage of the inner surface of the casing. Each of the pads contains a transmitting coil (for the eddy current measurement) and two sensor coils wound in opposite directions (for both the flux leakage and eddy current measurements). The two sensor coils are wound in opposite directions so that for both measurements
Transmlttcr coil
Fig. 53.29-Eddy
currentprinciple
OTHER
WELL
53-23
LOGS
there is zero voltage as long as no anomaly exists, but a signal will be produced when the quality of the casing is different below the two coils. The same sensor coils can be used for both measurements since two distinct frequencies are involved. A frequency of 2 kHz is used for the eddy current measurement, giving a depth of investigation of about 1 mm. The sensor pads are mounted on springs so that they are held in contact with the casing, facilitated through centralization of the sonde. Various sizes of magnet pole pieces are available and are selected according to the casing ID to optimize the signal strength for the flux leakage measurement. Six measurements of flux leakage and eddy current distortion are made on each array, and the maximum signal from each array is sent uphole to the surface instrumentation. Four signals, the eddy current and flux leakage data from the two arrays, are recorded. The flux leakage data correspond to anomalies located anywhere in the casing, while eddy current distortion occurs only at the inside wall of the casing. The standard presentation of the measurements is as shown in Fig. 53.31, with the data from the two arrays displayed in Tracks 2 and 3. Enhanced data arc displayed in Track 1, making any anomalies more obvious. Interpretation. The measurements are generally suitable only for qualitative interpretation. This is because any voltages induced in the sensor coils depend not only on the size of any flaws in the casing, but also on the magnetic permeability of the casing, the logging speed, and the abruptness of a defect. The measurement, therefore, is used primarily to locate the presence of small defects in the casing, such as pits and holes. Defects such as gradual decreasing of the wall thickness cannot be detected. To get a complete picture of the state of the casing the electromagnetic thickness tool also should be used to measure the casing wall thickness, since the PAT device will give zero signal in the two extremes of no casing and perfect casing (except at the collars). Two sets of data are recorded, one set influenced by defects occurring anywhere in the casing, and the other by faults on the inner surface. By examining the log, therefore, it can be inferred whether the casing is damaged on the inner or outer wall, assuming that there is no defect within the casing. Although the magnetic flux bulges away from both sides of the casing at the location of a defect, the effect is greater on the side of the flaw, hence for the flux leakage measurement, smaller defects can be detected on the inner surface than on the outer surface. Because of the overlapping configuration of the two-pad arrays all of the inner surface of the casing is surveyed, but there is a casing-diameter-dependent defect size below which the flaw will be seen by only one array, and above which it will be seen by both arrays. The eddy current measurements are not able to detect flaws smaller than about 0.39-in. diameter, while the flux leakage limit is somewhat lower (0.25 in.). This means that if an anomaly of less than %-in. diameter is present it cannot be determined whether it is on the inner or outer surface. If a deflection is noted on the eddy current measurement but not on the flux measurement it is
6 ARM CENTRALIZER
MAGNET
UPPER PAD ARRAY
LOWER PAD ARRAY
MAGNET
6 ARM C ENTRALIZER
Fig. 53.30-The pipe analysis tool
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53-24
ENHANCED
T
CURVES
LOWER
ARRAY
1 I
/
I
UPPER
Inner wall
Total wall /
rrl I;IFI
ENGINEERING
j I I
lnner wall
i I
r
HANDBOOK
ARRAY Total wall
I I i
/
/
iI4 z Z-=.-_ .-_-- .
I ---= ----
!
COI Se\ ‘erc Surface
Fig. 53.31-The
pipe analysis log In severely corroded casing.
OTHER WELL LOGS
LOWER Total wall
ARRAY
UPPER
I
inner wall
Inner wall
\-. lz-.
Fig. 53.32-Pipe
I
.,
,i _-
analysis log over a perforated section of casing.
-
-
ARRAY Total wall
53-26
PETROLEUM
assumed that the defect on the inner wall is less than 1 mm deep, and also usually can be ignored. In addition, events can be seen on the flux leakage readings that are not caused by casing damage but are a result of the presence of localized magnetization in the casing. This is one reason why a reference PAT survey should be run in new casing, so that a time-lapse technique can be applied to determine the casing damage. The example of Fig. 53.32 includes sections of perforated casing (798 to 805 m, 807 to 819 m and 821 to 830 m), and there is a clear indication of damaged and undamaged casing. The flux leakage measurement (total wall) is responding strongly through the perforated intervals, the eddy current curve less so. This is probably a result of the diameter of the perforations being fairly close to the detection limit of the eddy current measurement. In the upper section the tool response is much lower, indicating a certain amount of corrosion on both surfaces of the casing, but probably nothing major. The large deflections occurring on all the curves are caused by the casing collars.
Casing Collar-Locator
Log
The collar locator is used to locate casing collars, usually in conjunction with another cased-hole service such as a nuclear log or a perforating gun. Perhaps its most common use is in precisely locating perforating points. To do this the collar locator is run with a nuclear log (either the gamma-ray or neutron log) after the casing is set. This survey accurately positions casing collar in reference to the nuclear log. By correlating the nuclear log with logs run in an open hole, casing collars can be positioned accurately with reference to the openhole logs. The collar locator is then run with the perforating gun. The collars adjacent to the desired perforating interval are located and the desired interval perforated using the casing collars as reference points. Use of the collar locator makes it possible to locate perforations within a few inches of the desired interval. Various types of collar locators are now in use. Some of the collar locators are sensitive enough to locate old perforations in casing. The collar locator also can be used to locate the casing shoe in openhole completions.
ENGINEERING
HANDBOOK
References I. Kamp, A.W.: “Downhole Telemetry From the User’s Point of View,” J. Pet. Tech. (Oct. 1983) 1792-96. 2. Grosso, D.S., Raynal, J.C., and Radar. D.: “Report on MWD Experimental Downhole Sensors,” J. Per. Tech. (May 1983) 899-904, 3. “Measurements 4
5
6
7. 8.
9.
IO.
II.
12.
13.
14.
15.
16.
17.
While Drilling (M.W.D.) Technical Specifications,” Schlumberger Well Services. Houston. Hodgson, H. and Gemado, S.G.: “Computerized Well Planning for Directional Wells,” paper SPE 12071 presented at the 1983 SPE Annual Technical Conference and Exhibition, San Francisco, Oct. 3-6. Scott, A.C. and Wright, J.W.: “A New Generation Directional Survey System Using Continuous Fyrocompassmg Techmques,” paper SPE 11169 presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 29-Oct. 2. Walstrom, J.E., Harvey, R.P.. and Eddy, H.D.: “A Comparison of Various Directional Survey Methods and an Approach to Model Error Analysis.” J. Per. Tech. (Aug. 1972) 935-43. “Dipmeter- Interpretation-Volume-l-Fundamentals,” SchlumIberger Ltd., New York City (1981) 8. 10. 53. Bateman, R.M. and Konen, C.E.: “The Log Analyst and the Programmable Pocket Calculator-Part Ill-Dipmeter ComputaIlion.” The Log Anal~w (Jan.-Feb. 1978) 19. No. I, 3-l 1. IBateman, R.M. and Hepp, V R.: “Application of True Vertical Depth, True Stratigraphic Thickness and True Vertical Thickness Log Displays,” paper presented at the 1981 SPWLA Annual Logging Symposium. Pennbaker. P.E.: “Vertical Net Sandstone Determination for lsopach Mapping of Hydrocarbon Re.servoin.” Bull., AAPG (Aug. 1972) 53, No. 8, 1520-29. Hepp, V.R.: “Vertical Net Sandstone Determination for lsopach Mapping of Hydrocatin Reservoirs-Dixussmn.” Bull., AAPG (1973) 57, 1784-87. Holt. O.R., Schoonovers, L.G., and Wlchmann. P.A.: “True Vertical Depth, True Vertical Thickness, and True Stratigraphic Thickness Logs,” Truns., SPWLA Logging Symposium (1977) paper Y. Peveraro, R.: “Vertical Depth CorrectIon Methods for Deviation Survey and Well Log Interpretation,” Truns., SPWLA European Symposium, London (1979) paper P. Bateman. R.M. and Konen, C.E.: “The Log Analyst and the Programmable Pocket Calculator-Part VI-Finding True Straw graphic Thickness and True Vertical Thickness of Dipping Beds Cut by DirectIonal Wells.” 771~Log Aria/w (March-April 1979). Cuthbert, J.F. and Johnson, W.M. Jr., “New Casing lnspectmn Log,” paper SPE 5090 presented at the 1974 SPE Annual Meeting, Houston, Oct. 6-9. Illiyan.-I.S., Cotton, W.J. Jr.. and Brown, G.A.: “Test Resultsof a Corrosion Logging Technique Using Electromagnetic Thickness and Pipe Analysis Logging -Tools,“-J. Per. Tkh. (April 1983) 801-08. “Well Evaluation Development-Continental Europe.” Schlumberger Ltd., New York City (1982).
Chapter 54
Acidizing A.W. Coulter Jr., A.R. Hendrickson, S.J. Martine2.u. of
Dwell-Schlumberger Dowell-Schlumberger Tulsa
*
Introduction The use of acids to stimulate or to improve oil production from carbonate reservoirs was first attempted in 1895. Patents covering the use of both hydrochloric and sulfuric acids for this purpose were issued at that time. Although several “well treatments” were conducted, the process failed to arouse general interest because of severe corrosion of well casing and other metal equipment, The next attempts to use acid occurred between 1925 and 1930. These consisted of using hydrochloric acid (HCl) to dissolve scale in wells in the Glenpool field of Oklahoma and to increase production from the Jefferson Limestone (Devonian) in Kentucky. None of these efforts were successful and “acidizing” once again was abandoned. The discovery of arsenic inhibitors, which allowed HCl to react with the formation rock without seriously damaging the metal well equipment, revived interest in oilwell acidizing in 1932. At that time, Pure Oil Co. and Dow Chemical Co. used these inhibitors with HCl to treat a well producing from a limestone formation in Isabella County, MI. Results of this treatment were outstanding. When similar treatments in neighboring wells produced even more spectacular results, the acidizing industry was born. Throughout the years following those early treatments, the acidizing industry has grown to one using hundreds of millions of gallons of acid applied in tens of thousands of wells each year. Technology has developed with increasing rapidity, and many changes and innovations have been made to improve the effectiveness of acidizing treatments. Because of new techniques of application and development of additives to alter the characteristics of the acid itself, acidizing has become a highly skilled science. A knowledge of available materials, chemical reactions ‘Authors of the OrigInal chapter on this topic I” the 1962 editlon Included th!s aulhor (deceased). P E. Rlzgerald. and Harold E Staadt
at treating and well conditions, reservoir properties, and rock characteristics are required to design an effective and efficient acidizing treatment. Since it is beyond the scope of this text to cover all aspects of acidizing in detail, this discussion will be limited to a general description of materials, techniques, and design considerations. A bibliography is provided for those requiring a more detailed discussion of a particular subject. Also, the major well stimulation companies providing acidizing services offer literature and technical assistance for problem analysis and treatment design.
General Principles The primary purpose of any acidizing treatment is to dissolve either the formation rock or materials, natural or induced, within the pore spaces of the rock. Originally, acidizing was applied to carbonate formations to dissolve the rock itself. Over a period of time, special acid formulations were developed for use in sandstone formations to remove damaging materials induced by drilling or completion fluids or by production practices. There are two primary requirements that an acid must meet to be acceptable as a treating fluid: (1) it must react with carbonates or other minerals to form soluble products, and (2) it must be capable of being inhibited to prevent excessive reaction with metal goods in the well. Other important considerations are availability, cost, and safety in handling. While there are many formulations available, only four major types of acid have found extensive application in well treatments: hydrochloric, hydrofluoric, acetic, and formic acids. Hydrochloric
Acid (HCI)
An aqeuous solution of HCl is most commonly used for acidizing treatments, for reasons of economy and because it leaves no insoluble reaction product. When HCl is
PETROLEUM
54-2
I
In
3500
T I
3000
/ 16
ENGINEERING
HANDBOOK
pumped into a limestone formation, a chemical reaction takes place, producing calcium chloride, CO*, and water. This reaction is represented by the following equation:
I4 12 IO n b 4 2 0
0
4 STRENGTH
n
I2 OF ACID,
16
20
PERCENT
BY
24 WEIGHT
Fig. 54.1-Solution of limestone in acid.
TABLE %
HCI
1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 11.00 12.00 13.00 14.00 15.00 16.00 17.00 18.00 19.00 20.00 21.00 22.00 23.00 24.00 25.00 26.00 27.00 28.00 29.00 30.00 31.00 32.00 33.00 34.00 35.00 36.00 37.00 38.00 39.00 40.00 41.00
54.1~-HYDROCHLORIC
ACID DENSITY
SpecificGravity' "Baume** 1.0048 1.0097 1.0147 1.0197 1.0248 1.0299 1.0350 1.0402 1.0447 1.0500 1.0550 1.0600 1.0646 1.0702 1.0749 1.0801 1.0849 1.0902 1.0952 1.1002 1.1057 1.1108 1.1159 1.1214 1.1261 1.1310 1.1368 1.1422 1.1471 1.1526 1.1577 1.1628 1.1680 1.1727 1.1779 1.1827 1.1880 1.1924 1.1963 1.2008 1.2053
145
0.7 1.4 2.1 2.8 3.5 4.2 4.9 5.6 8.2 6.9 7.6 8.2 8.8 9.5 10.1 10.8 11.4 12.0 12.6 13.2 13.9 14.5 15.1 15.7 16.3 16.9 17.5 18.0 18.6 19.2 19.8 20.3 20.9 21.4 21.9 22.4 22.9 23.4 23.8 24.3 24.7
lbmlgal 8.377 8.418 8.460 8.501 8.544 8.586 8.629 8.672 8.710 8.754 8 796 8.837 8.876 8.922 8.962 9.006 9.045 9.089 9.132 9.171 9.218 9.261 9.303 9.349 9.385 9.433 9.478 9.523 9.563 9.609 9.663 9.694 9.738 9.777 9.820 9.860 9.924 9.941 9.974 10.011 10.049
AT 6O“F psilft depth 0.4351 0.4372 0.4392 0.4415 0.4437 0.4459 0.4482 0.4504 0.4524 0.4547 0.4568 0.4590 0.4610 0.4634 0.4654 0.4677 0.4698 0.4721 0.4743 0.4764 0.4788 0.4810 0.4832 0.4855 0.4876 0.4899 0.4922 0.4946 0.4967 0.4991 0.5012 0.5035 0.5057 0.5078 0.5100 0.5121 0.5144 0.5163 0.5180 0.5199 0.5219
One thousand gallons of 15% HCI will dissolve approximately 10.8 cu ft (1,840 lbm) of limestone. It will liberate approximately 7,000 cu ft of CO1 , measured at atmospheric conditions, and produce 2,042.4 lbm of calcium chloride. This salt is dissolved in the original water of the acid solution, plus 39.75 gal of water formed during the reaction. The specific gravity of this solution will be 1.181 (20.4% calcium chloride). While 15 wt% HCI has been the most commonly used, concentrations of 20 and 28% have become extremely popular over the past 2 decades. Regardless of the acid strength used, the reaction is the same and equivalent amounts of carbonate rock are dissolved. For example, 10,000 gal of 3% HCl solution will dissolve the same amount of rock as 1,000 gal of 28% HCl. Fig. 54.1 shows the effect of acid concentration on the amount of limestone dissolved. The main differences between the two solutions are their reaction rates (or spending times) and their physical volumes. Although lower concentrations of acid have greater equivalent volumes, their reaction times and depth of penetration into the reservoir, from the wellbore, are considerably less than those of the higher-strength solutions. Reaction rates and penetration will be discussed later. Similar reactions occur when dolomite or impure limestone is treated with HCI. Dolomitic lime contains a large percentage of magnesium combined as calcium magnesium carbonate. Although it reacts more slowly, this mineral also dissolves in HCl, and the resulting magnesium chloride is soluble in the spent acid. Other impurities occurring in limestone and dolomite are often insoluble in acid, and if appreciable percentages of such components are present, special additives must be included in the acid solution to ensure their removal. HCl ordinarily is manufactured in concentrations of 32 to 36 wt% HCl and is diluted at service company stations to 15, 20, or 28% for field use. The concentrated acid, the various chemical additives, and water are mixed in the tank truck used to haul the acid to the wellsite. Table 54.1 lists the weights of various concentrations of HCI. These data are useful in calculating mixing proportions for acid dilution, using the following equation:
vda
cda
7 da
vl-0 = Cca(HCI)Yca '
where V/da = cdd = ?'du = V,, = Cccr(HCI)= ycO =
final volume of dilute acid, desired concentration of dilute acid, specific gravity of dilute acid, volume of concentrated acid required, percent of HCI in concentrated acid, and specific gravity of concentrated acid.
Approximate proportions of concentrated acid and water required for dilution are shown in Fig. 54.2.
54-3
ACIDIZING
Determination of acid strength can be estimated in the field using either a hydrometer or a field titration kit. The accuracy of hydrometer readings depends on the care and technique used by the field engineer. Both the hydrometer and the glass cylinder in which the test is made should be free from oil or dirt. The spindle should float freely in the acid, and all readings should be made at the lowest level of the acid meniscus. The temperature of the acid sample should be taken and the hydrometer reading corrected to 60°F. Determination of acid strength by titration is simplified by the use of 0.59 N standard sodium hydroxide solution. If a 2-mL sample of the acid is titrated with this standard solution to a methyl orange end point, the burette reading (milliliters of sodium hydroxide used) will be equal to the acid strength (percent HCI). Acetic and Formic
FORMULA FOR CONCENTRATION:
MIXING
ACID
IN ANY
DESIRED
VOLUME OF STRONG = (VOL OF WEAK) (%WEAK) (SF? GR.OF WEAK) (=&OF STRONG) (SF’. GR.OF STRONG) GALLONS OFCONCENTRATED 7 HYDROCHLORIC ACID TO MAKE OF DILUTE ACID t 1,000 GALLONS
-8
- 32 - 30
-9
-28
- IO -II $? -12
1
-13 0
&
-14 2 I5 a
Acids
-16
Acetic acid (CH3COOH) and formic acid (HCOOH) are weakly ionized, slowly reacting, organic acids. They are used much less frequently than HCI and are suitable primarily for wells with high bottomhole temperatures (BHT’s above 250°F) or where prolonged reaction times are desired. The reaction of these acids with limestone is described by the following equation:
z
-17 0
-189 E -2om
3 s-23 ’ 2: Q-20 2-I; -17 k-16 Z-15 =-I4 - 13
-2&
k-12
2, EKBG -282
2HOrg+CaCOj
+CaOrgz
HAc is available in concentrations up to 100% as glacial HAc. while HCOOH is available in 70 to 90% concentrations. For field use, HAc solutions normally are diluted to I5 % or less. Above this concentration, one of the reaction products, calcium acetate, can precipitate from its “spent acid” solution because of its limited solubility. Similarly, the concentration of HCOOH normally is limited to 9 to 10% because of the limited solubility of calcium formate. At a 10% concentration, 1,000 gal HAc will dissolve 740 Ibm of limestone, whereas 1,000 gal HCOOH dissolves 970 lbm. Where more dissolving power per gallon of acid is desired, HCI is sometimes mixed with HCOOH or HAc. Such blends still provide extended reaction times. when compared with HCl. HCOOH and HAc also may be blended together. Table 54.2 illustrates some of the more common acid strengths and blends. Hydrofluoric
Acid (HF)
HF is used in combination with HCI and has been referred to as “intensified acid” or “mud removal” acid. depending on the formulation and use. HF is used primarily to remove clay-particle damage in sandstone formations, to improve permeability of clay-containing formations, and to increase solubility of dolomitic formations. Its utility is based on the fact that some clays. silica, and other materials normally insoluble in HCI have some degree of solubility in HF. For example, I .OOOgal of an acid solution containing 3% HF and 12% HCI will dissolve 500 lbm of clay and up to I .450 lbm of CaC03, 4HF+SiO?
-tSiFJ +2H10
and ZHF+SiF,+HzSiF,.
:3oE
+HzO+CO,.
: 32 -34w :36g
z
1380 -400
Fig. 54.2-Dilution of concentrated HCI
TABLE
54.2-DIFFERENT Acid
Concentration
Type 7.5 15 28 36
ACIDIZING
SOLUTIONS
Relatwe CaCO, Eouivalent Reaction (Ibm/l,i)OO bal acid) time’
HCI HCI HCI HCI Formic Acetlc Acetic
890 1,840 3,670 4,860 910 710 1,065
0.7 1.0 6.0 12.0 5.0 12.0 18.0
7.5 14
Formic/ HCI mixture
2,420
6.0
IO 14
Acetic/ HCI mixture
2,380
12.0
8 14
Formic/ Acetic mixture
1,700
18.0
10 10
15
‘Approwlmale time for acid react!on 10 be COmpleled ( %qx?nl ‘) to an equ~vaienf strength of 2 5% HCI solution Values are compared by using spending lime 01 15% HCI as 1
PETROLEUM
54-4
0.4 0.3 7’
\-MUD
I
I I ACID
;
0.41
z
0.3u
I
ENGINEERING
I
HANDBOOK
I
0.2 I 0. I 0
0
/-REGULAR ACID I I I I 6 12 18 TIME OF CONTACT IN HOURS
Fia. 54.3-Solubilitvof bentonite in mud
I 24
removal acid
Figs. 54.3 and 54.4 compare solubilities of bentonite and silica in HCl and HF acids. In carbonates, application of HF/HCl mixtures must be controlled carefully because of cost and possible precipitation of reaction products such as calcium fluorides or complex fluosilicates, which have a very limited solubility. For reaction with silicates, such as natural clays or clays in drilling fluids, the blends usually contain 2 to 10% HF and 5 to 26% HCI. The concentration of HCl used in the blend should be equal to or greater than that of the HF. The so-called “intensified acids” used in dolomitic formations are mainly HCl containing small concentrations of HF, usually about 0.25 % Intercrystalline films of silica, insoluble in HCl, often occur in the crystal structure of dolomite. When such are present, they prevent the acid from contacting the soluble portions of the rock. The presence of fluoride intensifier in the acid will destroy such films, allowing the acid to react more completely with the soluble portions of the rock. Fig. 54.5 illustrates the comparative reaction rates of HCI and intensified acid on dolomite formations. More recent developments of HF involve the use of delayed-action agents in sandstone acidizing. The first of these was a self-generating mud acid system, reported by Templeton er al. ’ The system provides slow generation of acid from the hydrolysis of methyl formate. yielding methyl alcohol and HCOOH acid. The acid then reacts with ammonium fluoride to yield HF in situ. They attribute the success of the system to getting the HF reaction away from the wellbore into areas that conventional HF solutions normally do not reach before spending. Equally important factors are the techniques of application and of returning the well to production following treatment. The treatment technique mvolves use of an aromatic solvent and mud acid preflush, along with the self-generating mud acid (SGMA). The wells are returned to production by opening the choke gradually over a 90-day period and never allowing an excessive drawdown. The process is available from most service companies as SGMA. A significant development in this area of slow-reacting, HF-supplying, clay-dissolving acid has been the fluoboric acid system reported by Thomas and Crowe.’ This acid
1 TIME
2
OF CONTACT
IN HOURS
Fia. 54.4-Solubilitvof silicasand in mud
hydrolyzes to form hydroxyfluoboric will dissolve clays.
removal acid
acid and HF, which
HBF4 +HZO-‘HBF30H+HF. This reaction provides a slow-release source of HF, which can penetrate deeply before spending. Perhaps more important, the slowly generated hydroxyfluoboric acid reacts with clays to form a nonswelling, nondispersing product that stabilizes fine clays and holds fine particles of silica in place.
Acid Reaction Rates A knowledge of the factors affecting the reaction rate of acids is important for several reasons. First, these factors, correlated with reservoir and formation characteristics, form a guide for the selection of acid type and volume for a given treatment. Next, a study of these factors can furnish an understanding of what parameters govern spending time, which will determine how far a given formulation can penetrate into the formation before spending. Many factors govern the reaction rate of an acid, such as pressure, temperature, flow velocity, acid concentration, reaction products, viscosity, acid type, area/volume ratio, and formation composition (physical and chemical). These factors have been the subject of extensively reported research for many years. Details of such studies are available in published literature. Only a brief general discussion will be presented here. Pressure Fig. 54.6 shows the effect of pressure on the reaction rate of 15% HCl with limestone and dolomite at 80°F. Above 500 psi, pressure has little effect on reaction rate. At bottomhole treating pressures, there is only a small difference (a factor of 1.5 to 2) in the comparative reaction of acid with limestone and dolomite compared to the rather large difference (a factor of about 10) at atmospheric pressure. Temperature
Acid reaction rate increases directly with temperature. At 140 to 150”F, the reaction rate of HCI and limestone is
54-5
ACIDIZING
.INTENSIFIED
-
5
IO
15
20
25
400
800 1200 1400 PRESSURE (PSI)
TIME IN MINUTES Fig. 54.5-Comparative reaction rates of conventional and intensified acids.
MARBLE
Fig. 54.6-Effect of pressureon
2000
reaction rate (15%
2400
HCI tit 80°F).
approximately twice that at 80°F. It must be recognized that the temperature controlling the reaction is affected by the injection temperature of the acid (a major factor), and by the heat liberated by the reaction itself (a minor factor). Computerized programs are used to estimate the bottomhole fluid temperature at various stages, allowing more effective acid treatment design. Flow Velocity Fig. 54.7 shows that increased flow velocity increases the reaction rate of 15 % HCl with CaCO 3. This velocity effect is more pronounced in narrower fractures. Reaction rate is a function of shear rate, 6 v/b, set - ’ as illustrated by the following equation: R=[(28.5
v/b)0.8+184]x10-6,
. . . . . . . . . . . ...(l)
where R is the reaction rate in lbmisq ft-set, v is the flow velocity in fracture, ft/sec, and b is the fracture width, ft. (The reaction rate is for 15% HCl with marble at 80°F under 1,100 psi pressure.) The flow velocity in fractures and channels depends on injection rate and actual geometry of the flow path. vd=O. 18i,,l(rfb)
vlf= 1,15i,,l(hb) v,, = 17.2i,,/d2
(radial fracture), (linear fracture), (cylindrical
. . .(2a) . ..
channel).
(2b) .
. . .(2c)
where v = flow velocity in fractures and channels, ftlsec, = acid injection rate, bbl/min, 1ac rf = fracture radius, ft, h = fracture height, ft, d = channel diameter, in., and b = fracture width, in. Acid Concentration
Reaction rate increases with acid concentration up to 24 to 25% HCl, but not proportionally, as shown in Fig.
I IO0
10 ,
ACID FLOW
1,000 VELOCITY
10,000
40,000
,s,ce,
FIAClUlE WIDTII
Fig. 54.7-Effect of flow on
reaction
rate
(15%
HCI with
CaCO,).
54.8. Above 25% HCl, the reaction rate actually decreases because of reduced acid activity. As acid spends, the reaction rate decreases as a result of reduced acid concentration and the retarding effect of dissolved reaction products, such as calcium or magnesium chloride. Area/Volume
Ratio
Area/volume (A/V) ratio is one of the major factors affecting reaction rate spending time, and may vary over a wide range. This ratio, the area in contact with a given volume of acid, is inversely proportional to pore radius or fracture width. Fig. 54.9 shows the time required for 15% HCl to spend on marble, at 80°F and 1,100 psi, for three different A/V ratios. The term “spending time” has very little meaning or value by itself. It must be related to flow geometry and, thus, to the distance the acid penetrates before it is spent. In matrix acidizing, extremely high A/V ratios may be encountered. For example, a IO-md, 20%-porosity limestone may have an A/V ratio of 28,000 to 1. In such a formation, it would be very difficult to obtain significant penetration before spending. A natural fracture, 0.00 1 in. wide, has an A/V ratio of 3,200: 1. A 0. l-in. fracture has an A/V ratio of 32: 1. The smaller ratios in wider frac-
PETROLEUM
“0
10
20
30
ENGINEERING
40
50
HANDBOOK
60
‘0
Th4E (min) Fig. 54.9-Effect of A/V ratioon spending time (15% HCI, 80°F and 1,100 psi).
Two formations having the same acid solubility and permeability may respond differently to acid treatment because of variances in physical structure. I
0
5
IO
I5
20
PERCENT
25
30
35
HCI
Fig. 54.8-Effect of concentrationon reactionrate and spending rate.
Acid Additives The use of a corrosion inhibitor as an additive made possible the firstcommercially feasible acidizing treatments. Since that time, many auxiliary chemicals have been developed to modify acid solutions, influencing their application and recovery. Corrosion
TABLE 54.3-EFFECT OF TEMPERATURE ON ORGANIC INHIBITOR PROTECTION TIME
Concentration
Temperature
WI
C’F)
0.6 1.0 2.0 2.0’
175 250 300 350
Protection Time (hours) 24 6 6 4
‘With mhtbltor aId
tures allow greater penetration of the acid into the reservoir before spending is complete. Formation
Composition
Probably the most important factor that governs effectiveness of an acidizing treatment is the rock composition. Its chemical and physical characteristics determine how and where the acid will react with and dissolve the rock. From the standpoint of chemical composition, there is little difference in the reaction rate of HCI on most limestones, all other factors remaining constant. The physical rock texture. however, can control pore size distribution. A/V ratio, pore geometry, and other properties. This, in turn, influences the type of flow channels created by acid reaction and is the key to acid response.
Inhibitors
Inhibitors are chemical materials that, when dissolved in acid solutions, greatly retard the reaction rate of the acid with metals. They are used in acidizing to avoid damage to casing, tubing, pumps, valves. and other well equipment. Inhibitors cannot completely stop all reaction between the acid and metal; however, they do slow the reaction, eliminating 95 to 98% of the metal loss that would otherwise occur. Most inhibitors have practically no effect on the reaction rate of acid with limestone, dolomite, or acid-soluble scale deposits. The length of time that an inhibitor is effective depends on the acid temperature, type of acid, acid concentration, type of steel, and the inhibitor concentration. Organic inhibitors in HCI are effective up to 400”F, but above 200°F relatively large concentrations are required. The effect of temperature on corrosion inhibition is illustrated in Table 54.3. Equations have been developed for estimating BHT’s during acid treatments. By knowing these temperatures, adequate corrosion protection can be provided, even in wells with static BHT’s up to 400°F. Surfactants
Surfactants are chemicals used to lower the surface terlsion or interfacial tension of fresh acid or spent acid solutions. The use of a surfactant improves the treating efficiency in a number of ways. The presence of a surfactant improves the penetrating ability of the acid solution entering a formation. This is extremely desirable in matrix acidizing treatments. be-
54-7
ACIDIZING
z -
ST 3; I 2 lpoo a 0’800yORDlNARY
A C I D ,
0
g 6 0 0 i;i
/
Egjpek& k! 3 z
0
20 15 5 IO PENETRATION IN FORMATION- FEET
E
PHI
Fig. 54.10—Effect of surface-tension-reducing agent in facili-
tating return of spent acid.
cause it provides deeper penetration of acid into the formation. In addition, surfactants permit the acid to penetrate oily films clinging to the surface of the rock and lining the pores, so that the acid can come in contact with the rock and dissolve it. The use of surfactants also facilitates the return of spent acid following the treatment (Fig. 54.10). Wetting of the formation is more nearly complete and there is less resistance to flow of the acid, so that the spent acid is readily returned through the treated section. This is especially important in low-pressure wells. Another advantage in the use of surfactants in acid is the demulsifying action obtained. Many surfactants are capable of inhibiting the occurrence of emulsions or destroying those already formed. Surfactants also promote dispersion and suspension of fine solids to provide better cleanup following treatment. These solids may be either mud solids or natural fines released from the formation. They are suspended and physically removed from the formation. Special surfactants are used as antisludge agents. Some crudes form an insoluble sludge when in contact with acid. The sludge consists of asphaltenes, resin, paraffin, and other complex hydrocarbons. The acid reacts with the crude at the interface, forming an insoluble film. The coalescence of this film, which results on the sludge particles, can be avoided by use of proper additives. Ethylene glycol monobutyl ether is a mutual solvent surfactant used in matrix sandstone acidizing to water-wet the formation. This agent prevents particle migration and subsequent particle plugging. It improves cleanup by preventing the stabilization of emulsions by fine particles. Many different surfactants are used in acidizing. Type and concentration for a particular application should be selected on the basis of laboratory testing. Silicate-Control Agents Various silicate compounds, commonly known as clays and silts, usually are present in most limestones and dolo-
t-942
PH3
PHI
PH5
Fig. 54.11—Photograph showing effect of pH on the volume of
silicate particles.
mites. One of the characteristics of these silicates is that they will swell in spent acid. Naturally, this is undesirble because swollen silicate particles may block formation flow channels, reducing well production. Silicate-control additives are chemicals that prevent released silicate particles from adsorbing water. Some buffer the pH of the solution near the isoelectric point (where the volume of the swelled clays is at a minimum). Others cause shrinkage of the silicate particles by replacing the adsorbed water molecules with a water-repellent organic film. Thus, possible formation plugging is prevented, treating pressures are lowered, faster cleanup is provided, and the occurrence of particle-stabilized emulsions is minimized. This is illustrated in Fig. 54.11. Iron-Control Agents Iron control is approached two ways. The oldest and most common approach is to use sequestering agents, which act by complexing iron ions, thereby preventing precipitation when the acid spends. A second method is use of reducing agents that reduce any ferric ions (Fe3+) to ferrous ions (Fe2+), which do not precipitate as the hydroxide or hydrous oxide until the pH of the system is above 7. Since acids in contact with the formation rock will not spend to a pH that high, the hydroxide will not damage the well. Spent acid usually has a pH between 4.5 and 6.5, no higher. Erythorbic acid is one of the most effective reducing agents that can be used for this purpose. The reduction of all the ferric iron to ferrous iron, however, does not prevent the precipitation of ferrous sulfide (FeS), which precipitates when the acid spends to a pH of 2, as it will readily in almost any formation. To protect fully against iron precipitation in a sour well, a complexing agent is needed. Citric, lactic, and acetic acids as well as EDTA or NTA are popular sequestrants. In some wells where H 2S can become mixed with the acid it also may be advisable to use both the reducing agent and the sequestering agents, since ferric iron can react with H 2S to
PETROLEUM
54-8
precipitate free sulfur, which itself can damage permeability The loss of effectiveness of acetic acid at temperatures above 125°F and the possibility of precipitating calcium citrate also are factors that should be considered in guarding against iron precipitates. Alcohols
Methyl and isopropyl alcohols sometimes are used at concentrations of 5 to 20 ~01% of acid to reduce surface tension. Methyl alcohol is sometimes used at concentrations, up to 66 % to increase vapor pressure of the acid and spent acid solution. Use of alcohols thus improves both rate and degree of cleanup, which can be particularly helpful in dry gas wells. Gelling and Fluid Loss Agents
Natural gums and synthetic polymers are added to acid to increase the viscosity of the acid solution. 3 This reduces leakoff into large pore spaces and, to some extent, into natural hairline fractures. It also provides some degree of reaction rate retardation. Other materials used to control leakoff are fine (IOOmesh) sand4 and fine salt.5 These materials bridge in hairline fractures to reduce fluid flow out of the main fracture during fracture acidizing treatments. Another successful fluid-loss control agent is a mixture of finely ground, oil-soluble resins. 6 Originally designed as a diverting agent for use through gravel packs during sandstone matrix acidizing treatments, this agent was later shown to be effective as a fluid-loss agent in fracture acidizing, when used at higher concentrations. ’ Liquefied
Gases
Liquid nitrogen and liquid CO2 sometimes are used in acid solutions to provide added energy for better well cleanup. Nitrogen also is used to make foamed acid, which provides excellent leakoff control in low permeability rock. 8.9 Retarded
Acids
It is often desirable in acid fracturing treatments to retard the reaction rate of the acid to provide deeper penetration of active acid into the formation. Retardation may be accomplished by use of slower-reacting acids (HAc and HCOOH), by adding chemicals to reduce reaction rate, or by increasing concentration to extend spending time. HAc and HCOOH are weakly ionized and sometimes are used to obtain longer reaction time. The additional cost of these acids may prohibit extensive use in certain formations. Deeper matrix penetration than would be obtained by HAc or HCOOH is obtained by the fasterreacting HCl because the channeling or wormhole effect produced by the HCl reduces the A/V ratio, thus prolonging reaction time. In fractures, the HAc and HCOOH would obtain deeper penetration than HCl; however, larger volumes would be required to dissolve an equivalent amount of rock. Some chemicals, added to HCl, form a barrier on the rock surface, which interferes with its normal contact and “retards” the reaction rate of the acid. Acid-in-oil emulsions generally exhibit retarded reaction rates. The acid in the emulsion does not completely contact the rock sur-
ENGINEERING
HANDBOOK
face because of the presence of an interfering oil film. This is particularly true for emulsions with at least 20% oil as the outer phase. Certain surfactants recently have been found to be beneficial in reducing reaction rate and, thus, extending spending time and penetration distance. These surfactants, in the presence of oil, provide a hydrophobic or water-repellent, oil-like film on the rock surface that restricts acid/rock contact. Fluid-loss materials and gelling agents (acid-thickening additives) also tend to reduce the reaction of HCl by film development on rocks. High concentrations of an acid provide longer reaction times than lower concentrations because (1) there is more acid to react, (2) the additional reaction products further retard reaction rates, and (3) the enlarged flow path, with reduced A/V ratio, extends the spending time and penetration of a high-concentration acid. For example, 28% HCl may take four to six times longer to react completely than does 15% HCl. In this case, the reaction time is extended in spite of the initially faster reaction rate of the 28% HCl.
Acidizing Techniques There are three fundamental techniques used in acidizing treatments. 1. We&ore Cleunup. This entails fill-up and soak of acid in the wellbore. Fluid movement is at a minimum, unless some mechanical means of agitation is used. 2. Matrix Acidiz,ing. This is done by injecting acid into the matrix pore structure of the formation, below the hydraulic fracturing pressure. Flow pattern is essentially through the natural permeability structure. 3. Acid Fmcturing. This is injection into the formation above hydraulic fracturing pressure. Flow pattern is essentially through hydraulic fractures: however, much of the fluid does leak off into the matrix along the fracture faces. The technique selected will depend on what the operator wishes to accomplish with the treatment. Matrix acidizing may be selected as a proper technique for one or more of the following reasons: (1) to remove either natural or induced formation damage, (2) to achieve low-pressure breakdown of the formation before fracturing, (3) to achieve uniform breakdown of all perforations, (4) to leave zone barriers intact, or (5) to achieve reduced treating costs. The principal types of formation damage are mud invasion, cement, precipitates, saturation changes, and migration of fines. The effect of damage on injectivity or productivity is shown in Figs. 54.12 and 54.13. It can be seen that the greatest flow increase results from restoring the natural rock permeability. The magnitude of this primary flow increase depends on the extent (radius) of the damage. Further increase in pore size by matrix acidizing results in only a limited increase in flow (stimulation). If the producing formation does not have enough natural permeability, then a hydraulic fracturing treatment should be considered. The primary purpose of fracturing is to achieve injectivity or productivity beyond the natural reservoir capability. An effective fracture may create a new permeability path, interconnect existing permeability streaks, or break into an untapped portion of the reservoir.
ACIDIZING
54-9
00
25
5 m
0
I
2 RADIAL
3 4 EXTENTd c4ALGul
6
7 ZorE.
0
9
lo
FEET
I
IO PERCENT
100
OF NATURAL
1000
PERMEAElllTY
Fig. 54.12-Effect of damaged zone on flow. Fig. 54.13-Effect
of permeabilitychanges on radialflow.
The success of any fracturing treatment depends on two factors: fracture conductivity and effective penetration, as illustrated in Fig. 54.14. If enough etched fracture conductivity can be achieved, then increased penetration becomes important. For any given formation, there will be an optimum conductivity and penetration, which will be controlled by cost. In other words, there will be some point where production increase per dollar spent will be a maximum. This must be determined by pretreatment design.
Laboratory Testing The physical and chemical characteristics of the formation rock often affect the results of an acidizing treatment. In some cases, the use of special additive chemicals will improve the action of the acid or avoid cleanup difficulties in returning the spent acid following the job. It is important, therefore, that samples of the formation rock (either cores or cuttings) and, if possible, samples of the crude oil and formation brine be subjected to laboratory testing before acidizing to design the most effective treatment. Customarily, permeability. porosity, and oil- and watersaturation tests are run on formation core samples, using standardized core-analysis procedures. In addition, acidsolubility tests are run to determine to what extent the formation will respond to an acidizing treatment. Formation solubility may be determined two different ways. In the first method, a weighed chunk of the rock is immersed in an excess of acid and maintained at formation temperature. After an hour, any insoluble residue is washed. dried, and weighed. With samples known to contain silicates, additional tests may be run in which the rock is exposed to the dissolving action of combined HCl and HF. A more rapid test, suitable for samples known to consist largely of limestone or dolomite, entails dissolving a weighed sample of the rock in an excess of HCl and measuring the volume of CO* gas evolved during the reaction. A simple apparatus for conducting this test is shown in Fig. 54.15. In addition to these tests of the formation rock, the emulsifying tendencies of the formation crude should be determined whenever possible. Samples of the crude are mixed
McGUlRE IO'
IO'
RELATIVE
CONDUCTIVITY,
IO'
AND ID'
SIKORA IO'
bk#,,-In
Fig. 54.14-Relationship of conductivityand penetration to productivity increase.J= productivity index of well after stimulation,J, = productivityindex before stimulation, ri= radiusof fracture(ft), re = drainage radius (ft).k,=permeability of fracture (md), k, = permeabilityof formation (md), and b = fracture width (in.).
with the acid to be used in the acidizing treatment and then are shaken. The mixture is allowed to stand, and the time required for the oil and acid to separate is observed. Additional tests are run on mixtures of the crude oil with acid that has been spent completely on pulverized formation rock. If the formation crude shows a tendency to emulsify with either the fresh acid or the spent acid, the use of an appropriate surfactant is indicated. Similar tests using a mixture of crude and acid are made to determine acid sludging tendencies. Sludge is identified by filtering the mixture through a small mesh screen. Appropriate surfactants that are added to the acid to prevent sludge formation are evaluated. Other determinations of rock characteristics include tests for clay swelling tendencies and tests to determine rock composition (such as X-ray diffraction analysis) to indicate need for stabilizers, sequestering agents, or other acid additives.
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TABLE
54.4-FLOW
Diameter of Pore (A il 1 to 2 2 to 5 5 and above
Fig. 54.15-Laboratory solubillty tester(carbon dioxide evolution method).
Acid Treatment Design Three techniques of acidizing have been described previously. Wellbore cleanup treatments normally do not require complicated design procedures. Matrix and fracture acldlzmg treatments. on the other hand, can involve extensive predesign laboratory testing and complicated design procedures and calculations. Matrix Acidizing-Carbonate
Formations
Matrix acidizing in carbonates normally is used to break down all perforations and to remove damage. Plugging materials can be removed and permeability restored in two ways: (1) by dissolving the damaging material itself or (2) by dissolving part of the rock in which the damage exists. In carbonate rocks with acid solubilities greater than 50%) the latter method is often most effective. The dislodged solid particles or liquids then can bc removed physically by the return of the spent acids to the well. HCI normally is used in matrix treatments of carbonates, but HAc and/or HCOOH should be considered
ENGINEERING
THROUGH SIZES Pore Volume w 60 25 12 3
PORES
HANDBOOK
OF VARIOUS
Flow Through Pores (% of Total Flow) 10 15 30 45
for wells with temperatures in excess of 250 to 300°F. Any acid solution should be modified by use of proper additives to meet special situations. Acid inhibitor selection must be based primarily on treating temperature and, to some extent, on the type of acid formulation. Surfactant type and concentration should be selected to minimize emulsion tendencies and, perhaps, to aid in dispersing fine undissolved solids. These may be drilling mud, cement solids, or natural clay particles released from the formation. Suspension and removal of these materials can play an important part in the overall treatment results. Diverting agents may be used to promote uniform penetration in long sections. Acid-swellable synthetic polymers, controlled-solubility particulate solids, perforation ball sealers, gel slugs, etc., have been used successfully to provide more uniform injectivity. Assuring the distribution of acid into the entire interval is a critical part of carrying out a matrix treatment. Otherwise, large portions of the interval may get very little, if any, acid. In matrix acidizing, injection rates should be controlled so that the formation is not fractured. The use of as high a rate as possible without exceeding the fracturing pressure is recommended. In certain cases, it may be necessary to create a fracture to open perforations, after which pressure can be reduced below fracturing pressure, thus providing a matrix flow pattern. Controlling the injection pressure is the primary concern. Maintaining bottomhole pressures below hydraulic fracturing pressures may restrict injection rates to only fractional barrels per minute. An increasing rate may then be possible as the treatment progresses. Because of differences in the size and shape of the pores, penetration of acid in a carbonate rock is far from uniform. Porosity anomalies may result from vugs, hairline fissures, or tortuous capillary-like pores. Because of these heterogeneities, a “channeling” or “wormholing” occurs with most acid formulations. The resultant effect is the attainment of much greater acid penetration of matrix than expected. The wide distribution of flow in a rock of varying pore diameters (Table 54.4) is further accentuated by acidizing. As discussed in a preceding section, the fast-reacting HCl may provide greater penetration of the limestone matrix than the slow-reacting acetic acid, but not as great as with the emulsified or gelled acids. Evidently, the slow reaction of acetic acid does not change the flow distribution rapidly enough to “channel,” but rather results in several small pore enlargements for short distances as opposed to a few large, long channels. Since the formation damage normally does not exist for a great distance from the wellbore, the volume of acid needed is small. With a formation porosity of IO%, 60
54-11
ACIDIZING
gal of acid per foot of section will fill the porosity to a radius of 5 ft. Usually, matrix treatment volumes range from 50 to 250 gal per foot of section. If damage is deeper than 5 to 10 ft, then larger volumes of acid, a means of retarding the reaction rate, or, perhaps, fracturing techniques, may be required. Very little rock must be dissolved to result in a significant amount of damage repair or permeability increase. Removal of only 1% of limestone or dolomite rock for a distance of about 5 ft from the wellbore requires only 70 gal of 15 % HClift of vertical interval. An overflush in the matrix acidizing treatment is recommended. This will ensure efficient displacement of the acid into the matrix. A minimum shut-in time is recommended before returning the spent acid to the well. Since the spending time of acid is short, a long shut-in time of several hours is not necessary, even for the so-called ‘‘retarded acid. ’’The overflush fluid may be brine, water, oil, or a weak acid. Enough volume should be used to ensure maximum penetration of the last portion of the acid, before it is spent. Matrix Acidizing--Sandstone
Formations
The purpose of sandstone acidizing is to restore permeability by dissolving away formation-damaging clay-like minerals or other acid-soluble materials. The clay may be inherent in the formation or may be the result of drilling mud or workover fluid invasion. The type of acid used most often in sandstones is a mixture of HF and HCl. These mixtures commonly are rem ferred to as mud acids or mud removal acids. As previously discussed, fluoboric acid also has become popular in sandstone formations. Concentrations of 2 to 6 % HF and 8 to 12 % HCl normally are used. If a significant amount of calcium carbonate is present in the formation (5 to lo%), a spearhead of HCl should be used to react with it before the HF/HCl is injected. With carbonate content above 20%, HF acid probably is not needed, except to give entry through clay damage. As in any matrix-type treatment, injection of the HF/HCl should he below fracturing pressure. The volume of acid required depends on the depth and severity of the damage. A total of 50 to 250 gal of acid per foot of interval is the normal treatment volume, if damage is not extensive. An acid solubility test may not be a realistic evaluation of acid requirements. Results of a field study by Gidley et al. lo confirmed some earlier recommendations based on laboratory core flow studies. These results showed much greater success when more than 125 gal/t? acid was used. The reported core flow test showed what response the formation will have to acid. This is illustrated in Fig. 54.16. Although some of these formations have approximately the same acid (HF/HCI) solubility, permeability, and porosity, the response to acid is quite different. Initial reduction in permeability is a common occurrence observed with many formation core flow tests. It is attributed to sloughing particles (clays, silica, fines, etc.) that apparently bridge in the flow channels and restrict flow, before their further reaction with the acid. An inadequate acid volume treatment could lead to a restricted permeability in a formation, if the bridging is severe. Since secondary reactions may occur, resulting in possible precipitation of damaging reaction products, mud
5
"0 MUD
ACID
VOLUMf
IO RfPUIRfMENT5
15
20
(p.l/f12)
Fig. 54.16--Response of cores from producing formations to mud acid.
acid should be returned to the wellbore as soon as the initial spending time has elapsed. The spent HF/HCl acids should not be allowed to mix with formation brine, if at all possible because of the danger of precipitates. Inhibitors, surfactants, and diverting methods should be selected just as in an HCl acid treatment. As in the case of matrix acid treatment in carbonates, an overflush is recommended. Suitable fluids include weak acid, oil, or water. Formation brine should not be used to overflush HF/HCl. Short shut-in times should be used-a few hours at the most. Fracture
Acidizing-Carbonate
Formations
The primary purpose of an acid fracturing treatment of a carbonate formation is to achieve productivity or injectivity beyond the natural capabilities of the reservoir. It is most applicable in formations with a low and/or ineffective permeability structure. The effectiveness of an induced hydraulic fracture is a function of both its conductivity and the extent of penetration of the drainage radius of the well. These factors will depend on well and reservoir properties, formation characteristics, injection rate, type and volume of acid used, and shape and orientation of the fracture. All these factors have been correlated by several companies into “guides” to acid fracture treatment design. Such guides provide mathematical relationships for determining the fracture area and conductivity achieved by different volumes of specific acid formulations at various injection formulations. These guides are programmed for computer calculation, so that rapid comparison of various treatment designs can be made for selection of best results per dollar of treatment cost. These guides are not sufficiently similar to get clear comparison between different companies but should be compared only with other calculations from the same system.
Critical Wells In ultradeep, high-temperature wells, many factors must be considered in the stimulation treatment design. First, the high BHT can drastically affect reaction rate of acid, inhibition, and other properties of the acid formulation.
54-12
These effects can be partially offset by formation cooldown techniques. Basically, this consists of pumping a pad volume of fluid (generally gelled water) into the formation to cool the rock to a more normal treating temperature. Most companies have computer programs available to calculate pad volumes required for a given temperature reduction. Another problem is created when fluids with temperatures lower than BHT’s are used. This problem is mechanical and involves tubing movement. In ultradeep wells, such contraction can create stress in the tubing greater than tubing strength, resulting in a parted string. The solution to this problem is to slack off or to release tension at the top of the tubing string as the job progresses. Again, computer programs are available from most service companies to predict tubing movement under given conditions.
Summary In summary, acidizing is a process that uses reactive materials to increase well production by dissolving either the reservoir rock or damaging materials blocking the pore spaces of the rock. Different kinds of acids and additives are available, so that treating fluids can be tailored to meet individual well needs. Acid formulations may be applied in either matrix- or fracture-type treatment, depending on the degree of stimulation or production increase desired. While acidizing, and acidizing treatment design, in detail are beyond the scope of this text, published literature offers answers and assistance in solving many of the problems encountered. The General References cover many of the recent technical developments in this field. In addition, most service companies providing acidizing service offer laboratory facilities, technical assistance, and computer programs for problem analyses and treatment design.
References I. Templeton, C.C. er al.: “Self-Generating Mud Acid,” J. Per. Tech. (Oct. 1975) 1199-1203. 2. Thomas, R.L. and Crow, C.W.: “Matrix Treatment Employs New
3.
4.
5.
6.
7.
8.
Acid System for Stimulation and Control of Fines Migration in Sandstone Formations,” paper SPE 7566 presented at the 1978 SPE Annual Technical Conference and Exhibition, Houston, Oct. l-3. Crowe, C.W., Martin, R.C., and Michaelis, A M.: “Evaluation of Acid Gelling Agents for Use m Well Stimulation,” paper SPE 9384 presented at the 1980 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 21-24. Miller, B.D. and Warembourg. P.A.: “Prepack Technique Using Fine Sand Improves Results of Fracturing and Fracture Acidizing Treatments.“. paper SPE 5643 presented-at the 1975 SPE Annul? Technical Conference and Exhibition, Dallas, Sept. 2%Oct. I. Schrieter, F.E. and Shaw, M.S.: “Use of Fine Salt as a Fluid Loss Material in Acid Fracturmg Stimulation Treatments,” paper SPE 7570 presented at the 1978 SPE Annual Technical Conference and Exhibition, Houston, Oct. l-3. Crowe, C.W.: “Evaluation of Oil-Soluble Resm Mixtures as Divenmg Agents for Matrix Acidizing,” paper SPE 3505 presented at the 1971 SPE Annual Meeting, New Orleans, Oct. 3-6. N&ode. D.E. and Kmk. K.F.: “An Evaluation of Acid Fluid Loss Additives. Retarded Acids, and Acidized Fracture Conductivity,” paper SPE 4549 presented at the 1973 SPE Annual Fall Meecmg, La5 Vegas. Sept. 30-Oct. 3. King, G.E. and Hollingsworth, F.H.: “Evaluation of Dwertmg Agent Effectiveness and Clean-up Characteristics Using a Dynamic Laboratory Model-High Permeability Case.” paper SPE 8400 presented at the 1979 SPE Annual Technical Conference and ExhIbition, Las Vegas, Sept. 23-26.
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9. Scherubel, GA. and Crowe, C.W.: “Foamed Acid: A New Concept in Fracture Acidiaing,” paper SPE 7568 presented at&he 1978 SPE Annual Technical Conference and Exhibition. Houston, Oct. 1-3. 10. Gidley, J.L., Ryan, J.C., and Mayhill, T.D. : “Study of Field Applications of Sandstone Acidizing,” /. Per. Tech. (Nov. 1976) 1289-94.
General References Abram, A. ef al: “The Development and Application of a High pH Acid Stimulation System for a Deep Mississippi Gas Well,” paper SPE 7565 presented at the 1978 SPE Annual Technical Conference and Exhibition, Houston, Oct. 1-3.
Barron, A.N., Hendrickson,A.R., and Wieland, D.R.: “The Effect of Flow on Acid Reactivity in a Carbonate Fracture,” (April 1962) 409-15; Trans., AIME, 225
J. Per. Tech.
Black, H.N. and Stubbs, B.A.: “A Case History Study-Evaluation of San Andres Stimulation Results,” paper SPE 5649 presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 29-Oct. 1. Broddus, E.C. and Knox, J.A.: “Influence of Acid Type and Quantity in Limestone Etching,” paper API No. 851-39-I presented at API Production Dev. Mid-Continent Dist., Wichita, March 31-April 2, 1965. Burkill, G.C.C. and Pierre, M.L.: “Successful Matrix Acidizing of Sandstones Requires a Reliable Estimate of Wellbore Damage,” paper SPE 5590 presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 29-Oct. I, Chat&in, J-C., Silberberg, I.H., and Schechter, R.S.: “Thermodynamic Limitations in Organic Acid-Carbonate Systems,” Sot. Per. Eng. J. (Aug. 1976) 189-95. Church, D.C., Quisenberry, J.L., and Fox, K.B.: “Field Evaluation of Gelled Acid for Carbonate Formations,” J. Pet. Tech. (Dec. 1981) 241 l-74 Clark. G.J., Wong, T.C.T., and Mungan, N.: “New Acid Systems for Sandstone Stimulation,” Proc., SPE Formation Damage Control Symposium, Lafayette, LA (March 24-25, 1982) 187-97. Coppel, C.P.: “Factors Causing Emulsion Upsets in Surface Facilities Following Acid Stimulation,” J. Per. Tech. (Sept. 1975) 1060-66. Coulter, G.R. and Purvis, S.B.: “Successful Stimulation PracticesOffshore Holland,” J. Per. Tech. (June 1982) 121 l-18. Coulter, A.W. Jr., Copeland, C.T., and Harrisberger, W.H.: “A Laboratory Study of Clay Stabilizers,” Sot. Pet. Eng J. (Oct. 1979) 267-69.
Coulter, A.W. Jr. er al.: “Alternate Stages of Pad Fluid and Acid Provide Improved Leakoff Control for Fracture Acldizing,” paper SPE 6124 presented at the 1976 SPE Annual Technical Conference and Exhibition, New Orleans, Oct. 3-6. Coulter, A.W. Jr et al. : “Mathematical Model Simulates Actual Well Conditions In Fracture Acidizing Treatment Design.” paper SPE 5004 presented at the 1974 SPE Annual Meeting, Houston, Oct. 6-9 Crawford, D.L., Coulter, A.W. Jr.. and Osborn, F.E. III: “Removal of Wellbore Damage From Highly Permeable Formations and Naturally FracturedReservoirs,” paper SPE 8796 presented at the 1980 SPE Formation Damage Control Symposann, Bakersfield, CA, Jan. 28-29. Crenshaw, P.L., Flippen, F.F., and Pauley. P.O.: “Stimulation Treatment Design for the Delaware Basin Ellenburger.” paper SPE 2375 presented at the 1968 SPE Annual Meeting. Houston. Sept. 29-Oct. 2. Crowe, C.W. and Minor, S.S.: “Effect of Acid Corrosion Inhibitors Upon Matrix Stimulation Results,” paper SPE I I1 I9 presented at the 1982 SPE Annual Technical Conference and Exhibmon. New Orleans. Sept. 26-29
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Davis. J.J., Mantillas, G., and Melnyk. J.D.: “Improved Actd Treatments by Use of the Spearhead Film Technique.” paper SPE 1164 presented at the 1965 SPE Rocky Mountain Regional Meeting, Billings. MT, June 3-4. Deysarkar, A.K. cf al. : “Crosslinked Fracture Acidizing Acid Gel.” paper 82-33-16 presented at the 1982 CIM Annual Meeting, Calgary. June 6-9.
Hendrickson. A.R.. Rosme, R.B., and Wieland. D.R.: “The Role of Acid Reaction Rates in Planning Acidizing Treatments.” Truns., AIME, 222 (1961). Hendrickson, A.R., Hurst. R.E., and Wieland. D.R.: “Engmeered Guide for Planning Acidizing Treatments Based on Specific Reservoir Characteristics.” J. Per Twh. (Feb. 19M)) 16-23: Trans.. AIME. 219.
Dill, W.R.: “Retarded Acidizing Fluids.” U.S. Patent No. 4.322.306 (1982).
Hill, D.G. and DeMort, D.N.: “Effect of Hydrogen Sulfide on Inhibition of Oil Field Tubing in Hydrochloric Acid,” paper SPE 6660 presented at the 1977 SPE East Texas Section, Sour Gas Symposium, Tyler. Nov. 14-15.
Dill. W.R. and Keeney, B.R.: “Optimtzing HCI-Formic Acid Mixtures for High Temperature Stimulation,” paper SPE 7567 presented at the 1978 SPE Annual Technical Conference and Exhibition, Houston, Oct. l-3.
Holman, G-B.: “State-of-the-Art 1982) 239-41.
Dunlap, P.M. and Hegner, IS.: “An Improved Acid for Calcium Sulfate Bearing Formations,” J. Pet. Tech. (Jan. 1960) 67-70: Trans.. AIME. 219. Eiy, .I., McDow. G., and Turner, I.: “Stimulation Techniques Used in the Austin Chalk,” Proc., 29th Annual Southwestern Pet. Assn. Short Course, Lubbock (1982) 110-2 1. Fogler, H.S., Lund, K., and McCune, C.C.: “Predictmg the Flow and Reaction of HCliHF Acid Mixtures in Porous Sandstone Cores,” Sue. Per. Eng. J. (Oct. 1976) 248860; Trans., AIME, 261. Ford, W.G.F. and Roberts, L.D.: “The Effect of Foam on Surface Kinetics m Fracture Acidizing.” J. Pet. Tech. (Jan. 1985) 89-97. Ford, W.G.F.: “Foamed Acid, An Effective Stimulation Fluid,” paper SPE 9385 presented at the 1980 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 21-24. Ford, W.G.F.. Burkleca. L.F., and Squire, K.A.: “Foamed Acid Stimulation Success in the Illmois and Michigan Basins,” paper SPE 9386 presented at the 1980 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 21-24. Graham. 1.W.: “Well Stimulation by Two-Phase Flow,” U.S. Patent No. 4,174,753 (1979). Green, E.B., Lybarger. J.H., and Richardson, E.A.: “In-Situ Neutralization System Solves Facility Upset Problems,” Paper SPE 4796 presented at the 1974 SPE Annual Meetmg, Houston, Oct. 6-9. Haafkens, R., Luque, R.F., and DeVries, W.: “Method for Formmg Channels of High Fluid Conductivity in Formation Parts Around a Borehole,” U.S. Patent No. 4,249,609 (1981). Hall, B.E.: “Methods and Compositions for Dissolving Silicates,” U.S. Patent No. 4,304,676 (1981). Hall, B.E., Underwood, P.J.. and Tinnemeyer, A.C.:“Stimulation of the North Coles Levee Field with a Retarded-HF-Acid.” paper SPE 9934, presented at the 1981 SPE California Regional Meeting. Bakersfield. March 25-27. Hall, B.E. and Anderson, B-W.: “Field Results for a New Retarded Sandstone Acidizing System,” paper SPE 6871 presented at the 1977 SPE Annual Technical Conference and Exhibition, Denver, Oct. 9- 12. Harris, F.N.: “Application of Acetic Acid in Well Completion, Stimulation, and Reconditioning,” J. Pet. Tech. (July 1961) 637-39. Harris, L.E.: “High Viscosity Acidic Treating Fluids and Methods of Foaming and Using the Same,” U.S. Patent No. 4,324,668 (1982). Harris, O.E., Hendrickson, A.R.. and Coulter, A.W. Jr.: “HighConcentration Hydrochlortc Acid Aids Stimulation Results in Carbonate Reservoirs.” J. Pet. Tech. (Oct. 1966) 1291-96. Hendrickson, A.R. and Cameron, R.C.: “New Fracture Acid Technique Provides Efficient Stimulation of Massive Carbonate Sections,” J. Cdn. Pet. Tech. (Jan.-March 1969) 1-5.
Well Stimulation,“J.
Per. Tech. (Feb.
Horton, H.L., Hendrickson, A.R.. and Crowe. C.W.: “Matrix Acidizing of Limestone Reservoirs,” paper API-No. 906-10-F presented at the 1965 API Prod. Div. Southwest District Meeting, Dallas, March 10-12. Hudock. K. and Skelton, N.: “Fracture Acids Undergo Comparative Tests,” Northeast Oil Reporter (Feb. 1982) 74-76. 78. Jennings, A.R.: “The Effect of Surfactant-Bearing Fluids on Permeability Behavior in Oil-Producing Formations,” paper SPE 5635 presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 29-Oct. 1. Keeney, B.R. and Frost, J.G.: “Guidelines Regarding the Use of Alcohols in Acidic Stimulation Fluids,” paper SPE 5158 presented at the 1974 SPE Annual Meeting, Houston, Oct. 6-9. Kincheloe, R.L.: “Matrix Acidizing Reduces Formation Damage.” Eng. (Jan. 1967) 74-75, 78, 83.
Pet.
King., G.E.: “Foam Stimulation Fluids: What They Are. Where They Work,” Pet.Eng. Inrl. (July 1982) 52. 56. 58, 60. Knox, J.A., Lasater, R.M.. and Dill, W.R.: “A New Concept in Acidizing Utilizing Chemical Retardation,” paper SPE 975 presented at the 1964 SPE Annual Meeting, Houston, Oct. 11-14. Kunze, K.R. and Shaughnessy, C.M.: “Acidizing Sandstone Formations with Fluoboric Acid,” paper SPE 9387 presented at the 1980 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 21-24. Labrid, J.: “Acid Stimulation in Argillaceous Sandstone-Interpreting Acid Response Curves-Measuring Kinetic and Petrophysical Parameters,” paper SPE 5156 presented at the 1974 SPE Annual Meeting, Houston, Oct. 6-9. Lee, M.H. and Roberts, L.D.: “The Effect of Heat of Reaction on Temperature Distribution and Acid Penetration in a Fracture,” Sot. Per. Eng. J. (Dec. 1980) 501-07. Leggett, B. el al. : “Use of a Novel Liquid Gelling Agent for Acidtzing in the Levelland Field,” paper SPE 11121 presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 26-29. McBride, J.R., Rathbone. M.J., and Thomas, R.L.: “Evaluation of Fluoboric Acid Treatment in the Grand Isle Offshore Area Using Multiple-Rate Flow Test,” paper SPE 8339 presented at the 1979 SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 23-26. McCune, C.C. er al. : ’‘Acidization VI-A New Model of the Physical and Chemical Changes in Sandstone During Acidizing,” paper SPE 5157 presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 29-Oct. 1. McLaughlin, W.A. and Berkshire, D-C.: “Adicizing Reservoirs While Chelating Iron with Sulfosalicvlic Acid,” Canada Patent No. 1.086.485 (1980). McLeod, H.O., Ledlow, L.B., and Till, M.V.: “The Planrung, Execution and Evaluation of Acid Treatments in Sandstone Formations.” paper SPE 11931 presented at the 1983 SPE Annual Technical Conference and Exhibition, San Francisco, Oct. 5-8.
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McLeod. H.O. and Coulter. A.W. Jr.: “The Use of Alcohol in Gas Well Stimulation.” paper SPE 1663 presented at the 1966 SPE Eastern Regional Meeting. Columbus, OH. Nov. IO- I I. McLeod. H.O.. McGinty. J.E.. and Smith. C.F.: “Deep Well Stimulation with Alcoholic Acid,” paper SPE 1558 presented at the 1966 SPE Annual Meeting, Dallas. Oct. 2-5.
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HANDBOOK
Shaughneasy, C.M. and Kunze. K.R.: “Understandmg Sandstone Acidizing Leads to Improved Field Practices.” paper SPE 9388 presented at the 1980 SPE Annual Technical Conterence and Exhibttion, Dallas. Sept. 2 l-24. Smith, C.F., Dollarhide. F.E.. and Byth, N.J.: “Acid Corrosion Inhibitors-Are We Getting What We Need?” J. Pet. Tech. (May 1978) 737-46.
Miller, B.D. and Bergstrom, J.M.: “Results of Acid-in-Oil Emulsion Stimulations of Carbonate Formations.” paper SPE 5648 presented at the 1975 SPE Annual Technical Conference and Exhibition. Dallas, Sept. 28Oct. I.
Smith, C.F., Crowe. C.W.. and Wieland. D.R.: “Fracture Acidizing in High Temperature Limestone.” paper SPE 3008 presented at the 1970 SPE Annual Meeting, Houston. Oct. 4-7.
Moore. E.W., Crowe. C.W., and Hendrickson. A.R.: “Formation, Effect and Prevention of Asphaltene Sludges During Stimulation Treatment,” 3. Pet. Tech (Sept 1965) 1023-28.
Smith, C.F., Crowe, C.W., and Nolan, T.J. III: “Secondary Deposition of Iron Compounds Following Acid Treatments,” J. Pet. Tech. (Sept. 1969) 1121-29.
Muecke, T.W.: “Principles of Actd Stimulation.” Proc.. SPE Intl. Petroleum Conference and Exhibition, Beijing, China (1982) 2. 291-303.
Smith. C.F., Nolan, T.J. III, and Crenshaw, P-L.: “Removal and Inhibition of Calcium Sulfate Scale In Waterflood Projects.” J. Per. Tech. (Nov. 1968) 1249-57.
Norman, L.R., Conway, M.W., and Wilson. J.M.: “Temperature Stable Acid Gelling Polymers. Laboratory Evaluation and Field Results,” paper SPE 10260 presented at the 1981 SPE Annual Technical Conference and Exhibition, San Antonto. Oct. 5-7. Norman. L.R.: “Aqueous Acid Solution Gelling Agents.” Canada Patent No. 1.106.724 (1981). Novotny. E.J.: “Prediction of Stimulation from Acid Fracturing Treatments Using Fintte Fracture Conductivtty.” /. Pet. Tech. (Sept. 1977) 1186-94; Tmns.. AIME. 263. Pablev,, A.S., Ewing. B.C.. and Callawav. R.E.: “Performance of Crosslinked Hydrihlortc Actd in the Rocky Mountain Region,” Paper SPE 10877 presented at the I982 SPE Rocky Mountain Regtonal Meeting. Billings, MT, May 19-21. Pollard, P.: “Evaluation of Acid Treatments From Pressure Buildup Analysts,” 1. Pet Tech. (March 1959) 38-43: Trans.. AIME. 216. Roberts. L.D. and Guin, J.A.: “A New Method for Predicting Acid Penetration Distances,” Sot. Pet. Eng. J. (Aug. 1975) 277-85. Ross, W.M.. Pierson, N.O., and Coulter, A.W.: “Matrix Acidizing Corrects Formation Damage in Sandstones,” Per. Eng. (Nov. 1968) 64-69. Rowan, G.: “Theory of Acid Treatments of Limestone Formations,” J. Inst. Pet. (Nov.
Smith, C.F., Ross, W.M., and Hendrickson, A.R.: “Hydrofluoric Acid Sttmulation-Developments for Field Application,” paper SPE 1284 presented at the 1965 SPE Annual Meeting. Denver. Oct. 3-6. Smith, C.F. and Hendrickson. A.R.: “Hydrofluoric Acid Stimulation of Sandstone Reservoirs.” J. Per. Tech. (Feb. 1965)215-22; Trum.. AIME, 234. Swanson, B.L.: “Well Acidizing Composntons,” 4,240,505 (1980).
U.S. Patent No.
Vivian. T.A.: “Acidification of Subterranean Formations Employing Halogenated Hydrocarbons,” U.S. Patent No. 4,320.014 (1982). Wade, R.P. and Aziz, K.: “Stimulating the Triassic Carbonates in the Foothills Gas Trend of Northeast Brittsh Columbia,” paper 81-32-35 presented at the 1981 CIM Annual Meeting, Calgary.‘May 5-6 Walsh. M.P., Lake. L.W., and Schechter. R.S.: “A Deacriptton of Chemical Precipitation Mechanisms and Their Role in Formation Damage During Stimulation by Hydrofluoric Acid.” fro<. SPE Formation Damage Control Sympostum, Lafayette. LA (1982) 7-27. Watkins, D.R. and Roberts, G.I.: “On-Site Shows HCI and HF Contents Often Varied fied Amounts,” paper SPE 10770 presented Regional Meeting, San Francisco, March
Acidizing Fluid Analysis Substantiallv From Speciat the 1982 SPE California 24-26.
1959) 321-32.
Royle, R.A.: “Demulsifyer for Inclusion in Injected Acidization Systems for Petroleum Formation Sttmulation,” U.S. Patent No. 4.290.901 (1981). Salathrel, W.M. and Shaughnessy, C.M.: “Method for Generating Hydrofluoric Acid in a Subterranean Formation,” U.S. Patent No. 4,136,739 (1979). Scherubel, G.A.: “Method of Controlling Fluid Loss in Acidizing Treatment of a Subterranean Formation.” US. Patent No. 4.237,974 (1980). Scherubel, G.A.: “Self-Breaking Patent No. 1,086,934 (1980).
Retarded Acid Emulsion.”
Canada
Wiley, C.B.: “Success of a High Friction Diverting Gel in Acid Sttmulation of a Carbonate Reservoir, Cornell Unit, Wasson San Andres Field,” .I. Pet. Tech. (Nov. 1981) 2196-2200: Trans.. AIME, 271. Woodroof, R.A. Jr., Baker, J.R., and Jenkins, R.A. Jr.: “Corrosion Inhibition of Hydrochloric-Hydrofluoric Acid/Mutual Solvent Mixtures at Elevated Temperatures,” paper SPE 5645 presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas. Sept. 29-Oct. 1. Young, P.J. and Romocki, J.M.E.: “Well Treating Compositions and Method,” Great Britain Patent No. 2.047,305 (1980).
Chapter 55
Formation Fracturing S.J. Martinez, U. 01 TUIU * R.E. Steanson. DOM~~II Schlumhergcr A.W. Coulter. D oi~cil Schlumherrcr
*:*: * :i;
Introduction Fracturing techniques were developed in 1948 and the first commercial fracturing treatments were conducted in 1949. The process rapidly gained popularity because of its high success ratio, and within a very few years. thousands of wells per year were being stimulated by hydraulic fracturing treatments. Early treatments consisted of pumping 1,000 to 3.000 gal of fracturing fluid, containing about I Ibm of 20/40-mesh sand/gal. at rates of I to 2 bbbmin. Today. a single treatment can require several hundred thousand gallons of fluid and more than a million pounds of propping agent. Although irtjection rates have exceeded 300 bblimin in some instances, rates of 20 to 60 bblimin are about average. Materials, equipment, and techniques have become highly sophisticated. A bibliography is presented at the end of this chapter for those interested in a detailed discussion of particular technologies. This discussion is limited to a generalized description of fracturing theory, materials, techniques, equipment, and treatment planning and design.
Hydraulic Fracturing Theory Oil and gas accumulations occur in the pore spaces or natural fractures of a subsurface rock where structural and/or stratigraphic features form a trap. When a well is drilled into an oil-bearing rock. the fluids must flow through the surrounding rock into the wellbore before they can be brought to the surface. If the pore spaces of the rock are interconnected so that channels exist through which the oil can flow. the rock is “permeable.” The ease wzith which tlutd can how through a rock determines its degree of permeability. It has high permeability ifoil. gas, or water can flow easily through existing channels and
low permeability if the connecting channels are very small and fluid flow is restricted. In the case of high permeability. drilling fluids may enter the flow channels and later impair flow into the wellbore. In the cast of low permeability, the flow channels may not permit enough flow into the wcllbore. In either case. the well may not be commercial because fluid cannot flow into the wellborc fast enough. It then becomes necessary to create an artificial channel that w*ill increase the ability of the reservoir rock to conduct tluid into the wellbore. Such channels often can be crcatcd by hydraulic fracturing. During hydraulic fracturing treatments. what actually happens when a rock ruptures. or fractures. can be ex plained by basic rock mechanics. All subsurface rocks are stressed in three directions because of the weight of overlying formations and their horizontal reactions. Whether one of the horizontal stresses or the vertical stress ia the greatest will depend on the additional stresses imposed on the rock by prior folding. faulting. or other peological movement in the area. These tectonic stresses will control the direction of the fracture and determine wghethcr the fracture plane will be horizontal. vertical, or inclined. Every formation rock has some measure of strength depending on its structure. compaction, and cementation. It has tensile strength in both vertical and horizontal directions. The forces tending to hold the rock together are the stresses on the rock and the strength of the rock itself. When a wellbore is filled with fluid and pressure is applied at the surface, the pressure ofthe fluid in a perforation or even in the port spaces of the rock will increase. This hydraulic pressure is applied equally in all directions. If the pressure is increased, the forces applied by the fluid pressure in the rock will become equal to the forces tending to hold the rock together. Any additional pressure applied will cause the rock to split or fracture. The fracture will extend as long as sufficient pressure is applied by injection of additional fluids.
PETROLEUM
55-2
When the treatment is complete and flow is reversed to produce the well. pressure will gradually return (decline) to reservoir pressure. As this occurs, the force5 tending to hold the rock together come into play again and the fracture will close or “heal.” To prevent closure, some solid material must be placed in the fracture to hold it open. Such materials are called “propping agents.” Since the permeability of these propping agents is much higher than that of the surrounding formation. the ability of the propped fracture to conduct fluids to the wellbore can result in good production increases. In fact, fracturing has made profitable production possible from many wells and fields that otherwise would not have been profitable.
Formations Fractured Fracturing has been used successfully in all formations except those that are very soft. Fracturing has proved successful in sand, limestone, dolomitic limestone, dolomite. conglomerates, granite washes, hard or brittle shale, anhydrite, chert, and various silicates. The plastic nature of soft shales and clays makes them difficult to fracture, Fracturing has helped wells producing from formations that have such a wide range of permeabifities that it is impossible to set upper and lower permeability limits of formations that might be helped by fracturing. Production increases have been obtained from zones having permeabilities ranging from less than 0.1 to as high as 900 md.
Fracture Planes Analysis of pressures encountered on many thousands of fracturing treatments has shown that the bottomhole pressures (BHP) recorded during the injection of fracturing materials range from 0.40 to I .80 psi/ft depth. ’ Only in a few treatments have fracturing pressure gradients been outside of this range. Those were almost all in shallow experimental treatments. The fracture gradient of is calculated from treatment data by Eq. I:
Rf=
where gt p/r p,, pf b
PI! fP> -Pj D )
= = = = =
(1)
unit fracture gradient, psiift, total hydrostatic pressure, psi, total surface treating pressure, psi, total friction loss, psi, and depth of producing interval, ft.
Analysis of thousands of treatments plus experimental work in reservoirs with known fracture gradients indicate that horizontal fractures are produced in reservoirs having fracture gradients of 1 .O or higher. This is generally in shallow wells less than 2,000 ft deep. Vertical fractures are produced in reservoirs having fracture gradrents of 0.7 or lower. Such gradients are normally encountered in wells deeper than 4,000 ft. Very few cases have been found where formations have gradients in the intermediate range between 0.7 and 1 .O. Consequently. the use of fracture gradients to predict the general inclination of fractures should be useful in almost every case.
ENGINEERING
HANDBOOK
With few exceptions. wells in the same reservoir will have nearly identical fracture gradients. Thus. the gradient from one well generally will serve as a guide for the entire pool.
Fracture Area In 1957, Howard and Fast’ presented a mathematical equation to determine the surface area of a newly opened fracture. The equation, based on the quantity of fracturing materials used and the rate at which they are injected into the formation, takes into account the physical characterisitics of the fracturing fluids and the specific reservoir conditions. This equation is: ib A,=--47rK’
e-” .erfc(x) + __
- 1 . I
(2)
where
x =
2K&t b
’
and A, = total area of one face of the fracture at any time during injection. sq ft, i= constant injection rate during fracture extension, cu ft/min, t= total pumping time, minutes, b= fracture width (breadth), ft, K= fluid coefficient, a constant that is a measure of the flow resistance of the fluid leaking off into the formation during fracture operations, and erfc(x) = complementary error function of x. Essentially, during a fracturing treatment, only the volume of fracturing fluid that remains within the wall of the fracture is effective. The fluid that leaks off into the pores of the rock is lost insofar as added fracture extension is concerned. When the width of a fracture is known or assumed (fracture width is normally calculated using either Perkins and Kern3 or Khristianovitch and Zheltov4 models), the volume of the fracture can be calculated. With these data, it is possible to plot the controllable variables of a fluid volume and injection rate against the fracture area produced for any particular fluid coefficient. Examples of such graphs, for various injection rates. are shown in Figs. 55.1 through 55.5. The rate of fluid leakoff into the formation, as expressed by the fluid coefficient, is controlled by three variables: the viscosity and compressibility of the reservoir fluid, the viscosity of the fracturing fluid, and the fluid-loss characteristics of the fracturing fluid.
Reservoir-Controlled Fluids This group includes those fracturing fluids having low viscosity and high fluid-loss characteristics, in which the rate of leakoff is controlled by the compressibility and viscosity of the reservoir fluid.
FORMATION
55-3
FRACTURING
(AVERAGE FRACTURE
FRACTURE SAND FILL,
WIDTH =O.l INCH) THOUSANDS OF LB 60 05 I70
(AVERAGE FRACTURE 255
FRACTURE SAND FILL.
WIDTH=O.I THOUSANDS
425
4 f
26 I,
1,
/
I \
I I /
8 I\
I u
\
\
I\’
INCH) OF LB 170 255 E-100.000 F-250;000
In .”
Fig.
I I 70 FRACTURE
40 AREA,bNE
(AVERAGE FRACTURE 17
FRACTURE SAND FILL, 25 43
I 10 FRACT%
40 AREA,
Fig.
f=cJ RO IO0 200 xl0 500 FACE, THOUSANDS OF SQ FT~ _-
-_
._-
55.1-Effect of fluid coeflicient and volumeon fracture at constant injection rate of 10 bbllmin.
8.5 IO
P
E
GAL
WIDTH =O.l INCH) THOUSANDS OF LB 60 85 I70
Fig.
area
55.3-Effect of fluid coefficient and volume on fracture at constant injection rate of 30 bbllmin.
.8.5
’ ‘X’
S-IO;000 C-25,000 D-50,000 I I II IO FRACT%E
Fig.
\
B-10,000 GAL’ C-25.000 GAL1 I 05O;OOO GAL I I I 10 FRACT::E AREA::NE:
\I
, I I _ “A ,, 200 300 ” 0” 100 :ACE, THOUSANDS OF SO
55.2-Effect of fluid coefficient and volume on fracture at constant inpction rate of 20 bbllmin
FRACTURE
Fig.
area
FRACTURE SAND FILL, 25 43
50BPM I I x
1
area
425
255
500 60 80 100 200 300 ONE FACE, THOUSANDS OF SO FT
(AVERAGE FRACTURE I7
425
.\I\1
ZO,BPM I I
D50.000
GAL GAL
I I GAL’ GAL GAL I
AREA,
ONE FACE,
OF SO FT
55.4-Effect of fluid coefficient and volume on fracture at constant injection rate of 40 bbllmin.
WIDTH : 0.1 INCH) THOUSANDS OF LB 60 85 170
255
425
IhlllN \.
h
IIIIITV 40 60 80 AREA, ONE FACE,
THOUSANDS
\ I ?. 300 500 100 200 OF SQ FT THOUSANDS
55.5-Effect of fluld coefficient and volume on fracture at constant injection rate of 50 bbllmin.
area
area
PETROLEUM
55-4
The coefficient for this type of fracturing dctcrmined from Eq. 3.’
K,.
=0.0374~+
fluid may be
-.
(3) PR
where K, Ap k,, 4,. (‘R PK
= fluid coefficient (compressibility-viscosity controlled), ftimin “, = differential pressure, across the face of the fracture, psi, = effective formation permeability, darcies, = effective formation porosity. 7%. of = isothermal coefficient of compressibility the reservoir fluid, psi -I. and = reservoir fluid viscosity. cp.
Compressibility considerations are generally found to be most applicable in high-pressure, low-volume-factor wells that have high saturations.
Viscosity-Controlled Fluids This group includes those fracturing fluids in which the rate of leakoff is controlled by the viscosity of the fluid itself. The coefficient for this type of fracturing fluid is cxpresscd by Eq. 4.’
where K, = fluid coefficient X,. = 111 =
9, = p, =
(viscosity
controlled),
ftimin ” . cffcctivc formation permeability. darcies, differential pressure across the face of the fracture. psi-this ih the product of the fracture gradient and depth. minus normal reservoir pressure. (,q, XD)-~JR. ct‘fcctivc formation porosity. %. and fracturing fluid viscosity. cp.
‘2r
I 0.5
I
CONDUCTIVITY Fig.
55.6-Increased fracture greater
I
I 5
I
I
I 50
I
RATIO
fracture penetration by containment in the productwe interval can provide production Increases.
of the much
ENGINEERING
HANDBOOK
The effective porosity represents the space in the matrix into which fracturing fluid will leak off. In figuring effective porosity, the effects of residual oil and water saturation should be considered. The permeability factor in the equation almost always will be the permeability ofthe water-wet formation. but it could be that of an oil-wet formation. The average md-ft of exposed section also is considered.
Fluid-Loss-Controlled
Fluids
This group includes fracturing fluids containing special fluid-loss additives designed to reduce the loss of fluid taking place during a fracturing treatment. The fluid coefficient for this type of fracturing fluid is based on Eq. 5’: K,=0.0328z,
111
.
(5)
where K,
= fluid coefficient, wall building (fluid-loss additive), ftimin “, 17~= the slope of the fluid-loss curve, plotting cumulative filtrate volume vs. the square root of flow time, mL/min”. and A = cross-sectional area of test media through which flow takes place. cm2.
In this case, the coefficient is obtained from an experimental test to determine the fluid loss resulting from the use of a particular fluid-loss additive in a particular fracturing fluid. The test must be performed at. or corrected to, bottomhole temperature (BHT) and pressure conditions. Spurt loss is the leakoff occurring while the tluid-retaining wall (filter cake) is being built up. It can bc determined from this test by extrapolating the straightline portion ofthe curve back to zero time on the ordinate. The value at this intercept is the spurt loss.
Stimulation Results The increased production obtained following a fracturing treatment is the result of increased fracture penctration and conductivity. The greater penetration produces a larger drainage area from which reservoir fluids can be produced. Increased fracture conductivity results from the lowered resistance to flow through the fracture. permitting greater production of fluid under reservoir energy conditions. Fig. 55.6> shows the relationship between fracture penetration, fracture conductivity ratio, and production increase. These curves represent fracture penetration as a decimal fraction of the drainage radius. If a good conductivity ratio can be achieved, then a fracture penetrating 100% of the drainage radius can provide as much as a 1%fold increase in the production. Fracture conductivity is controlled largely by propping agent permeability, size. and placement. Strength of the propping agent is also very important, The effect of thcsc properties on fracture conducti\ ity will hc discussed later. Fracture penetration is rclatcd directly to fracture-tluid cll.iclency and containment ot.thc fracture withln the production zone. A good fracturing tluicl should hc trclati\,cI\ IOM in cost and ha1.c low tluid 1~s. IOU friction lo\\.
FORMATION
good proppant transport characteristics. tcmpcraturc stahility. ability to thin for good cleanup, and compatibility with reservoir rock and tluids. Containment of the fracture within the productive interval is a function not only of tluid properties but also of technique.
Fracturing Materials Fracturing
55-5
FRACTURING
Fluids
Fracturing fluids may be divided into three broad divisions: oil based. water based. and mix based. Classitication depends primarily on the main constituent of the fracturing fluid. The aqueous-based fluids are either water or acid. and the mix-based fluids are emulsions.
special crosslinking svstcms and stabtli/ers. The highviscosity gels arc particularly useful in deep well\ bccattsc of their temperature stability. They are able to create wide. deeply penetrating fractures at lower rates and can maintain their viscosity over the longer pumping times rcquircd in deeper wells. Fig. 55.7 shows the viscosity profile ot one such fluid. Two other characteristics of fracturing Iluids normally are reported and are used in computer job design. Thcsc arc the consistency index, I,.. and the behavior index. l,,. The power law model is used to calculate thcsc characteristics. The consistency index is based on pipe tlow gcometry. The power law parameters arc defined as follows: I,, = behavior index; log slope of the shear stress vs. shear rate curve. dimensionless. and I,. = consistency index; shear stress at I set Ibf-see - ’ift’
Oil-Based Fluids. In the past. refined oils, crude oils and soap-type gels of crude, kerosene. or diesel oil wcrc quite common. Because of safety considerations, lack of temperature stability, and cost of tailoring these materials to be efficient fluids, they are seldom used today. A new thickened and crosslinked hydrocarbon gel. made from either light refined oils or crude oil. is used extensively in hydraulic fracturing of oil- and gas-condensate wells producing from reservoirs adversely affected by water or brine. These gels exhibit all the characteristics of an cfficicnt fracturing fluid.
Water-Based Fluids. Gels. Water-based tluids arc natural or synthetic polymer gels of water or hydrochloric acid. They may be either linear or crosslinked gels. The watcrbased fluids are used almost exclusively except in those extremely water-sensitive reservoirs previously mentioned. The popularity of aqueous fluids is based on many factors. including these four: (1) they are safe to handle, (2) their cost is low in comparison to oil-based tluids, (3) they are. or can be formulated to be, compatible with nearly all reservoir fluids and conditions, and (4) they can be tailored to meet almost any treating requirements. Rheological properties, friction pressure. fluid loss, and break time can be closely controlled to provide an efficient fracturing fluid over a wide range of well and rescrvoir conditions. The primary disadvantage of aqueous fluids is that they may not be applicable in formations that are adversely affected by water. Waterfrac services use linear (uncrosslinked) gels of fresh water. salt water, or produced brine as efficient and economical fracturing fluids. Guar and hydroxypropyl guar thickening agents are available to satisfy the rcquirementa of a wide range of reservoir properties. They can be used in either batch- or continuous-mix techniques. A cellulose derivative thickener is available for applications in which fluids with extremely low residue are required. The viscosity of fluids used in waterfrac services is controlled by thickening-agent concentration. High-viscosity fracturing fluids have been developed that contribute directly to wider. better-propped, and more-conductive fractures. Fracture width is increased by increasing the viscosity of the fracturing fluid. Wider fractures permit use of larger proppant, which has grcater permeability. These viscous fluids also have the proppant-transport properties required to carry higher concentrations of proppant deeper into the fracture. They achieve their high viscosity at gel concentrations in the same range as the traditional waterfrac fluids by using
Apparent viscosity is related to the consistency behavior index as follows:
lJL,/=
t.
index and
47.880/,. . ,-, 3 Y ‘I
where PO = apparent viscosity, y = shear rate. see t
cp. and
Since shear history (shear rate and time at shear) adversely affects the rheology of some crosslinked gels. test methods have been developed that more accurately describe the fluids at the time they enter the fracture. Table 55. I compares data developed by the API test method and shear history method.h The data provided by the shear history method give more reliable prediction of friction losses while pumping. Such information is a requisite in job design to predict fracture geometry and reduce
6
TIME.
Fig.
55.7-Viscosity ous gel.
profile
a
1
HR
of high-viscosity,
crosslinked,
aque-
PETROLEUM
55-6
TABLE 55.1-COMPARISON RP39M AND SHEAR HISTORY CONTAINING 30-lbm/l,OOO-gal
Time (hours)
P’F) 225
250
275
*Shear hIstory slmulatlon
I,
0 1 2 4 6 8
-
-
0.570 0.588 0.630 0.672 0.710
0.065 0.045 0.021 0.011 0.0058
0 1 2 4 6 8
-
-
0.656 0.674 0.712 0.752 0.792
0.127 0.019 0.0095 0.0046 0.0024
0 1 4 6 8
0.718 0.740 0.805 0.842
-
0.014 0.010
0.0048 0.0037
Foams.During recent years, foams have become extremely popular as fracturing fluids. Normally classed as water-
RAlf
,
at 170 set-’ 342 259 150 98 63 220 170 103 62 39 157 126 84 79
I,
I
cp at 170 set - ’
0.7512 0.7709 0.7912 0.8309 0.8713 0.9115
o.0017 0.0015 0.0013 0.0009 0.0007 0.0005
23 22 20 18 17 15
0.7306 0.7743 0.8179 0.9044 0.9918 -
0.0021 0.0014 0.0009 0.0004 0.0002 -
25 21 17 11 7 -
0.7156 0.7371 0.7688 -
0.0020 0.0014 0.0009 -
22 17 13
method
the possibility of premature screenout. Figs. 55.8 through 55.13 are examples of friction-loss data for various fluids. In many of the high-viscosity fluids, shear history effects are minimized by using additives to delay crosslinking until the fluid reaches the bottom of the hole. This technique also reduces friction losses since high viscosity does not develop until after the fluid has passed through the tubulars.
FLOW
SHSM’-XL”A” cp
I,
HANDBOOK
OF RHEOLOGY DATA GENERATED BY API METHOD FOR CROSSLINKED AQUEOUS FLUID THICKENER AND lo-lbm/lOO-gal STABILIZER RP39M-XL“A”
Temperature
ENGINEERING
based fluid, foam is a dispersion of a gas, usually nitrogen, within a liquid. A surfactant is used as a foaming agent to initiate the dispersion. Stabilizers are used where high temperatures or long pumping time occur. The volumetric ratio of the gas to the total volume of the foam, under downhole conditions, is called the quality of the foam. Quality is expressed as a number equal to the percentage. A 75-quality foam is 75% gas by volume at downhole temperature and pressure. In fracturing, foam quality usually ranges from 65 to 85 (compositions containing less than 52% gas are not normally stable foams).
bbI/mi~
Fig. 55.8-Typical friction-loss curves for linear gel of fresh water or brine using guar or hydroxpropyl guar thickeners.
Fig. 55.9-Typical friction-loss cellulose thickener
curve
of linear
aqueous
gel using
FORMATION
FRACTURING
0
flow
Fig.
RATE
bbl/min
,
FLOW
55.10-Typical friction-loss curve for crosslinked gel using guar-based thickener.
aqueous
Foam is designed primarily for low-permeability or low-pressure gas wells. However, it may have equal advantages in low-pressure oil wells. In oil wells it may be necessary to use a different foaming agent that is compatible with reservoir fluids and reduces the possibility of emulsions. Some advantages of foam are: (1) good proppant transport, (2) solids-free fluid-loss control, (3) low fluid loss, (4) minimum fluid retention owing to its low water content, (5) compatibility with reservoir fluids, and (6) low hydrostatic pressure of returned fluids, which gives rapid
4-+++: Fig.
RATE
,
10
bbl
55.1 P-Typical friction-loss curve type fracturing fluid.
friction-loss
I ‘01
10 10‘0IPlO99
7
I II
curve
for gelled
Fig.
I 20
1111111 I , 78910
fLOW
dispersion-
bbI/mla
oil fracturing
Mix-Based Fluids. Mix-based fluids are oil-in-water dispersions or emulsions that serve as highly efficient waterbased fracturing fluids.
lmim
for oil-in-water
55.1 l-Typical fluid.
,
cleanup and allows quicker well evaluation (gas in foam helps return liquids to the wellbore). Some disadvantages of foam are: (1) more surface pressure is required because of low hydrostatic head; and (2) there is the added expense of gas, especially under high pressure where volume is reduced.
,b ’ ’’“‘I
x:0 fLOW
Fig.
RATE
RATE
,
I 30
l1llll 40 IO
709090
bbl/m,n
55.13-Typical friction-loss curve for emulsion-type fracturing fluid.
heavy
oil-in-water
0
PETROLEUM
55-8
1 ---Fy--> .... ....,, .
-
am.-, 1,--w -- --_ __ - --:-z-. -q.y.
.. .... .. ._
7
\ ::
Testsrun using aluminumpIties
1.20-40m&ala%
width= 0.3in:
\ 5.oM)
3 5 4
beads
.. 3.20JOmeshexwimentalprop :.4.28-48mesh sxpenmental prop :&20-M meshsinlared bauxlle
andlinear ttow.
2.5w
‘h.. %_
.... 'Y. .. I .-.I
7,5M) 10,000 12.5w
15,ow
17,500 2f
Overburden presrure.pri
Fig. 55.14-Effect of closure stress on permeability of various propping agents.
The viscous emulsions are water-outside-phase emulsions containing two parts oil (crude or refined) and one part water or brine. These arc commonly called “polyand are designed to provide high-viscosity emulsions” fracturing fluids at temperatures up to 350°F. They are seldom used because of fire hazard and cost. A crosslinked gel provides high viscosity in the water volume (95 %a). and a 5 % oil phase is dispersed throughout the mixture to give excellent fluid-loss control properties without requiring the addition of solids. The leakoff control is the result of two-phase fluid flow that reduces the relative permeability of the formation more than conventional fracturing fluids do over a wide permeability range. The fluid is highly efficient even when compared to viscous-emulsion fracturing fluids. Normally. the 5% oil content is low enough to avoid significant effects on either friction pressure or hydrostatic head. even when used with the highly viscous water or brine gels. Fracturing tluid composition is normally proprietary information of the service company supplying it. While competitive iluids are available from most of the service companies, rheological and friction-loss data will vary according to the fluid. Therefore. handbooks provided by the service companies should bc used to obtain data for job design.
Propping
Agents
Propping agents are used to maintain fracture-flow capacity after completion of a hydraulic fracturing treatment. The amount of proppant used, the manner in which it is placed in the fracture, and the properties of the material itself all play a vital role in maintaining productivity throughout the life of the well, The selection of the propping agent and scheduling of the proppant during the treatmcnt are important parts of the overall completion and treatment design. The ux physical properties of propping agents that affeet the resultant fracture conductivity are grain strength. grain roundness t’ac2crrain size. grain size distribution, tor. quality (amount of fines and impurities). and proppant density
Grain Strength.
While all thcsc physical properties have ;I decided cffcct on fracture conductivity. quality standards
ENGINEERING
HANDBOOK
have been established so that the main considerations are grain strength and grain size. If a proppant is not strong enough to withstand closure stress of the fracture, it will crush. and permeability will be reduced greatly. Also, as reservoir pressure is reduced by fluid production, the closure stress will increase. Therefore, it is important that proppant strength be selected for the stress that will be present during the later life of the well. Fig. 55. I4 shows the effect of closure stress on permeability of various propping agents when the formation is a hard, competent rock. Sand is an acceptable propping agent at closure stresses up to 6,000 psi. At stresses greater than this, high-strength proppants such as sintered bauxite particles or plasticcoated sand grains should be used. In soft formations, the proppant will tend to embed into the formation under closure stress and reduce fracture width. This, in turn, reduces fracture flow capacity. In the past, deformable proppants such as rounded walnut shells and aluminum pellets have been used in an attempt to overcome this problem. By deforming or spreading out, these proppants presented a larger surface area to the fact of the fracture and resisted embedment. The low density and malleability of these proppants caused both pumping and placement problems, and they were never widely acceptcd. There was also a corrosion or oxidation of the aluminum that resulted in loss of pack permeability. A better solution to embedment is a wide. packed fracture. In such a fracture, width reduction resulting from embedment is a small percentage of total fracture width, and adequate flow capacity is maintained even after embedment occurs.
Grain Size. A large proppant grain size provides a tnore permeable pack under low closure stress conditions and can be used in shallow wells. However. dirty formations or those subject to significant fines migration are poor candidates for large-size proppants. The fines tend to invade the proppant pack. causing partial plugging and rapid reduction in permeability. In these cases. smaller sizes of proppant that resist invasion of fines are better. Larger gram sizes are generally not considered for deeper wells because of greater susceptibility to crushing. Proppant Placement. The manner in which a propping agent is placed in a fracture is also important. As previously stated, soft or high-permeability formations need a wide, fully packed fracture. In very-low-permeability formations, only a thin fracture may be necessary. However. fracture length becomes important in such formations because the greater the surface arca of formation exposed to the propped fracture, the greater the volume of oil or gas that can drain into the fracture. Since fluid enters the fracture along its entire length. long fractures must be wider at the wellbore than at the tip to accommodate the increasing amount of fluid as the fracture nears the wellbore. To accomplish this fracture geometry. the proppant must be scheduled so that its concentration in the fracture fluid increases steadily as the treatment progresses.
Fracturing Techniques Although fracturing treatments usually arc pctformcd by pumping materials down the casing or tubing at rates as high as well limitations and economics will permit. spc-
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cial techniques sometimes are used to help control vertical fracture growth. Such control is directly related to fracturing efficiency. In the case of massive zones, adequate fracture height to cover the entire zone is desirable. With narrow zones, containment of the fracture within the productive zone improves efficiency and penetration and prevents fracture growth into undesirable zones. While vertical growth can be controlled to some extent by controlling injection rate. more sophisticated techniques are required for optimum efficiency. A Limited Entry@ technique involves designing the number and size of perforations to match an economically feasible pump rate so that all perforations are forced to accept fluid during the treatment. Another specialty technique to limit downward growth of a vertical fracture involves building an artificial lower barrier. This is done by using low injection rates and fluids with poor proppant transport characteristics at the beginning of the treatment. Propping agent can create a proppant pack at the bottom of the fracture. A pressure drop will exist across this pack and will divert the fluid that follows outward and upward, thus slowing or even stopping downward fracture growth. Similarly, a buoyant propping agent can create an artificial upper barrier by floating to the top of the fracture and bridging to form a proppant pack. In this case also, the pressure drop across the pack will force subsequent fluids outward to increase fracture length.
Multiple-Zone Fracturing Whcrc multiple zones are open to the wellbore. mechanical devices such as packers or bridge plugs can be used to isolate zones so that each can be treated individually. Where it is desirable to fracture more than one zone in a single treatment, sized particulate materials or perforation ball sealers can be used. The particulate materials usually are suspended in a viscous fluid and filter out at the fracture entrance. After treatment, they generally flow back with produced fluids. They also can break down through chemical reaction. Ball sealers seat in perforations and divert fluid flow. They are unseated by reverse flow and either fall to the bottom or are produced along with the returning fluids. When ball sealers are used. a mechanical device to catch the balls should be used at the surface to prevent the balls from plugging valves or other surface equipment.
Fracturing Equipment Hydraulic fracturing equipment consists of pumps and blenders. high-pressure manifolds and treating line, remotely controlled master valves, and tree savers. Pumping equipment is the conventional triplex pump. quintaplex pump. or a pressure-multiplier type of pump. The latter employs an entirely different putnping concept from the triplex pump. It operates by using a low-pressure working fluid to push a large piston. This large piston is directly connected to a smaller piston, or ram, which handles the treating fluid. Because of a slow cycle speed. the pressure multiplicrs are capable of long pumping times at high pressures. Both the triplex and pressure multiplicr arc capable of high-pressure operation. Above 12.000-psi treating pressure, however. the multiplier is prcfcrred. Thcsc units are capable of operating at prcshutch slightly in cxccss of 70.000 psi.
Individual pumping units are powered by engines ranging from less than 100 to more than 1,300 hp. For high horsepower requirements, multiple units are used. Fluids used in hydraulic fracturing are mixed in blenders. They are either batch mixed before a job and stored in tanks on location or continuously mixed during the job. Blenders are capable of metering both dry and liquid additives into a fluid, mixing the fluid and additives, and metering and mixing propping agent into the fluids. After mixing and blending, the slurries are supplied by the blender to the suction on the high-pressure pumps under pressure. Blending units capable of handling volumes in excess of 100 bblimin are available. Liquid nitrogen is the gas normally used for foam or energized tluid. Special transport and pumping equipment is required to handle the nitrogen, which generally is metered into the treating line on the downstream (highpressure) side of the triplex or multiplier pumps. Another piece of equipment recently added to fracturing fleets is the treatment monitoring vehicle. This vehicle gathers data, uses a computer to analyze them. and presents the results as they occur, or in “real time.” The data are presented by a printer, plotter, and on a CRT screen. Real-time analysis and presentation of data allow positive control of a treatment. Ample warning of problems normally is available so that changes can be made to permit successful completion of the job. Also. the equipment can be used to monitor a tninifrac job before the main treatment. Analysis of the minifrac can either verify job design or indicate needed design changes before the main treatment.
Treatment Planning and Design Success of a hydraulic fracturing treatment depends on creating a deeply penetrating, highly conductive fracture in the producing zone. Research, engineering studies, and experience have provided reliable planning or treatment design guides. Job calculations with these guides are based on reservoir conditions, laboratory tests. theoretical data. well information, and experience in a given area. Most service companies and many oil-producing companies have job-design calculations computerized to aid in rapid and accurate design comparisons. Special computer programs are available also to calculate tubing expansion and contraction, bottomhole cool-down (fluid temperature at the wellbore and in the fracture), proppant scheduling to provide best propped fracture geometry, and anticipated productivity increase. Evaluating and selecting optimal treating conditions for any individual well includes several steps. First, accurate reservoir and well-completion data must be accumulated to provide a sound basis for engineered treatment preplanning. Next, the fracture area and the extent of formation penetration necessary to provide the desired productivity increase are calculated. The fracture conductivity. as related to the permeability of the matrix, is detertnined also. After this. the comparative efficiency of various fracturing fluids, based on specific well conditions. is dctermined. as well as the volumes and injection rates necessary to provide the desired fracture extension. Horsepower rcquirements for each type of treatment then can be calculated; and fracturing materials and tcchniqucs can be sclccted that. theoretically. will most cf’ficicntlv and eco-
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nomically produce the desired productivity increase. Only when all these factors are considered collectively can a well-integrated fracturing treatment be carried out.
HANDBOOK
and K, =0.001076;,
...... ....
..
...
. .(5)
Nomenclature A= A, = b= CR = D= erfc(x) = gf = i= Ill = I,. = k, = K=
K,. = K, = K,. = m=
P.f = P/r = PR
=
P.,
=
Ap =
cross-sectional area of test media through which flow takes place, cm* total area of one face of the fracture at any time during injection, sq ft fracture width (breadth), ft isothermal coefficient of compressibility of the reservoir fluid, psi - ’ depth of producing interval, ft complementary error function of x unit fracture gradient, psi/ft constant injection rate during fracture extension, cu ftlmin behavior index; log slope of the shearstress vs. shear-rate curve, dimensionless consistency index: shear stress at 1 set-‘, lbf-set - ’ift 2 effective formation permeability, darcies fluid coefficient, a constant that is a measure of the flow resistance of the fluid leaking off into the formation during fracture operations fluid coefficient (compressibility-viscosity controlled), ft/min ‘X fluid coefficient, wall building (fluid-loss additive), ft/min ‘X fluid coefficient (viscosity controlled), ft/min % slope of fluid-loss curve, plotting cumulative filtrate volume vs. square root of flow time, mL/min” total friction loss, psi total hydrostatic pressure, psi normal reservoir pressure, psi total surface treating pressure, psi differential pressure across face of fracture, psi total pumping time, minutes shear rate, set -’ apparent viscosity, cp fracturing fluid viscosity, cp reservoir fluid viscosity, cp effective formation porosity, %
Key Equations
in SI Metric Units
where K,.,K,,
and K, are in m/s I’, Ap is in kPa, k, is in pm*, 4, is in percent, CR is in kPa-‘, pR is in Pa’s, m is in mL/s’, and A is in m*.
References 1. Hurst, R.E.. Franks. J.E., and Rollins, J-T.: “Horsepower Requirements for Well Stimulation.” Drill Blr (Oct. 1958) 25. 2. Howard, G.C and Fast. C.R.: Hydmulic Frcrcturin~. Monograph Series, SPE, Richardson, TX (1970) 2. 3. Perkins, T.K. Jr. and Kern, L.R.: “Widths of Hydraulic Fractures.” J. Pet. Tech. (Sept. 1961) 937-49; ‘firms.. AIME. 222. 4. Khristianovitch, S.A. and Zheltov, Y.P.: “Formation of Vertical Fracture by Means of Highly Viscous Fluids.” Proc., Fourth World Pet. Coni., Rome (1955) i. 579. 5. McGuire, W.J. and Sikora, V.J.: “The Effect of Vertical Fractures on Well Productivity,” J. Pet. Terh. (Oct. 1960) 72-74: Truns., AIME. 219. 6. Cralgie, L.J.: “A New Method for Determining the Rheology of Crosslinked Fracturing Fluids Using Shear HIstory Simulation,” paper SPE 11635 presented at the 1983 SPElDOE Low-Permeability Gas Reservoirs Symposium, Denver, March 14-16.
General References Abou-Sayed, A.S.: “Laboratory Eraluation of In-Situ Stress Contrast in Deeply Buried Sediments,” paper SPE I1069 presented at the 1982 SPE Annual Technical Conference and Exhibition. New Orleans, Sept. 26-29. Abou-Sayed, AS.. Ahmed, U., and Jones. A.: “Systematic Approach to Massive Hydraulic Fracturing Treatment Design.” paper SPE 9877 presented at the 1981 SPEiDOE Low-Permeability Gas Reservoirs Symposium, Denver, May 27-29. Agarwal. R.G.. Carter, R.D., and Pollock. C.B.: “Evaluation and Performance Prediction of Low-Permeability Gas Wells Stimulated by Massive Hydraulic Fracturing,” J. Pet. Tech. (March 1979) 362-72. Ahmed, U., Strawn, J., and Schatz. J.: “Effect of Stress Distribution on Hydraulic Fracture Geometry: A Laboratory Simulation Study in One-Meter Cubic Blocks,” paper SPE II637 presented at the 1983 SPEiDOE Low-Permeability Gas Reservoirs Symposium. Denver. March 14- 16. Ahmed. U. et ul. : “State-of-the-Art Hydraulic Fracture Stimulation Treatment for a Western Tight Sand Reservoir,” paper SPE I 1 I84 presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 26-29. Ainley, B.R. and Charles, G.J.: “Fracturing Using a Stabilized Foam Pad,” paper SPE 10825 presented at the 1982 SPEIDOE Unconventional Gas Recovery Symposium, Pittsburgh. May 16-18.
K,. = 1.9203 x 10 -4 Ap
kc 6 6,CR
. . (3)
, ...
LLR
K,.=2.41~10-~
k,ApO, p, ..,..,,,
.
. (4)
Almond. S.W.: “Factors Affecting Gelling-Agent Residue Under Low Temperature Conditions.” paper SPE 10658 presented at the 1982 SPE Formation Damage Control Symposium, Lafayette. March 24-25. Aron. J. and Murray, J.: “Formation Compressional and Shear Interval Transit-Time Logging by Means of Long Spacings and Digital Techniques,” paper SPE 7446 presented at the 1978 SPE Annual Technical Conference and Exhibition, Houston. Oct. l-4. ,
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Baumgartner. S.A. 68,crl.: “High-Efliciency Fracturing Fluids for HighTemperature. Low-Permeability Reservoit?.” paper SPE I IhlS presented at the 1983 SPElDOE Low-Permeability Gas Reaervolrs Symposium, Denver. March 14-16. Bennett, C.O.. Reynolds. A.C.. and Raghavan. R.: “Analysisof Finite Conductivity Fractures Intercepting Multilayer Re.servoirs.” paper SPE 11030 presented at the I982 SPE Annual Technical Conference and Exhibition. New Orleans, Sept. 26-29. Bennett, C.O. et ul.: “Performance of Finite Conductivity Vertically Fractured Wells in Single-Layer Reservoirs,” paper SPE IlO2$ presented at the 1982 SPE Annual Technical Conference and Exhibiiion. New Orleans. Sept. 26-29 Callahan, M.J.. McDaniel, R.R.. and Lewis. P.E.: “Application of a New Second-Generation High-Strength Proppant in Tight Gas Reservoirs.” paper SPE II633 presented at the 1983 SPEiDOE LowPermeability Gas Reservoirs Symposium, Denver, March l4- 16. Cinca-Ley. H.: “Evaluation of Hydraulic Fracturing by Transient Pressure Analysis Methods.” paper SPE 10043 presented at the 1982 SPE Intl. Petroleum Exhibition and Technical Symposium. Beijing. March 19-22. Cinco-Ley, H. and Samaniego-V.. F.: “Transient Pressure Analysis for Fractured Wells.” J. Per. Tech. (Sept. 1981) 1749-66.
Cutler. R.A of rrl. : “Comparison of the Fracture Conductivity of Commcrcially Available and Experimental Proppants at Intermediate and High Closure Stresses.” Sot,. Pet.&g. J. (April 1985) 157-70. Daneshy. A.A.: “On the Design of Vertical Hydraulic Fractures.” J. Per. Twh. (Jan. 1973) 83-97: Trcrns., AIME. 255. Daneshy. A.A.: “Numerical Solution of Sand Transport in Hydraulic Fracturing.” J. Pet. Tech. (Jan. 1978) 132-40. Daneshy. A.A.: “Hydraulic Fracture Propagation in Layered Formatmns.” Ser. Pet. Eq. J. (Feb. 1978) 33-41. Daneshy, A.A. E( al.: “Effect of Treatment Parameters on the Geometry of a Hydraulic Fracture,” paper SPE 3507 presented at the I97 I SPE Annual Meeting, New Orleans, Oct. 3-6. Dobkins. T.A.: “Improved Methods to Determine Hydraulic Height,” J. Pet. Tech. (April 1981) 719-26.
Fracture
Elkins. L.E.: “Western Tight Sands Major Research Requirements.” paper presented at the 1980 lntl. Gas Research Conference. Chicago, June 9-12. Fertl. W.H.: “Evaluation of Fractured Reservoir Rocks Using Geophysical Well Logs,” paper SPE 8938 presented at the 1980 SPEiDOE Unconventional Gas Recovery Symposium. Pittsburgh. May 18-21.
Clark. J.A.: “The Prediction of Hydraulic Fracture Azimuth Through Geological. Core. and Analytical Studies.” paper SPE I I61 I presented at the 1983 SPEiDOE Low-Permeability Gas Reservoirs Symposlurn. Denver, March 14-16.’
Gardner, D.C. and Eikerts, J.V.: “The Effects of Shear and Proppant on the Viscosity of Crosslmked Fracturing Fluids.” paper SPE II066 presented at the 1982 SPE Annual Technical Conference and Exhibitmn. New Orleans, Sept. 26-29.
Clark. P.E. and Quadir. J.A.: “Proppant Transport in Hydraulic Fractures: A Critlcai Review of Particle Settling Velocity Equations,” paper SPE 9866 presented at the 1981 SPEiDOE Low-Permeability Gas Reservoirs Symposium, Denver, May 27-29.
Geertsma, J. and de Klerk. F.: “A Rapid Method of Predicting Width and Extent of Hydraulically Induced Fractures.” J. Pet. Tech. (Dec. 1969) 1571-81; Trm~r.. AIME. 246.
Clark, P.E. and Guler. N.: “Proppant Transport in Vertical Fractures: Settling Velocity Correlations.” paper SPE I1636 presented at the 1983 SPElDOE Low-Permeability Gas Reservoirs Symposium, Denver, March 14-16. Cleary. M.B.: “Analysis of Mechanisms and Procedures for Producing Favorable Shapes of Hydraulic Fractures,” paper SPE 9260 presented at the 1983 SPE Annual Technical Conference and Exhibition, Dallas. Sept. 21-24. Cleary. M.P., Kavvadas, M.. and Lam, K.Y.: “A Fully ThreeDimensional Hydraulic Fracture Simulator,” paper SPE 1163 I presented at the 1983 SPEiDOE Low-Permeability Gas Reservoirs Symposium. Denver. March 14-16. Clifton, R.J. and Abou-Sayed. A.S.: “A Variational Prediction of the Three-DimensIonal Geometry of tures , ” paper SPE 9879 presented at the 1981 Permeability Gas Reservoirs Symposium, Denver,
Approach to the Hydraulic FracSPElDOE LowMay 27-29.
Cloud. J.E. and Clark, P.E.: “Stimulation Fluld Rheology 111. Alternatives to the Power Law Fluid Model for Crosslinked Gels,” paper SPE 9332 presented at the 1980 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 21-24. Conway, M.W. and Harris, L.W.: “A Laboratory and Field Evaluation of a Technique for Hydraulic Fracturing Stimulation of Deep Wells,” paper SPE 10964 presented at the 1982 SPE Annual Technical Conference and Exhtbition, New Orleans, Sept. 26-29. Cooke, C.E. Jr.: “Effect of Fracturing Fluid on Fracture Conductlvity,” J. Per. Tech. (Oct. 1975) 1273-82.
Geertsma. J. and Haafkens, R.: “A Comparison of Theories for Predicting Width and Extent of Vertical Hydraulically Induced Fractures.” Trans.. ASME (1979) 101. 8-19. Govier. G.W. and Aziz, K.: The F/or\, ofCo!np/er Mirrures Van Nostrand Reinhold Co., New York City (1972).
in Pipes.
Guppy. K.H., Cinco-Ley, H.. and Ramey, H.J. Jr.: “Pressure Buildup Analysis of Fractured Wells Producing at High Flow Rates,” J. Pet. Tdz. (Nov. 1982) 2656-66. Hall, C.D. Jr. and Dollarhide. F.E.: “Performance of Fracturing Fluid Loss Agent< Under Dynamic Conditions,” J. fit. Tech. (July 1968) 763-68; Trans.. AIME, 243. Hanson, J.M. and Owen, L.B.: “Fracture Orientation Analysis by the Solid Earth Tidal Strain Method,” paper SPE II070 presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans. Sept. 26-29. Hanson. M.E. ef al.: “Some Effects of Stress, Friction. and Fluid Flow on Hydraulic Fracturing,” Sot. Pet. Eng J. (June 1982) 321-32. Harrington, L.J., Hannah. R.R., and Beirute, R.: “Post-Fracturing Temperature Recovery and Its Implication for Stimulation Design.” paper SPE 7560 presented at the 1978 SPE Annual Technical Conference and Exhibition, Houston, Oct. l-4. Harrington, L.J., Hannah, R.R , and Williams. D.: “Dynamic Expertments and Proppant Settling in Crosslinked Fracturing Fluids.” paper SPE 8342 presented at the 1979 SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 23-26. Harris, P.C.: “Dynamic Fluid-Loss Characteristics of Foam Fracturing Fluids,” paper SPE II065 presented at the 1982 SPE Annual Technical Conference and Exhibition. New Orleans. Sept. 26-29.
Crawley, A.B.. Northrup, D.A.. and Sattler, A.R.: “The U.S. DOE West&n Gas Sands Project Multiwell Experiment Updates.” paper SPE I I183 presented at the 1982 SPE Annual Technical Conference and Exhibition. New Orleans, Sept. 26-29
Hurst, R.E.: “An Engineered Method for the Evaluation and Control of Fracturing Treatments.” &-i/i & Prod. Prcrc., API (1959) 168-76.
Cutler. R.A. er al. : “New Proppants for Deep Gas Well Stimulation.” paper SPE 9869 presented at the 1981 SPEiDOE Low-Permeability Gas Reservoirs Symposium. Denver. May 27-29.
King. G.E.: “Factors Affecting Dynamic Fluid Leakoff with Foam Fracturing Fluids.” paper SPE 6817 presented at the 1977 SPE Annual Technical Conference and Exhibition, Denver. Oct. 9-12.
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HANDBOOK
Lcx~rboura. J.A.. Sif’lrman. T.R and Wahl. H.A : “Evaluation ot Frscturlng Fluid Stnbillty Usins 1 Heated Pres~ur~zccl Flow Loop.” Srr. for. EQ. .I. (June 1984) 24Y-55.
Smtth. M.B.: “Stimulation Design l’or Short. PI-cctw Hqdraullc Fractures-MHF.” p;iper SPE LO>13 prewntcd jlt the the lY81 SPh Annual Techntcal Conlcrcncc and Exhibition. San Antonio. Oct. 1-7.
McDaniel. R.R.. Deywrher. A.K.. trnd Calluntn. M.J : “An Improved Method lor Meawrtnf Flutd Los5 ut Stmulated Fracture Condtttonh.” .Sm Per. hq. J. (Au:. 1985) 4X2-90.
Smtth. M.B.. Logan. J.M.. ;tnd Wood. M.D.: “Fracture Afttnulh--,A Shallow Experiment.” 71n/r.j., ASME (June IYXOI 102. YY- 105.
McLcwi. H.O. Jr.: “A Simplified Apprcwh to Design of Fracturing Trcntmcnt\ Li\ing High-Vihcwitg Crosslinked Fluids.” paper SPE II614 prewntcd at the 1983 SPEiDOE Lcw-Permeability Gab Rexr\mr\ Sympo\tum. Denver. March 14- 16. Neal. E.A.. Parmley, J.L.. and Colpoy\, P.J.: “Oxide Ceramic Proppant\ liv Treatment of Deep Well Fractures.” paper SPE 68 16 presentcd at the 1977 SPE Annual Technical Conference and Exhthttion, Denber. Y-12. Noltc. K.G.: “Dutcrmtnation of Fracturing Paramrter~ t’rom Fracturtng Prehwre Dechne.” pqxr SPE 8341 presented at the I979 SPE .Annual Tcchniwl Conference and Exhibition. Las Vegas. Sept. 23-26. Noire. K.G.: “Fracture Design Considerations Based on Preawre Anal>\is.” paper SPE IO91 I presented at the 1982 SPE Cotton Valley Sympwiurn. Tyler. TX. May 20. Noltc. K.G. and Smith. M.B.: “lntcrprctation J. PC/. Tdl. (Sept. 19X1) 1767-75.
trl’Fracturtng Prehsurc\.”
Nord~rcn. R P : “Propagation ol ;L Verttcal Hydraulic PC/. hy J. (Aug. 1972, 306-14.
Fracture.” Sex,
Palmer. I.D. and Carroll. H.B.: “Three~Dimen~ionaI Hydraulic Fractuw Propag;ltion m the Prcwwc of Strc\\ Variations.” Sw. Prv t‘r~,~. J. (Dec. iY83) 870-78. Palmer. I.D. and C;~mmll. H.B.: “Numerical Solution tar Height of Elonewted Hvdraultc Fracturch with LeakoH‘.“ paper SPE I1627 presentcd itt the 1983 SPE!DOE Low-Permeability Gas Reservoirs Sympostum. Denver. March 14-16. Pcnq. G.S.: “Nondama$~~ Fluid-Los\ Additive\ for Ux in Hydraulic Fr;tcturing of Ga\ Wells.” paper SPE 1065’) presented at the 1982 SPE Formawn Damage Control Symposium. Lafayette. March 24-25. Roprs. R.E.. Veatch. R.W.. and Noltc, K.G.: “Pipe Viwmeter Study 01’Fracturing Fluid Rheolop) .” Sw. Pcv. BI,~. J. (Oct. 1084, 575-81. Roscnc. R.B. and Shumakcr. E.G.: “Viscws Fluid\ Prwldc Improved Rewlt\ from Hydraulic Fracturmg Treatmentr.” paper SPE 3347 prewnttxl al rhc IY7 I SPE Rocky Mountw~ Regional Meeting. Blllmps, MT. June 2-3. Roxpilcr. M.H.: “Determination of Princtple Strcsw and the Cmt’mcmt‘nt 01‘Hydraulic Fracturea tn Cotton Valley.” paper SPE 8405 presented at the 1979 SPE Annual Technical Conference and Exhibit,on. La\ Vegas. Sept. 23-26. Settari. A.: “Simulation of Hydraulic Fracturing Proceases.” Srw. Pcv. 15t.y. J. (Dec. 1980) 487-500. Scttari. A.: “Quantitative Analysis of Factors Controlling Verttcal Fracturc Growth (Containment).” paper SPE I I629 presented ill the lYX3 SPEiDOE Low-Permc;thility Gas Reservoir\ Symposium. Denver, March I-1- 16. Settarr. A.: “A New General Model of Fluid Losz, in Hydraultc turing.” Sot. Prr. +q. J. (Aug. 1985) 491-501.
Frac-
Stnclatr. A.R.: “Heat Trawtcr Eft’ects in Deep Well Fracturm:.” P<,r. T<,
.I.
Smith. M.B.. Rosenberg. R.J.. and Bowen. J.F.: “Fracture Width: DC\ign \i\. Mcawremcn~.” paper SPE 10965 prcwntcd at the IOX2 SPE Annual Technical Conl’erencc and Exhibition. New Orlcan~. Sept. 26-29. Thomas. R.L. and Elhul. J.L. “The Use 01 Vtw)$ Stuhlli/~r\ m High Temperature Fracturing.” paper SPE X344 presented at the lY7Y SPE Annual Technical Cont’crcnce and Exhlhition. Las Veg”h. Sept 23-26. Teufel. L. W.: “Determination 01‘lwSitu Stressw t’rum Anelawc Stram Recovery Measurements ol’orientcd Core: Appltcation\ to H!draulic Fracturing Treatment Design.” paper SPE I t h49 pre\entctl at the 19X3 SPElDOE Low-Pcrmcahilit) Ciao Re\ervwr\ Symportum. Dcnvu. March 14-16. Teutel. L.W. and Clark. J.A.: “Hydrattllc Frxturc Propagatwn m Layered Roth: Experimental Studie 01‘Fracturc Contammcnt.” S,w. PC/. OI,~. I. (Feb. 1984) 19-32. Thiercelin. M. and Lemancryk. .R “The Etiect of Stre\s Gradvmt on the Height ot Vertical Hydraulic Fractures.” pap! SPE I I626 prlxntv ed at the IYX3 SPEIDOE Low-Pcrmcuhilil) Ga\ Rswt-I air\ Sympo\ium. Denver. March 14-16. Tin\lev. J.M. (‘I rrl.: “Vertical Fmcturc Hetcht-it> Et’rcct I,” Stcad\~ State Productton Increase.” J. PC,. 7iTh. (ii,) IYhY) 633-38: />tr,,;.. AIME. 246. wn Poollcn. H.K.. TimIcy. J.M.. and Saundcrh. C.D. “H>draultc Frncturins-Fracture Flow Capacltg w. Well Prwlucttvtty.” J. PC/. 7isof Production Tot> of Hydraulically Fractured Well+ in a Tight Solutton Gas-Drive Rtwxwrlr.” paper SPE I1084 presented at the 1982 SPE Annual Technical Ccmlcrcncc and Exhibition. New Orleans. Sept 26-29. Warpmskt. N.R. (‘I (I/.: “L;lhoratory Investigatwn on the Ellect of In+ Situ Strcahes on Hydraulic Fracture Containment.” .‘+I. Prr. E/IX. J. (June 1982) 333-40. Waters. A.B.: “Hydraulic lY81) 1416.
Fracturing-What
I\ It?” J Pcv. ‘li>~./~.(Aug.
Wendorft’. C.L.: “Frac Sand Quality Control-A Muht tar Good Frac Treatments.” paper presented at the 1978 ASME Petroleum Div. Annual Meeting. Houston. Nov. 5-9. Wheeler. J.A.: “Analytical Calculations of Heat Tran\l& Iron1 Fractureh,” paper SPE 2494 presented at the lY6Y SPE Improved Oil Recovery Symposium, Tulsa. April I.?- IS. White. J.L. and Daniel. E.F.: “Key 7&/r. (Aug. 1981) 1501-12.
Factors in MHF Dchisn.” J. PCI.
Whitsitt, N.F. and Dysart. G.R.: “The Ellcct oITempcraturc on Sttmw lation Design.” J. &r. Twh. (April 1970) JY3%501: Inrrt$. AIMS. 249. Wood. M.D. (21trl.: “Fracture Proppant Mapptng Usin: Surtace Sttperconducting Magnetometers,” paper SPE II617 pre\ented at the 1983 SPElDOE Low-Pcrmcahility Gas Rcwwirh Symposium. Denver, March 14-16.
Chapter 56
Remedial Cleanup, Sand Control, and Other Stimulation Treatments A.W. Coulter Jr., Dwell Schlumberger* S.J. Martinez, Information Services Div., U. of Tulsa* K.F. Fischer, Dwell Schlumberger*
Introduction Although fracturing and acidizing are the most common types of well stimulation used today, other types of stimulation treatments also are used. Some of these treatments use acid-type materials but are not generally classed as acidizing jobs. These treatments are specifically designed for the removal of a blocking agent such as gypsum (gyp), drilling mud. paraffin, formation silicate, particles, or other materials on the wellbore face and in the formation immediately adjacent. The first stimulation treatments used in oil and gas wells involved explosives such as dynamite or nitroglycerin. This method was used for many decades before being discontinued for safety reasons. More recent attempts to stimulate with explosives involved displacement of explosive material into the producing formation in a fracturetype treatment. The material was then detonated. Because this method was hazardous, research involving explosives has been discontinued.
Reperforation In some cases it is useful to reperforate a well in the same zone in which it was originally perforated. The detonation of the gun loosens blocking materials in the formation adjacent to the well and in the previous perforations, and simultaneously creates more drainage holes into the wellbore. Also, over a period of time, some of the original perforation tunnels might become totally blocked by migratory fines, scale, gyp, or paraffin. Reperforation in such cases could greatly increase drainage area into the wellbore.
Abrasive Jet Cleaning Another method used to clean up shot holes or to remove gyp contaminating the formation near the wellbore makes
use of a jetting tool. One or more streams of sand-laden fluid are forced through a hardened, specially designed nozzle at pressures of 1,000 psi and up, to impinge against the wall of the borehole. These jets, striking against the face of the open hole, loosen and break up gyp deposits, and may penetrate the formation. If the tool is moved up and down while jetting, the entire borehole can be cleaned. This same tool may be used for perforating pipe; the high-pressure jets of sand-laden fluid are able to cut through %-in-thick steel pipe in 15 to 30 seconds. They can then penetrate the formation to a depth of 12 or 15 in. in another 5 minutes or so, forming large unobstructed channels for the production of reservoir fluids.
Mud Removal Several materials are used to remove drilling mud from the borehole and the adjacent formation. The most commonly used material is a mud-dissolving acid consisting of inhibited hydrochloric acid (HCI) with an added fluoride. This material dissolves part of the mud and loosens the remainder so that it may be flushed out. Mud-removal agents are often used ahead of fracturing, acid jobs, or cement, to clean the face of the pay, to allow a lower breakdown pressure, and to minimize mud contamination. Acid cleanup solutions, containing special surfactants that increase penetration and provide special muddispersing properties, are also used when an infiltration of mud into the formation is suspected. Other solutions, containing phosphates or other chemicals, may be used to loosen and disperse mud particles so they can be more easily flushed from their position in or adjacent to the wellbore. Special blends of surfactants, iron chelating agents, and mud-dispersing agents also have been effective in removing mud from the formation.
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Water Blocks and Emulsions Oil- and/or water-based solutions containing low-surfacetension, emulsion-breaking agents have been used successfully to remove water blocks or emulsions from a formation. More recently, solutions of special surfactants and alcohols have become popular. These materials are pumped into the formation to contact the water or emulsion block. By changing the blocking material’s physical characteristics, the solution enables the blocking fluid to be produced. Treatments of this type usually consist of a specialized, commercially available product with an oilcarrying agent. If a large zone is to be treated, diverting agents, ball sealers, or packers should be used to ensure that the solution contacts the blocking fluids. Otherwise, the chemicals will probably enter the more permeable and nonblocked portions of the formation and miss the blockage completely.
Scale Deposits When a well produces some water, gyp deposits may accumulate on the formation face and on downhole equipment and thereby reduce production. These deposits may have low solubility and be difficult to remove. Solutions of HCI and ethylenediaminetetraacetic acid (EDTA) can often be used to remove such scales. Soluble portions of the scale are dissolved by the HCl while the chelating action of EDTA breaks up and dissolves much of the remaining scale portions. When deposits contain hydrocarbons mixed with acid-soluble scales, a solventin-acid blend of aromatic solvents dispersed in HCl can be used to clean the wellbore, downhole equipment, and the first few inches of formation around the wellbore (critical area) through which all fluids must pass to enter the wellbore. These blends are designed as a single stage that provides the benefits of both an organic solvent and an acid solvent that contact the deposits continuously.
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HANDBOOK
equipment. This in turn minimizes the adherence paraffin accumulations to the treated surfaces.
of
Large-Volume Injection Treatments A simple technique often used to free or to open blockages within the formation consists simply of pumping large volumes of crude oil, kerosene, or distillate into the formation. These treatments are especially effective when the formation is blocked by fine silicates or other solids. Pumping the oil into the formation may rearrange these fine particles so that flow channels to the wellbore are reopened. Sometimes it is helpful to add surface-active agents or emulsion-breaking agents to the oil.
Steam Injection In some areas where low-gravity crude is produced, steam is used to heat and reduce the viscosity of the oil and thereby allow the oil to move more easily to the wellbore. Two types of steam injection are used. In some areas, steam is injected into a central injection well and the oil produced from adjacent or surrounding wells. The other type of injection is often referred to as “huff ‘n’ puff.” This consists of alternate steam-injection and oil-production cycles from the same well.
General Comments In any case of production decline, it is important to have all available facts and to make the best possible analysis from these facts as to the factors contributing to the decline. If the problem is not analyzed as completely as possible before treatment, a great deal of money may be wasted in the use of an incorrect treatment. Also, whenever a fluid is to be pumped into a specific part of a zone, some chemical or mechanical method should be used to ensure that the fluid enters the proper zone.
Sand Control
Paraffin Removal
Sand Formation Properties and Geology
Several good commercial paraffin solvents are on the market. These materials can be circulated past the affected parts of the wellbore or simply dumped into the borehole and allowed to soak opposite the trouble area for a period of time. Soaking, however, is much less effective because the solvent becomes saturated at the point of contact and stagnates. In the past, many paraffin solvents havt contained chlorinated materials having an organic chloride ion. Presumably such materials have been taken off the market because of problems encountered in refineries with poisoning of certain catalysts by organic chlorides. The nonorganic chloride ion from HCl is water soluble, and it can be readily extracted from the oil during refining processes. Therefore, the problem of catalyst poisoning does not arise when HCl is used in paraffin-removal formulations such as acid dispersions. Hot-oil treatments also are commonly used to remove paraffin. In such a treatment, heated oil is pumped down the tubing and into the formation. The hot oil dissolves the paraffin deposits and carries them out of the wellbore when the well is produced. When this technique is used, hot-oil treatments are usually performed on a regularly scheduled basis. Paraffin inhibitors are a recent development. These are designed to create a hydrophilic surface on the metal well
Most oil and gas wells produce through sandstone formations that were deposited in a marine or detrital environment. Marine-deposited sands, where most of the hydrocarbons are found, are often cemented with calcareous or siliceous minerals and may be strongly consolidated. In contrast, Miocene and younger sands are often unconsolidated or only partially consolidated with soft clay or silt. These structurally weak formations may not restrain grain movement. When produced at high flow rates, they may produce sand along with the fluids. Why Sand is Produced Fluid movement through sandstone reservoirs creates stresses on the sand grains because of fluid pressure differences, fluid friction, and overburden pressures. If these stresses exceed the formation-restraining forces, then sand grains and fines can move and may be produced with the fluid. Rapid changes in fluid production rates and fluid phases cause unstable conditions that can result in increased sand production. When a well starts to produce water, it will often start to produce sand. Muecke ’ demonstrated that particle movement takes place in a multiphase system when the wetting phase starts to move. Even consolidated sandstone can be mechanically and chemically damaged with time as the reservoir is produced. Overburden stress on sand grains increases as the
REMEDIAL CLEANUP, SAND CONTROL, & OTHER STIMULATION TREATMENTS
56-3
reservoir pressure decreases. Water movement can dissolve minerals that cement sand grains as well as change the carrying capacity of the formation fluids. Fines migration can reduce the permeability in the perforation tunnels. This can result in a higher pressure drop into the wellbore and a change in formation stresses. A calcitecemented formation can be damaged by an improperly designed acid treatment, and increased sand production can result.
screen, in primary or remedial work, and through coiled or concentric tubing. The type of sand-control method selected will depend on the specific well conditions. Important variables such as grain-size distribution, clay content, interval length, bottomhole temperature, wellbore deviation, mechanical configuration, bottomhole pressure, anticipated production rates, and cost should be considered before deciding on the method of sand control best suited to the well.
Consequences of Sand Production
Formation Sampling
Sand movement in unconsolidated formations and its ultimate production with oil and/or gas creates a number of costly and potentially dangerous problems. Most common among these problems are the following.2,3 1, Production interruptions can be caused by sand plugging the casing, tubing, flowlines, or separator. 2. Casing collapse can be caused by changes in overburden pressure and stresses within the formation. 3. Downhole and surface equipment can be destroyed, resulting in downtime for equipment replacements, spills, cleanup or even an uncontrolled blowout. 4. Disposal of produced sands is costly because regulations require the disposed sands to be essentially oil-free.
The most important design parameter in sand control is the formation sand grain size. The success of gravel-pack methods relies upon formation particles being restrained by the larger pack gravel. Chances for a successful sand control job are highest when representative samples of the formation are available for sieve analysis. This enables selection of the proper size of gravel. The most representative formation samples are obtained from rubber-sleeve core barrels. Sidewall cores, although they contain crushed grains and mud contamination, are the second choice. Bailed or separator samples are not representative since sand grains may have been segregated-the larger grains remaining in the hole and the smaller grains being produced with the well fluids.
Methods of Sand Control Higher allowable production rates have increased the need for more effective and durable sand-control systems, which exhibit minimal permeability impairment. Experience indicates that sand control should be implemented before the formation is seriously disturbed by sand removal.4 Four general types of sand-control methods have been developed to reduce or to prevent the movement of formation sands with produced fluids. 1. In some cases, sand production can be prevented merely by restricting the production rate and thus reducing the drag forces on the sand grains. 4 This simple approach is usually uneconomical. Increasing perforation size and density along with the use of clean, nondamaging completion fluids will help to decrease fluid velocity and drawdown pressure at higher production rates. 2. Gravel packing is the oldest, simplest, and most consistently reliable method of sand control. It has wide application both on land and offshore. Advances in gravel-pack technology, which use a viscous fluid to carry high gravel concentrations around a screen, have resulted in faster and more productive gravel packs. Improved completion tools and through-tubing tools that eliminate the need for costly workover rigs have expanded the application of gravel packing. 3. Sand consolidation plastic treatments inject resins into the producing interval, binding the formation sand grains together while leaving the pore spaces open. With use of special preflush systems and diverting agents, intervals up to 30 ft thick have been successfully consolidated and provided with the strength necessary to allow high production rates. 4. Resin-coated gravel packing places gravel coated with a resin both inside and outside the perforations and in the casing. As the resin cures, the sand grains are bound together. A strong, highly permeable, synthetic sandstone filter results. After curing, the excess resin-coated gravel is drilled from the casing, resulting in a full-open wellbore. This gravel pack can be used with or without a
Formation Analysis Formation sand sieve analyses should be conducted to determine formation properties under bottomhole conditions. Treatment steps in acidizing, clay stabilization, and sand control can be determined. Typical sandstone analyses include permeability, porosity, response to acid, mineralogy, petrographic analysis, scanning electron microscope analysis, X-ray diffraction analysis, and optical emission spectrographic analysis. Well Preparation A successful sand-control installation is dependent on following the recommended procedures for all phases of the drilling and completion operations. Selection of the proper gravel size or resin, use of nondamaging drilling and completion fluids, perforation density and cleanliness, and gravel placement are among the important factors affecting well productivity. The following are some of the factors that should be considered before any sand control procedures are initiated. Cleanliness. Clean Tubing. Steps must be taken to ensure that new or used tubing is as free as possible of rust, scale, mill varnish, and other contaminants or obstructions. Many of the contaminants can be removed chemically through the use of solvents or mechanically by “rabbiting” the joints before running. Acidizing the tubing string after it has been run will remove rust and some of the pipe dope that accumulates (see next section) inside the tubing. The string can be acidized by pumping HCl down the string to within 100 to 200 ft of the bottom and then immediately reversecirculating the acid out. Complexing or reducing agents should then be used. The acid should not be allowed to exit the tubing string nor to reach the perforations. Any iron present in the ferric state could precipitate as gelatinous ferric hydroxide (FeOH), which can be extremely damaging to the formation.
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TABLE 56.1-PRESSURE
Gravel U.S. 10120 mesh, 500 darcies
U.S. 20/40 mesh, 119 darcies
U.S. 40/60 mesh, 40 darcies
DROP ACROSS A SAND-FILLED
Flow Rate, q (BPDlperforaiion) 10 25 50 100 10 25 50 100 10 25 50 100
Formation sand,
1 darcy
10
Pipe Dope. Pipe dope, when improperly applied, may be squeezed inside the tubing at the joints and can be transported into the formation by treatment fluids or become lodged in the screen or liner slots, resulting in decreased production. It is virtually impossible to remove the solids found in pipe dope from an oil or gas well chemically. Pipe dope should therefore be applied sparingly to the pin end of the tubing. It should not be used inside the collar where it can be squeezed into the tubing strmg when the joint is made up. Filtering of Fluids. Significant reduction of oil and gas production can be caused by formation damage caused by solids in the fluids used in well completion or workover operations. Clays, silt, or organic solids injected into a perforated interval can become trapped in the formation matrix or in the perforation tunnels where they can act as a low-permeability choke, reducing the productivity of the well. Cement Bond. A good bond between the cement and the formation and between the cement and the casing is essential to isolate the producing zone. Primary cementing is one of the most critical phases in a successful well completion. and good cementing practices should be followed.
Fig. 56.1-Hrgher perforatron density rncreases the success ratro for sand consolrdatron treatments.
HANDBOOK
PERFORATION
Ap (psi) With Perforation Diameter of 3/8in. 0.6 24.0 132.0 495.0 2,079.o 2.0 55.0 272.0 983.0 4,037.o 6.0 177.0 893.0 3,250.O 13,400.o 450.0 27,760.O
in.
Vi in.
1 in.
0.2 8.0 44.0 175.0 666.0 1.o 21.0 99.0 357.0 1,298.O 3.0 67.0 324.0 1,178.O 4,360.O 190.0 9,280.O
0.1 2.3 10.0 37.0 137.0 0.4 6.0 25.0 81 .O 282.0 1.3 20.0 80.0 260.0 927.0 64.0 2,091 .O
0.05 1.oo 4.00 13.00 48.00 0.20 3.00 11 .oo 31 .oo 104.00 0.70 9.00 33.00 98.00 323.00 32.00 808.00
‘12
An in-gauge borehole is important, and the string should be equipped with adequate centralizers, particularly in deviated holes. Spacer fluids and cement slurry properties must be controlled. The string should be equipped with scratchers through critical zones and either rotated or reciprocated during placement of the slurry. Turbulent flow is recommended. If there is any indication of poor bonding, a squeeze cement job should be performed. Intervals to be treated separately should be effectively isolated by bonded cement to reduce the possibility of communication between zones. Perforations. The success of sand-control treatments in holes, measured in terms of well productivity and treatment life, is greatly affected by perforation size and density and by perforating damage. Perforation tunnels must be open so they can be filled with pack gravel to prevent filling with formation sand. If perforations are plugged, gravel cannot be deposited in the tunnels (as carrier fluids flow into the formation) and formation consolidation chemicals cannot be injected. If formation sand is lodged in the perforation tunnels, the pressure drop within the perforation can be excessive, even though the permeability of the formation sand is rclatively high. Experimental results indicate that fluid flow can be turbulent in gravel-filled perforation tunnels with pressure drops far greater than those predicted by Darcy’s linear flow equations. As shown in Table 56.1, pressure drop within a gravel-filled perforation tunnel can be quite significant. 4m6 The greater the perforation density, the less the drawdown through each perforation tunnel and the less the velocity through each effective perforation. Intervals perforated 4 shotsift show cumulative production before sanding to be seven times greater than intervals perforated with only 1 shot/ft. Two perforations per foot show two-thirds the capacity of 4 shots/ft.’ In wells gravel-packed effectively. the lower fluid velocity resulting from high perforation density and largediameter perforations reduces screen erosion and increases the ltfc of the sand-control treatment. Pressure drop cased
REMEDIAL CLEANUP, SAND CONTROL, & OTHER STIMULATION TREATMENTS
56-5
through higher-density, large-diameter perforations also is reduced, resulting in higher wellhead pressure and greater oil or gas production. For sand consolidation, closely spaced perforations (8 to I2 shots/ft) increase the likelihood of a uniform plastic pattern around the wellbore, even if some of the perforations are plugged. Fig. 56.1 illustrates what can happen when a perforation is plugged. Note that the sand is not consolidated behind the plugged perforation on the right side of Fig. 56.1(a), and that this is the spot where a failure is most apt to occur. Perforation Cleaning. The high-pressure jet from a perforating gun pierces the casing and forms a hole by pulverizing cement and formation into compacted particles. Cement and material from the jet charge are mixed with the formation material in the compacted zone while loose debris fills the perforation tunnel. It is necessary to remove this debris from the perforation tunnel to increase the probability of success in sand consolidation or gravel packing. Fig. 56.2 shows the damage that can occur in the perforation and on the face of the formation during drilling and perforating. 8 Perforation-cleaning methods include backflow, underbalanced perforating, backsurging, washing, and acid stimulation, or combinations of these. These methods are discussed next. Backflow. Flowing the well may not clean up more than a few perforations and, if enough differential is available to purge debris from the perforations, the well may sand up. Backflow must be done slowly and carefully. Underbalance. Perforating with hydrostatic pressure less than formation pressure allows tunnel debris to be carried into the wellbore with the first surge of fluid from the formation. Backsurging. Backsurging techniques dislodge gun debris and loose material from perforation tunnels by sudden exposure of a perforated zone to an open chamber at atmospheric pressure. The differential pressure created causes formation fluids to surge through the perforations into the casing, flushing the perforation tunnels. Backsurging has proved to be very successful in improving productivity. Perforation Washing. Washing IS achieved by straddling a small increment of the perforated interval with a special tool and injecting nondamaging fluids into the perforations in the increment. The fluid circulates outside the casing and back through the perforations nearest the tool seals, removing debris and formation sand from the perforations and from behind the casing. The tool is moved in increments equal to the seal spacing until the entire perforated interval is washed. After the perforations are washed or surged and debris is circulated out, a positive-depth indicator is placed in the well below the perforations to establish a reference point from which the string is accurately spaced out. This is especially important in multiple completions with closely spaced producing intervals. M&-LXAcid Stimulation. The purpose of matrix acidizing is to penetrate the formation at less than fracturing pressure and to remove damage from perforation tunnels and the critical area surrounding the wellbore. Mud filter cake, silt, and clay are typical damaging materials that may be removed by mud acid to restore a well’s natural productivity.
Fig. 56.2-Drawing
of a perforation tunnel showing fluid invasion from the wellbore into the formation, and debris in the perforation and the compacted zone surrounding the perforation tunnel.
The formation solubility should be determined in both mud acid and HCI. If mud acid is used, a formation solubility at least 10% greater in mud acid than in HCl is preferred. Moreover, the formation solubility in HCl should be less than 20% to avoid calcium fluoride precipitation. A typical three-step acid stimulation consists of an HCI preflush, matrix treatment with mud acid, and an HCI overflush. HCl Prejlush. A preflush of 50 to 100 gal/fi of perforations is advisable. The HCI is used to prevent contact of mud acid with calcareous materials or formation brine. This prevents or reduces the chances of precipitation of calcium fluoride and various fluosilicates. Matrix Treatment With Acid. The proper volume of mud acid should be injected to remove damage near the wellbore. Usually 50 to 200 gal/ft of perforations is required. Success in matrix acidizing depends on acid contacting the entire production interval. This is achieved through the use of diverting agents. A mutual solvent comprised of ethylene glycol monobutyl ether ‘).I0 is sometimes needed to achieve good results. It is an effective water-wetting agent, demulsifier. and interfacial-tension reducer. Overflush. Completion or workover brine should not be used as an overflush for mud acid because of the possible precipitation of sodium, potassium, or calcium tluosilicates. The use of dilute HCI, ammonium-chloride solution, light oil, or nitrogen as the overflush agent is recommended. Clay Control In many cases, formation permeability may be damaged by the various clay materials present. Many clays are water sensitive, and contact with foreign fluids may cause damage by two mechanisms. The first, and probably the more critical, mechanism is dispersion and migration of the clay particles. Dispersion may be caused by charge differences or by fluid movement. The dispersed clays are then free to move through the formation until they enter an opening too small to pass, thus lodging and reducing permeability. The second mechanism is expansion or swelling of the clay particles. Water absorbed between
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HANDBOOK
the clay particles causes the particles to expand, with a corresponding decrease in pore volume and the plugging of pore channels. To avoid a production decrease, it is important to stabilize clays before or along with a sand-control treatment. Gravel Selection
DIAMETER
RATIO
PACK
MEDIAN/FORM
MEDIAN
Fig. 56.3-Gravel-pack permeability impairment caused by formation sand invasion is illustrated by curve of change in ratio of increases. A ratio of 5 to 6 is the largest gravel that will stop all sand entry. Theoretical curve beyond 14 indicates sand flowing freely through gravel (after Ref. 12).
TABLE 56.2A-AVAILABLE
Gravel Size (in.) 0.006 0.008 0.010 0.012 0.017 0.023 0.033 0.033 0.047 0.066 0.079
to 0.017 to 0.017 to 0.017 lo 0.023 lo 0.033 to 0.047 to 0.066 to 0.079 to 0.079 to 0.094 to 0.132
GRAVEL SIZES
IJ.S. Sieve - Number 40/l 00 40/70 40160 30150 20/40 16130 12120 1o/20 10116 8112 6/10
TABLE 5&2B-FORMATION SIEVE ANALYSIS U.S. Sieve Number 30 40 50 70 100 140 200 270 325 400 PAN
Approximate Median Diameter [in.) 0.012 0.013 0.014 0.017 0.025 0.035 0.050 0.056 0.063 0.080 0.106
SAND
Cumulative Wt% Retained Sample A 0.2 1.2 5.1 16.0 35.0 62.0 82.0 93.0 97.0 98.3 100.0
Sample B 0.1 0.6 2.5 7.5 19.0 39.0 58.0 77.0 86.0 90.0 100.0
Gravel should be sized to prevent invasion of the pack by the finest formation sand. I’-13 For example, if 20% of a gravel pack is fine sands, the permeability will be 35% less than if no fines were present. 13,14 A gravel size should be selected that will restrict the movement of fine formation sand but will not reduce the flow of fluids to uneconomical rates. Saucier I2 suggests that the gravel size for controlling uniform sands should be five to six times the diameter of the mean (median) formation sand grain size. Degree of pack impairment is illustrated in Fig. 56.3, which shows the ratio of effective to initial pack permeability vs. the ratio of the pack median diameter to the formation median diameter. Proper gravel size is determined by the following steps. 1. Obtain a representative formation sample; closely spaced samples from rubber-sleeve cores provide the best design bases. 2. Perform a sieve analysis. 3. Plot the sieve analysis data on either a cumulative logarithmic diagram (S-plot) or a logarithmic probability diagram. 4. Calculate the gravel median grain diameter using a five-to-six multiple of the 50-percentile formation grain diameter. When multiple cores from a single zone are provided, they should be analyzed and plotted separately. The samples should not be mixed. The sample with the smallest 50-percentile grain diameter is used to select the gravel. Tables 56.2A and 56.2B list some of the commercial gravel sizes available. Gravel should be screened and checked to verify size and distribution. Sieve analysis data for two rubber-sleeve, core-barrel samples, taken from the same zone, are tabulated and are plotted in Figs. 56.4 and 56.5. Note that Sample A is from a portion of the zone that contains coarser sand than the portion from which Sample B was taken. If Sample A alone had been taken, a coarser gravel would have been selected, and a gravel-pack failure could have resulted. In Fig. 56.6, produced, bailed, and core-barrel samples from the same well zone have been plotted. The corebarrel sample plots as a straight line (minor variations are typical, however). The dashed variation shown could indicate a sieving or weight problem. A bailed sample would typically rise on the left because finer formation grains would have been produced, leaving the larger grains in the wellbore. Conversely, a produced sample would rise on the right, indicating an excess of fines. The same data are shown in an S-plot (Fig. 56.7). Each of the curves is typically S-shaped, and any curve plotted by itself would not readily be interpreted as varying from the norm. An error in gravel selection could result if the sample type were not known. Gravel Quality. Studies have indicated that gravels containing fine particles outside the specified range will have lower permeability. I4 Some supply sources furnish gravel with excessive amounts of particles smaller than specified. Angular gravels may bc broken during shipping and
REMEDIAL CLEANUP, SAND CONTROL, & OTHER STIMULATION TREATMENTS
CUMULATIVE
LOG DIAGRAM (S.PLOT) U.S. SIEVE
GRAIN
NUMBER
DIAMETER,
in
Fig. 56.4-Data
from sieve analyses of Formation Sand Samples A and B, taken from the same zone, are plotted here. Note that using Plot A would result in the selection of 20/40-mesh gravel rather than the better choice of 40/60-mesh gravel for packing this zone, as indicated by Plot B.
handling, thereby creating fine particles that reduce the quality of the gravel. Rounded gravels provide tighter, more uniform compaction and somewhat higher permeability than angular gravels. Screen Selection Many types of wire-wrapped screens are available, including ribbed, all-welded, grooved, and wrapped-onpipe. The all-welded screen has the wrapping wire resistance-welded to wire ribs at each point of contact. Spacer lugs, solder strips, and weld beads are not required and, therefore, the all-welded screen is stronger and more
LOGARITHMIC
56-7
PROBABILITYDIAGRAM
Fig. 56.6-Logarithmic
probability diagram of produced, bailed, and core-barrel samples from the same well.
corrosion-resistant; it also has a lower pressure drop, and it will not unravel if the wire is eroded or broken. The wrapping wire on these screens is usually made from 304 stainless steel while the pipe core is Pipe Grade S or K. Other wire and pipe materials are available. The configuration of the openings in all screens is very important. If the sides of the slots are parallel, plugging may occur as the small sand grains bridge the slot. To reduce the chance of this occurring, the wire used to wrap the screen is wedge-shaped. Fig. 56.8 shows the construction features of an allwelded screen. For gravel packing, the gauge of the screen should be small enough to prevent the passage of the gravel-pack sand. Slot width is usually taken as one-half to two-thirds of the diameter of the smallest gravel-pack grains.
CUYULATIYE
LO6
OI~GRAM
(I-PLO11 U 5.
SIIYE
“UMGEI
;Em.8;
H
g;:::-*
-
P
s*llPeP
CUMULATIVE Fig. 56.5-Data
I
itorn1
D*rl;il
PERCENTBY
WEIGHT
for Samples A and B are again plotted here. Sieve-analysis data for sands with a normal grain-size distribution will plot as a straight line on a log probability grid. The logarithmic probability diagram has an advantage over the S-plot in that sampling errors are more readily detected. Variations from the straightline plot could be caused by sieving and weighing errors, incorrect sample preparation, or by the sampling method itself.
Fig. 56.7-Cumulative log diagrams (S-plot) of produced, bailed, and core-barrel samples from the same well. Note that a bailed sample would result in the selection of a coarser gravel.
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Fig. 56.B-All-welded screen
The screen diameter should be as large as possible and yet leave adequate room for packing gravel. Table 56.3 shows the dimensions and inlet areas for several sizes of wire-wrapped screens. Screens are available with slot openings from 0.006 to 0.250 in. in 0.001 -in. increments. The screen length should overlap the perforated interval both above and below by 3 to 5 ft. Blank pipe should be run above the screen to provide a reservoir for extra gravel. Blank pipe length should be three to four times the screen length with a minimum length of 60 ft. Gravel Packing Methods. The term “gravel.” as used here. refers to a uniform, graded, commercial silica sand that is placed in the wellbore and perforation tunnels for the purpose of mechanically retaining formation sands. These are described next. Circulating gravel packs are done in two steps: an outside pack and an inside pack. The outside pack or prepack places gravel outside the perforations, where voids may exist in the formation surrounding the casing and in the perforations. An outside pack is, of course, not used in openhole completions. The outstde pack is usually attained by pumping a gravel slurry through an open-ended workstring with the application of fluid pressure. To achieve good gravel placement, fluid must be lost to the formation. The inside pack is achieved by pumping a slurry containing from 1/4to 15 Ibm of gravel per gallon of fluid down the workstring and through a crossover tool into the annular space between the screen and the casing. The gravel is held in place by the screen while the carrier fluid
ENGINEERING
HANDBC,‘Y
(brine, diesel oil, etc.) flows through the screen and crossover tool into the tubing/casing annulus and back to the surface. A wash pipe extends from the crossover tool. inside the blank pipe and screen, to the bottom of the screen. Returns are taken through the wash pipe. It is recommended that the wash pipe outside diameter be 0.6 times the screen liner inside diameter and made up with flush joints. This ratio of wash pipe outside diameter to liner inside diameter optimizes gravel distribution along the screen in deviated holes. The screen and blank pipe should be centralized every 15 ft, and the length of the screen should be such that it extends above and below the perforated interval by 3 to 5 ft. A calculated quantity of a high-density slurry at 15 Ibm of gravel per gallon of fluid (density of l3.8Y Ibm/gal if fluid is water) is circulated into place. As the grave1 settles out and packs in the hole outside the screen. injection pressure will increase. When the injection pressure has increased to between 750 and 1.500 psi above the originally established injection pressure, pumping is stopped. When the sandpack causes such a pressure increase, the condition is called a screenout. The slurry remaining in the reservoir above the screen (established by the blank pipe) will settle out so that ample gravel exists above the top of the screen. Since about 60% of the slurry volume consists of gravel. 100 ft of slurry will result in 60 ft of settled gravel. In grave1 packing intervals with the circulating method and a high-density slurry, a lower tell-tale is recommended. The lower tell-tale is a short section of screen, not less than 5 ft long, located below the production screen. A seal sub, installed between the lower tell-tale and the production screen, seals the wash pipe. Returns are thus taken only through the lower tell-tale. By this method, gravel is placed at the bottom of the screen. and a denser pack can be achieved. After screenout of the telltale screen, the wash pipe is pulled up into the production screen to complete the gravel pack. Squeeze gravel packing uses a gravel slurry consisting of 15 lbm of gravel added to a gallon of viscous carrier fluid. This gives a high-density (13.89 lbmigal) slurry. The carrier fluid transports the gravel into place and is squeezed away into the formation. A viscosity breaker in the carrier fluid reduces the viscosity according to a preplanned schedule; this allows for fast well cleanup. Reverse circulating gravel packing is a low-density method using r/4to 2 Ibm of gravel per gallon of carrier fluid. The slurry is circulated down the tubing/casing annulus. The gravel is retained on the outside of the screen while the carrier fluid flows through the screen and to the surface through the tubing. After the pack is completed and all the gravel in the annulus has settled, the tubing is pulled out of the hole, leaving the screen assembly with a polished nipple on top in the hole. A productton packer with an overshot seal assembly is then run over the polished nipple. If the pack is done in perforated casing, a prepack is usually done first. Several disadvantages associated with a reverse circulating gravel pack include (1) long rig time, (2) pack voids. (3) slurry pumped down the annulus scouring dirt and mill scale from the inside of the casing and the outside of the tubing, and (4) possible formation damage caused by large amounts of dirty fluid circulated and lost to the formation.
REMEDIAL
CLEANUP,
SAND
CONTROL,
TABLE
& OTHER
STIMULATION
56.3-COMMON
SCREEN
56-Q
TREATMENTS
SPECIFICATIONS
AND SIZES Screen
Pipe Base
OD (in.)
Weight (Ibmlft)
ID (in.)
Holes per ft
1.050 1.315 1.660 1 .soo 2.063 2.375 2.875 3.500 4.000 4.500 5.000 5.500 6.625 7.000 7.625 9.625
1.14 1.70 2.30 2.75 3.25 4.60 6.40 9.20 9.50 9.50 13.00 14.00 24.00 23.00 26.40 36.00
0.824 1.049 I ,380 1.610 1.751 1.995 2.441 2.992 3.548 4.090 4.494 5.012 5.921 6.366 6.969 a.921
72 60 72 a4 a4 96 108 108 120 144 156 168 180 192 204 264
Hole Diam. (in.)
Total Hole Area (sq in.lft)
7’6 ?A6 %6 %6 76 % ‘12 ‘12 ‘12 ‘12 ‘12 ‘12 ‘12 ‘/2 ‘/2 Cased
Screen
0.020
9.6 11.3 13.4 14.9 15.9 17.8 20.9 24.8 27.9 31 .o 34.1 37.2 44.2 46.6 50.5 63.0
14.4 16.9 20.1 22.3 23.9 26.8 31.5 37.3 41.9 46.5 51.3 55.9 66.5 70.0 75.9 94.7
wl6 2% 2% 2%
7
27/8 to 3% 27/8 to 3’/2 4
7%
8% 9% 10% Openhole
4% t0
!i’h
5
5%
to
Completion
Openhole Diameter (In.)
Screen Pipe Size (in.)
12 14 to 16 14 lo 18 16 to 20
4 5% 7
Wash-down gravel packs are done by dumping the gravel down the casing, allowing it to settle. and then running a screen-and-wash pipe assembly with a wash-down set shoe into the hole. Circulation is established through the shoe, and the screen assembly is lowered as the gravel is washed up the annulus. When the shoe tags bottom. circulation is immediately stopped, and the gravel allowed to settle around the screen. The screen is then released, and a production packer with a seal sub is run into the hole to seal the production string.
5
6.
7
8.
9.
References
0.012
a.2 9.7 11.5 12.7 13.6 15.3 17.9 21.2 23.9 26.5 29.2 31.9 37.9 39.9 43.3 54.0
Pipe Size (in.)
5% 6%
5% 65/s to 7% 75/s to as/e 95/8 to 10%
0.010
6.8 8.0 9.4 10.5 11.2 12.6 14.8 17.5 19.7 21.8 24.1 26.3 31.2 32.9 35.6 44.4
Hole Comoletion
4% 5
Casing (in.)
in
0.008 1.55 1.82 2.16 2.40 2.56 2.88 3.38 4.00 4.50 5.00 5.51 6.01 7.14 7.52 a.15 10.17
3.53 4.60 5.52 6.44 6.44 10.60 11.93 21.21 23.56 28.27 30.63 32.99 35.34 37.70 40.06 51.84
‘/‘l
Casing (in.)
Screen Surface Open Area sq in./ft for slot opening (in.)
IO. I I.
12. 13.
I-1.
2%
Brulst. E.H.: “Better Perl’ormance nf Gulf Coast Well\.” paper SPE 4777 presented at the 1974 SPE Symposium on Formation Damage Control, New Orleans, Jan. 3l-Feb. I. Gurley, D.G., Copeland. C.T.. and Hendrick. J.O. Jr.: “Debign. Plan. and Execute Gravel Pack Operations for MaxImum Production.“ J. Prr. Tech. (Oct. 1977) 1X9-66. Stein. N., Odeh. A-S., and Jones, L.G.: “Estimating Maximum Sand-Free Production Rates from Friable Sands for Different Well Completion Geometries.” J. Pa. Tech. (Oct. 1974) 1156-58. Klotz. J.A.. Krueger, R.F., and Pye. D.S.: “Maximum Well Producttvity in Damaged Formations Requires Deep. Clean Perforations,” paper SPE 4792 presented at the 1974 SPE Symposium on Formation Damage Control. New Orleans, Jan. 3l-Feb I. Brooks, F.A.: “Evaluation of Preflushes for Sand Consolidaiton Plastcs,” J. Par. TK~. (Oct. 1974) 1095-l 102. Gidley. J.L.: “Stnnulation of Sand\tonc Formations With the AcidMutual Solvent Method.‘~ J PH. Tech. (May 19711 SSl-58. Gulati. M.S. and Maly. G.P.: “Thin-Sectjon and Permeability Studtca Call for Smaller Gravels in Gravel Packtng,” paper SPE 4773 presented at the 1974 SPE Symposium on Formation Damage Control. New Orleans. Jan. 3l-Feb. I. Saucier. R.J.: “Gravel Pack Design Consideration\.” J. Pet. Ted? (Feb. 1974) 205-12. Williams. B.B., Ellioct. L.S.. and Weaver. R.H.: “Productwity of Inside Casing Gra\,el Psck Completions.” J. Pc,r. Twh. (April 1972) 419-25. Sparlin. D.D.: “Sand and Gravel-A Srudy of Their Permeabilitws,” paper SPE 4772 presented at the 1974 SPE Sympwium on Formation Damage Conrrol. New Orleans, Jan. 3 I-Feb. I.
Chapter 57
Oil and Gas Leases Joe B. Clarke Jr., Vermilion Oil and Gas Corp.*
The Landowner’s Interest Property All property can be classified as either real or personal. Real property is land and that which is affixed or appurtenant to land. Personal property is every kind of property that is not real property. Oil and gas in place are considered to be a part of the land and are therefore a form of real property. When oil and gas are reduced to possession by being brought to the surface, they become personal property. Ownership of property is the right to possess and use the property to the exclusion of others. Land cannot be without ownership. The rightful owners may be hard to determine, but ownership nevertheless exists. The extent of an owner’s rights may vary. Absolute ownership is a superior status excluding participation by anyone else. The absolute owner is most frequently referred to as the fee owner and absolute ownership as fee ownership. There is a form of qualified ownership referring to a status establishing an equal right of participation in another person. For example, two parties are co-owners of a tract of land. Each party has certain rights to use and enjoy the land, but the rights of each party are qualified by the rights of the other party. Another form of ownership is limited ownership, which is a restricted right. The absolute owner who grants a l-year grazing lease brings a form of limited ownership into being. The absolute or fee owner is entitled to possession, which means the actual or physical occupancy of a thing. The party in possession of a thing is occasionally not the owner of that thing. Possession undoubtedly carries with it the intention to hold, but possession does not mean ownership. The fee owner owns the surface of land and the minerals thereunder. The surface owner has no right to grant an oil and gas lease or mineral lease. However, the rights of mineral owners are often subject to the rights of ‘This
author also wrote the original chapter on thm topic rn the 1962 editlon.
surface owners. The mineral owner has the right to grant mineral leases. A royalty owner has a right to receive royalty or a share of production as obtained but has no right to grant mineral leases or receive bonuses or rentals. Ownership of Hydrocarbons in Place. Various ideas and theories have been suggested as to the nature of ownership of oil and gas in the reservoir prior to extraction. Two principal ideas have evolved: the absoluteownership and the nonownership theories. In the absolute-ownership theory, hydrocarbons are considered a part of the land and absolute ownership of the land is absolute ownership of the oil and gas in place. This theory divests the absolute owner of the hydrocarbons in place when there is drainage across property lines. The nonownership theory requires the acceptance of oil and gas as fugitive minerals. Absolute ownership of the land will therefore carry with it only the exclusive right to drill on the land in an attempt to reduce the oil and gas to possession. Absolute ownership of the oil and gas is not attained until the oil and gas are reduced to actual possession. Regardless of which theory of ownership each of the various states adheres to in its statutes, the courts are in agreement that oil and gas in place are minerals and a part of the land; when they are reduced to possession, they become personal property; a landowner has the right to drill a well on the property in an attempt to reduce the oil and gas to possession, and without liability for drainage from adjacent lands; these privileges and responsibilities can be transferred to others. Rule of Capture The theories of ownership provide for the migratory nature of oil and gas under certain conditions. The impossibility of determining liability for drainage whem
57-2
landowners produce in a lawful manner from a well on their land is recognized. This freedom from liability for drainage is referred to as the “rule of capture,” Since landowners cannot recover damages or enjoin the operator when their property is being drained by a well on adjacent lands, they must protect themselves as best they can. In short, they must drill, or have the lessee drill, a well on their own land as promptly as possible in order to prevent further drainage. This “offset drilling rule” is modified in these days of increased conservation legislation. Many states have statutes relating to well spacing, allocation of production, pooling, etc., which provide equitable relief for the landowners who are being drained by other means than the drilling of a well on their land, and which tend to prevent the drilling of unnecessary wells. Mineral Severance Severance of the minerals can occur in a number of ways. One of the most common ways is the conveyance of the land itself by a deed that provides for the reservation or exception of all or a part of the minerals to the grantor. Mineral severance is often accomplished by a deed conveying all or a part of the minerals themselves. A severance of oil and gas from the surface is recognized in all jurisdictions. A lease or a conveyance using the term “minerals” will include oil and gas without otherwise describing them. A conveyance of a named mineral without the phrase “and other minerals” will convey only the mineral named. In some areas, “oil and gas” leases are obtained; in other areas, “oil, gas, and mineral” leases are obtained. The owner of the mineral estate is entitled to the use of the surface as it may be necessary, subject to certain rights of the surface owner, for the exploration and recovery of the minerals. The foreclosure of a mortgage as to the surface estate is not effective as to the mineral estate, provided the execution of the mortgage is subsequent to the date of the mineral severance. Adverse Possession. Adverse possession refers to the possession of real estate that is open, visible, continuous, and exclusive. The statutes of the various states establish the manner in which titles can be acquired by adverse possession. If such possession is continued for the time and in the manner prescribed by the statutes, the effect is to divest the owner of title and to vest in the adverse possessor a new title. If the minerals have not been severed, adverse possession of the surface is adverse possession of the minerals. Minerals severed from the surface prior to the commencement of adverse possession cannot be acquired by adverse possession. The years of occupancy, the construction and maintenance of fences, the construction and use of houses and outbuildings, the drilling of water wells, the grazing of cattle, the cutting of timber, the growing of crops, the payment of taxes, etc., are all important items to be considered by the title examiner in determining whether or not a basis exists for the establishment of an adverse title under the statutes of the state involved. Partition. Partition is a division of real estate among coowners whereby each acquires a separate tract The ef-
PETROLEUM
ENGINEERING
HANDBOOK
fect of partition is to terminate the ownership of the undivided interests of the joint owners and to establish ownership in each co-owner as to the divided share. Partition is effected either voluntarily or involuntarily. The latter is called compulsory or judicial partition and consists of partition in kind or partition by sale and division of the proceeds. Partition in kind is, in general, the most equitable form of partition. Where such partition is impractical or unfair, partition by sale and division of the proceeds is resorted to. A lessee who acquires an oil and gas lease from less than the entire group of cotenants is faced with certain problems, each of which has to be solved on its own merits under the applicable statutes. Partition of a tract subsequent to the granting of an oil and gas lease by the co-owners does not enlarge the obligations of the lessee. In such an instance, the lessee would not be required to drill an offset to prevent drainage in the event that the completed oil well is on one of the partitioned tracts. Trespass. The landowner and his mineral lessee have several remedies for unauthorized entry and use of the surface and minerals. In determining the measure of damages for unauthorized intrusion it must first be determined whether the trespass was made in good faith or in bad faith. The measure of damages for unauthorized production in the case of good-faith trespassers is the value of the oil and gas at the surface less the reasonable costs of production; the measure of damages in the case of bad-faith trespassers is the value of the oil and gas at the surface. Unauthorized penetration of the subsurface is a form of trespass. A lessee who commences a well on a tract of land and allows or causes the borehole to deviate from the vertical in such a manner so as to drill into the subsurface belonging to an owner who has not leased to the lessee is liable for trespass. In questions involving this type of trespass, a court order may be obtained for a well survey to determine whether or not a trespass has occurred. Should such a well produce, the measure of damages would be the value of the hydrocarbons removed. If the well results in a dry hole, the trespasser is liable to the landowner for damages for the destruction of the mineral value of the land. Fee or absolute ownership carries with it the right of absolute control, including the right to grant oil and gas leases, to conduct exploratory operations on the land, to authorize others to so use the premises, etc. It therefore follows that a party who conducts exploratory operations without permission violates the rights of the landowner and is accordingly liable. In this type of trespass, damages may be recovered from the standpoint that such operation may have reduced or removed the marketability of an oil and gas lease on the land or reduced the leasing value of the land itself. Correlative Rights. Despite the rule of capture, there has been much said and written, and some legislation, regarding correlative rights. Property owners overlying a common source of supply are restricted in their right to remove hydrocarbons by their duties to adjoining landowners. They are obligated not to injure the reservoir or dissipate the reservoir energy, and they cannot remove a disproportionate share of the hydrocarbons. In general,
OIL AND GAS LEASES
owners may not use their land in such a manner as to injure the property of others. The principle of correlative rights is enforced by law in those states that have enacted comprehensive conservation legislation,
The Oil and Gas Lease Background A large number of printed lease forms are in use in the oil industry. The evolution of the oil-and-gas-lease contract has been a slow process. Present-day forms are quite lengthy when compared with the contracts made in the earlier years of the oil industry. The many refinements made since then have been based on the hard lessons learned through experience and on the many court decisions rendered as a result of the inevitable controversies which arose as the industry grew. The courts have held, keeping in mind the fugitive nature of oil and gas, that the primary purpose of the oil and gas lease is development. Should the oil and gas lease not contain an express provision in this regard, the law will imply an obligation on the part of the lessee to explore and develop the leased premises. An oil and gas lease is a conveyance or an interest or right. It is also a contract between the lessor and the lessee. Since an oil and gas lease conveys an interest in real estate, it must be in writing in accordance with the statute of frauds. A lease is sufficient if the names of the parties, the description of the property involved, and the terms of the agreement are set forth. It is not necessary that the lessee sign the lease to make it legally effective. Witnesses are not required in order to make the instrument effective between the parties. An acknowledgment is required only in connection with the recording of the instrument and does not affect the validity of the instrument between parties. Recording the lease is not necessary to the validity of the instrument between the parties, but is required to afford protection against bona fide purchasers. The Lessor A party owning a mineral interest and having the personal capacity to contract has the capacity to execute a valid oil and gas lease. Oil and gas leases from minors and insane persons are usually executed by guardians of such persons under the direction and approval of the court. The disabilities of minors may be removed in some states by judicial proceedings and leases obtained directly from such persons. Leases executed by minors are voidable at their election upon reaching majority. A lease executed by a person subsequently adjudged insane is voidable. Landowners often leave a will devising certain real property to their children subject to a life estate or usufruct in the surviving widow, who is called the life tenant or usufructuary. The children are called the remaindennen or naked owners. Neither the life tenant nor the remaindetman has the right to lease without the consent of the other. Both parties must join in the execution of an oil and gas lease for it to be valid. It is important that the rights of the lessors as to the bonus, delay rentals, and royalty payments be clearly set forth in the lease. Generally, the bonus and rental payments are payable to the life tenant, and royalty is payable to the remaindennan.
57-3
A landowner can execute an oil and gas lease on lands that are subject to the qualified rights of others provided the lease does not interfere with such prior rights. The most common example is the landowner who grants a surface lease for grazing purposes and then at a subsequent date executes an oil and gas lease. The lessee in the oil and gas lease cannot be prevented from entering on the surface to exercise the rights granted in the lease, but at the same time the lessee is responsible to the tenant for damages to the extent that the tenant’s rights are interfered with. A tenant’s consent agreement is usually obtained prior to operations of any kind. An administrator is one who is vested with the right of administration of an estate and is appointed by the court. An executor is a person appointed by a testator, or the party making a will, to execute his will. A trustee is a person holding property in trust for another party. Executors, administrators, and trustees have authority to execute oil and gas leases provided such specific authority is given by will, by the court, or by statutory pmvision. A power of attorney is an instrument authorizing one to act as the attorney or agent of the person granting it, and terminates upon the death of the grantor. In the case of married persons, the husband may, in general, execute a lease without the joinder of his wife. Homestead statutes usually require that all instruments creating encumbrances upon the homestead be signed by both parties. The wife, in general, can execute a lease on her separate property. In community-property states the husband may or may not have the right to grant a lease on the community estate without joinder by his wife; however, most lessees will insist upon the joinder of the wife. The law differs among the states as to whether or not a co-owner can execute a lease without the consent of the other cotenant. In most of the states, such a lease would be effective only as to the interest of the executing cotenant. Two or more lessees, each having leases on undivided interests in the same tract, are cotenants. Each is entitled to drill on any part of the leased premises but, if successful, must account to the other cotenant for his proportionate share of the production, less the cost of production. Consideration,
Date, Description, and Delivery
A valid oil and gas lease requires a consideration, a nominal cash payment or other consideration generally being sufficient. An undated lease takes effect upon execution and delivery. An exact description of the land to be leased is not necessary, provided the land can be identified with reasonable certainty. Delivery and acceptance of an oil and gas lease are required as with other conveyances: the intent of the lessor to make the instrument legally effective must be apparent. The Granting Clause. This clause in an oil and gas lease is usually the first paragraph in the lease and is one of the most important paragraphs in the entire contract. The rights of the lessee are very broadly set forth. The remaining provisions of the contract modify or enlarge upon the provisions of this paragraph. The granting of the lease is for the purpose of the development of the mineral estate. Accordingly, the lessee must have those exclusive rights that are necessary
57-4
to carry out the basic purpose of the lease. This includes the right to build pits and erect tanks and other equipment pertinent to the lessee’s operations. The lessee has the right to construct, maintain, and use roads, pipelines, and/or canals on the leased premises. The lessee is not liable for operations on the leased premises unless the surface is used excessively, the operations are negligent, or any express provisions in the lease are violated. The lessee is required to restore the premises to their original condition, insofar as is practicable, when required by the lease. The lessee has the right to conduct exploratory operations on the leased premises and to conduct secondary-recovery operations and to dispose of salt water by reinjection into suitable formations. The landowner is entitled to the use of the surface, less that required by the lessee, who has the responsibility of protecting this remaining surface for the benefit of the lessor. The lessee must exercise complete control over the surface storage of liquids and is responsible for damages in the event of leakage and injury to the adjoining surface. The Habendum Clause. A simple form of this clause provides that “this lease shall be for a term of blank years from the date hereof, called primary term, and so long thereafter as oil or gas is produced. ” This clause fixes the ultimate duration of the lessee’s interest. The lease may be terminated sooner, for example, by the failure of the lessee to pay delay rentals. The primary term will limit the life of the lease prior to the establishment of production from the leased premises. The primary term is one of the items that must be negotiated at the time of the purchase. The term most commonly used is either 3 or 5 years. It is usually difficult to acquire leases with terms longer than 5 years. In very active areas primary terms of 3 years and less are usual. For the lease to be extended beyond its primary term, production must occur, subject to certain exceptions to be discussed subsequently. The fact that oil or gas may have been discovered on the leased premises will not in itself keep the lease in force unless specific provisions are made to the contrary. This is especially applicable to oil. In the case of gas, provision is frequently made in the lease to extend the lease past its primary term in the event the lessee is not able to market the gas for lack of transmission lines, lack of a gas market, etc. When such a provision appears in a lease, it is referred to as a shut-in gas clause. It usually provides for the payment of a sum of money on an annual basis in an amount that may be as high as the lessor would ordinarily receive as delay rentals. The word “produced” in the habendum clause has been held to mean “produced in paying quantities. ” What constitutes production in paying quantities has been the subject of much dispute. In general, if a lease is past its primary term, and enough production is being obtained from the lease so that a profit is made, however small, in excess of the cost of operation, disregarding the drilling and completing costs, such lease is held by production in paying quantities. While a lease may generally be maintained in force past its primary term only by production, there are other ways provided for in the lease to maintain the lease past the primary term. A lease can often be kept in force, in
PETROLEUM
ENGINEERING
HANDBOOK
the absence of production, through the date of expiration and after the primary term by the lessee’s operations, which are conducted in a diligent manner looking toward the discovery and production of oil and gas. Most leases provide that the lease may be kept in force for an indefinite period of time in this manner provided that not more than 60 or perhaps 90 days elapse between the cessation of any such operations and the commencement of additional operations. Such additional operations might include reworking operations on any abandoned producer or deepening operations on a dry hole or possibly drilling operations for a new well at another location on the leased premises. Drilling and Delay Rental Clause. A simplified drilling and delay rental clause might say that “the lease shall terminate on blank date unless on or before such date the lessee either commences operations for the drilling of a well on said land or pays to the lessor a rental of blank dollars per acre for all or that part of the land which lessee elects to continue to hold, which payment shall maintain lessee’s rights in effect as to such land without drilling operations for 1 year from the above date.” The lessee may continue to maintain such rights without drilling operations for successive 1Zmonths periods by making similar payments to the lessor. Early oil and gas leases usually provided for the commencement of a well. Changes were gradually made in the lease to allow the lessee to defer drilling operations by the payment of an annual sum called the delay rental. This alternative obligation to drill or pay a delay rental, when considered with the right of the lessee to surrender the lease at any time, is called an “or clause.” Further changes were made. Wording was added to the lease to provide that, if no well was commenced before a certain time, usually 1 year from the date of the lease, the lease would terminate unless the lessee paid a delay rental. This further revised wording is known as the “unless clause.” Regardless of which clause is used, the lessee has the right either to commence a well within a specified time, pay a delay rental in lieu of commencing operations, or terminate the lease by the nonpayment of delay rentals. Almost all leases in use today are of the “unless” type. Since the lessee is under no obligation either to pay delay rentals or commence operations for the drilling of a well, the practice has been to pay a substantial consideration, called the bonus, for the granting of the lease. The bonus may be any agreed-upon sum but is usually large when compared with the delay rental. The bonus is sufficient to keep the lease in force and effect until such time, usually 1 year, as a delay rental may be provided for. The bonus is subject to negotiation at the time of the purchase of the lease. The bonus may run from $1 to many thousands of dollars per acre, depending on the size of the tract, the royalty, anticipated oil and gas reserves, the quality and quantity of geological and geophysical data available, etc. Most leases provide for the commencement of “operations. ” The commencement of actual drilling is not necessary unless specifically provided for. Operations incident to the actual drilling are sufficient and include building roads, digging pits, building the derrick, etc. Such operations must be continuous, diligent, and in good faith.
OIL AND GAS LEASES
The effect of the drilling of a dry hole during the primary term by the lessee may vary from one lease form to another. Most leases provide that, if a dry hole is completed on the leased premises within the primary term, the lease may be kept in force by the commencement of additional operations or by resuming the payment of delay rentals as provided for in the lease. In the “unless” type of lease, there is no obligation to pay the delay rental and there is no liability for failure to pay. Unless otherwise specifically provided for in the lease, the entire amount of the delay rental must be paid. Most leases permit the lessee to surrender a portion of the leased premises and then pay delay rentals on the balance. Delay rentals in most states are not a matter for negotiation as is the bonus and are usually in the amount of $l/acre/yr. Such is not the case in some areas, as in southern Louisiana. Here the delay rental is just as important as is the bonus as an item to be negotiated upon; it is the practice for rentals to be in an amount equal to at least one-third to one-half of the bonus consideration on a per-acre basis. The lease provides that rentals may be made on or before the specified date, payable to the lessor or to the lessor’s credit in a bank designated by the lessor. Most rentals are tendered by the lessee 3 to 6 weeks in advance of the due date to provide time for the lessee to receive a receipt from the lessor’s depository bank evidencing deposit of the rentals to the lessor’s credit. The lease also contains a proportionate-reduction clause or lesserinterest clause, which allows the lessee to reduce the amount of the delay rentals and royalty payments where the lessor does not own a full interest. Royalty Clause. A simple royalty clause might provide that the royalties to be paid by the lessee are (1) on oil and liquid hydrocarbons, one-eighth of that produced and saved from the land; (2) on gas, one-eighth of the market value at the well of the gas used by the lessee in operations not connected with the land leased, the royalty on gas sold by the lessee to be one-eighth of the amount realized at the well from such sales; (3) oneeighth of the market value at the mouth of the well of gas used by the lessee in manufacturing gasoline. The most common royalty is one-eighth, experience having shown this to be the most equitable fraction to be paid to the lessor in relatively unexplored areas. However, in known trends it is often difficult to purchase leases providing for a royalty of only one-eighth. Here again, the royalty is an item that must be negotiated in much the same manner as the bonus or delay rental. Royalties of one-sixth and more are now quite common in some areas. The royalty interest created at the execution of the lease is payable to the lessor in the event of production. It does not refer to any additional royalties that may be created by the lessee out of the working interest and that are called overriding royalties. It does not refer to an advance royalty that can be deducted from any subsequently accruing royalties. It does not refer to a minimum royalty, which is a sum the lessee agrees to pay in the event of production regardless of whether or not it is equivalent to the lessor’s share of gross production. A failure to pay royalties does not in itself effect automatic termination of the lease. Failure to pay
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royalties within a reasonable time could result in a forfeiture of the lease in a court action. Some delay, perhaps several months, in disbursing royalty is to be expected; title must be approved by the oil or gas purchaser and division orders circulated among those who will share in the production. Oil royalties are payable to the lessor either in oil or to the lessor’s credit in the pipeline, which is called payment in kind, or by payment in money based on the value of the royalty oil. Execution of a division order waives the lessor’s right to receive royalty in kind. Royalty is computed as a share of the gross and not as a share of the net production, which means the royalty is not burdened with any production costs. However, the lessor is required to pay his proportionate share of the cost of transportation and gross production taxes. Condensate or distillate is a liquid produced along with gas, but which originally was in the vapor phase in the reservoir. Casinghead gas is gas produced from an oil well. A gas well produces gas as distinguished from casinghead gas and may be defined in terms of gas/oil ratio by various regulatory bodies. The royalty payable on oil is also the royalty payable on condensate and other liquid hydrocarbons when separated on the leased premises. The royalties payable on gas are always payable in money and never in kind, and are subject to transportation costs. Royalty on gas is payable only on that gas which is sold or used off the leased premises. Royalty is not payable to the lessor on gas used by the lessee as a means of lifting the oil to the surface or that is injected into the reservoir for pressure-maintenance purposes. A gasoline plant may be justified in areas where there are sufficient reserves of rich gas. A lessee will often enter into a contract with a processing plant whereby his gas wells are produced full-well stream to the plant for extraction of liquid hydrocarbons. The independently owned plant will retain a percentage of the value of the liquid hydrocarbons removed as a processing charge and credit the lessee with the value of the balance of the separated liquids as well as with all the residue gas. The lessee then disburses royalty to the lessor in accordance with the terms of the lease. If the lessee owns an interest in the plant, the lessee may be required to pay royalty on extracted liquids and residue gas less only the actual operating costs of the plant depending upon the terms of the lease. The Pooling Clause. The pooling clause provides that the lessee, at its option, is given the right and power to pool or combine the land or mineral interest covered by the lease, or any portion thereof, with other land, lease or leases, and mineral interests in the immediate vicinity thereof, when in the lessee’s judgment it is necessary or advisable to do so in order to develop or operate the leased premises properly to promote the conservation of oil and/or gas. The clause further states that “any unit or pool created for the production of oil shall not exceed 40 acres and that any unit for the production of gas shall not exceed blank acres.” The number of acres inserted in the event of a gas well will vary from 160 to 640, depending on local practice. The term “pooling” refers to the combining of small tracts for the purpose of forming a unit on which a well may be drilled. A lease form should be used that contains
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an appropriate pooling clause. It may not be quite so important to obtain this right in certain areas where only oil is produced or in those states that provide for forced pooling and integration. The pooling right is related to development, and the owner of the working interest has the responsibility for such development. The lessee must act in good faith in exercising the pooling privileges granted in the lease. When a lessee declares a unit and places the unit declaration of record in accordance with the lease, it is presumably done in the interest of proper development and conservation. Caution should be exercised in planning a unit to be declared so the unit will be in reasonable conformance to the subsurface and seismic data available. A lessee who declares a unit of an unusual shape for the obvious purpose of holding a lease past its expiration date, or that includes acreage most likely not productive, or that tends to disregard available geological control is probably not acting in good faith. Such a declared unit may be vulnerable to attack by the lessors. When a lease contains a pooling clause, appropriate changes will appear elsewhere in the lease. The habendum clause may read, “this lease shall be for a term of blank years from the date hereof, called primary term, and so long thereafter as oil or gas is produced either on this land or on acreage pooled therewith, or with any part thereof. ” Operations for the drilling of a well or production from a well on a unit constitute operations or production from each of the tracts pooled.
the rental payment of the assignee shall not operate to defeat or affect the lease insofar as it covers that portion retained by the lessee. The “warranty clause” provides that the lessor warrants and agrees to defend the title the land leased. If the covenant of general warranty is breached, the lessee can recover the consideration paid for the lease with interest and the expenses incurred in defending possession. The lessee is given the right to redeem for the lessor, by payment, any mortgages, taxes, or other liens on the leased premises and to apply to the repayment of the lessee any rentals and/or royalties accruing under the lease.
Miscellaneous Clauses. Many miscellaneous clauses are found in leases for the benefit of the lessor or the lessee. The lessee is restricted in locating a well on the leased premises to the extent that no well may be drilled nearer than 200 ft to any house or barn. The lessee is required to lay pipelines at such a depth as not to interfere with plowing and cultivating operations. The lessee may be required to pay for all damages in connection with its operations on the land, although the damages are often restricted to timber and growing crops. A paragraph is often found in leases that has as its purpose the inclusion of small strips of adjacent land owned by the lessor but not specifically described in the lease. The lessor usually intends to include such small parcels of land in the lease, but for various reasons a description of the strip may have been omitted. This paragraph is called the “Mother Hubbard clause.” It is not intended that large tracts of land be subject to this clause but only strips or parcels of perhaps several acres in size. The lessee is given the right to use without cost gas, oil, and water produced on the leased premises for lessee’s operations thereon. The lessee is given the right to remove machinery and fixtures from the leased premises, including casing, within a reasonable period of time after the lease has terminated. The lease provides that the interests of the parties are assignable in whole or in part. No change in ownership of the land imposes any additional burden on the lessee until the lessee has been furnished with a certified copy of the recorded instrument evidencing the transfer. Since portions of many leases are eventually assigned, a clause is inserted to protect the lessee in the event of default in rental payments by the lessee’s partial assignee. It provides that in the event of partial assignment a default in
Assignments by the Landowner
The Implied Covenant. It is important to keep in mind that the underlying purpose of the lease is to secure production. Most leases have very little to say about the manner in which wells will be drilled, or even if a well will be drilled at all. Little is ever said about the well density or the intervals at which development wells will be drilled. The lack of specific agreement between the lessor and lessee in these regards is intentional. Too much is unknown about the nature and characteristics of any reservoir present. The obligations of the lessee are the obligations of an ordinarily prudent operator under the same or similar circumstances, considering the lessor’s interest as well as his own. The obligation to develop the leased premises as would a prudent operator arises only after discovery of oil or gas and continues for the life of the lease.
Right to Transfer. Fee owners can dispose of their land in any way they see fit, either in whole or in part. They can convey the surface and reserve the minerals, or vice versa. They can sell all or a divided part or an undivided interest in the minerals. They can sell all or a part of their interest in the proceeds from the minerals. They can create a subordinate interest and transfer it to another party, as is done when a lease is granted. Mineral Deeds and Interests. A mineral deed transfers the minerals or the right to obtain them as they exist in place. The owner of minerals has the right to go on the land, conduct exploratory operations, and produce oil and gas. If the minerals are subject to a lease at the time of the mineral conveyance, the mineral grantee may not exercise these rights until the lease terminates. The mineral owner has the right to execute a lease and to receive the bonus money therefrom. The mineral owner has the right to receive rentals and to share in the royalties if and when payable under any lease. Mineral interests are most often created by unqualified grants or reservations. However, many mineral conveyances are for a specified term of years, or for a specified term and so long thereafter as oil or gas is produced. Royalty Deeds and Interests. Royalty is a share in production and, when applied to a lease, refers to the share of the oil and gas that is received by the lessor from production under the lease. This share is usually one-eighth of the whole, although it may be any other fraction agreed upon. Royalty also refers to an interest that is created by grant or reservation either before or after the
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execution of a lease. The right to royalty is contingent on production and carries with it no right or interest in the minerals. The owner of a royalty interest receives no bonus and no delay rental payments. A royalty interest is an expense-free interest in the gross production and not in the net production. Royalties as well as minerals may be conveyed in fee or for a specified term of years, or for a specified term and as long thereafter as oil or gas is produced. When referring to a conveyed royalty interest, it is customary to refer to the number of royalty acres conveyed, as well as to the fractional interest. If a landowner sold half of his one-eighth royalty in a tract of 80 acres, the royalty grantee is said to have purchased 40 royalty acres. If a royalty buyer purchased one-eighth of the same landowner’s one-eighth royalty, the royalty purchaser would be entitled to one-sixty-fourth of all production and is said to own 10 royalty acres.
Assignments by the Lessee Right to Transfer. The lessee is the owner of the lease, and the interest is usually seven-eighths of the production but may often be much less, depending on the amount of royalty. This interest is referred to as the working interest. A lessee may transfer his entire interest either in whole or part, or an undivided portion in the lease or a part thereof. The lessee has the right to convey overriding royalties, production payments, undivided interests, or an entire interest in a portion of the leased premises. Assignments and Subleases. An assignment is a transfer of the assignor’s entire interest in a lease either in its entirety or in a portion thereof. A sublease is a partial transfer in that the sublessor retains an interest in the lease in so far as it affects the property subleased. An instrument conveying the working interest but providing for the reservation of an overriding royalty is a sublease rather than an assignment. Obligations undertaken by the lessee in the lease are called covenants. A contractual relationship exists between the lessor and the lessee, and there is said to be a privity of contract between the parties. The lessee has the right to assign the leasehold estate to a third party. The covenants contained in the lease are assumed by the third party and are said to be covenants running with the land. In the event of a true assignment, the lessee is usually relieved of his obligations to the lessor. In the event of a sublease, the lessee remains liable to the lessor because of the privity of contract between them. Overriding Royalty. An overriding royalty interest is an interest carved out of the working interest and is not burdened with the cost of development or production. It is therefore a kind of royalty interest. An overriding royalty is usually created in a sublease, but may be created by grant. It in no way affects the royalty interest that is payable to the lessor. The overriding royalty owner generally cannot require the lessee to maintain the lease in force, to drill a well, or to develop the property, and shares in oil and gas only when, as, and if produced.
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Production Payments. Oil payments, perhaps more correctly referred to as production payments, are related to overriding royalties in that they are usually carved out of the working interest and bear no cost of production. The overriding royalty differs from the production payment in that the former continues for the life of the lease and the latter terminates upon the payment of a specified sum of money from a stipulated percentage or fraction of the working interest. Production payments can be of practically any size and can be made payable out of any fraction or percentage of the working interest. The production payment is occasionally used in negotiating a lease. A company may be willing to spend not more than $lOO/acre as bonus for a lease but at the same time be willing to provide for a production payment of perhaps $2OO/acre payable out of one-sixteenth of seven-eighths. A landowner can occasionally be shown the advantages of a production payment, with the result that a deal is made instead of lost. The use of the production payment in the large-scale purchase of producing properties has become common. The task of how to purchase a producing property for a minimum cash outlay by the grantee with the grantor receiving the entire purchase price in cash and with the gain taxed at capital gains rates is often accomplished by an “ABC” transaction. A is the seller and the owner of the property. B is the purchaser of the property. C is the purchaser of the production payment and either has or can get the major part of the required cash. To illustrate, A owns a producing property that will sell for $l,OOO,OOO. B wants to buy the property but has only $200,000 for the purchase. A will convey the property to B for $200,000, retaining a production payment of $800,000 plus interest payable out of 85 % of the production. A will then sell the production payment to C for $800,000 cash. All parties to the transaction receive the maximum tax benefits allowed.
Unit Operations Background In recent years the objective has been to obtain the maximum ultimate recovery of oil and gas in place. In the early days of the industry a great number of unnecessary wells were drilled; only a fraction would have been required to obtain maximum efficient withdrawal. In time, limits were placed on the amount of production; wellspacing regulations came into existence; the establishment of drilling units and the pooling of small tracts of land followed. The advantages of cooperative development on a small scale became even more apparent when considered on the basis of the entire reservoir. Unit operation of a reservoir, whether for cooperative development, pressure maintenance, or secondary recovery, requires a knowledge of the hydrocarbons in place and an acceptance of the correlative rights of the owners; a fair distribution of the proceeds is best accomplished by contractual agreements among the royalty and working-interest owners. The unit operation of an oil and gas reservoir is to be distinguished from pooling, which is the combination of small tracts to form a drilling unit or comply with spacing regulations. The term “unitization” is usually used interchangeably with unit operations. Unitization
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therefore refers to the operation of all or a substantial part of the reservoir by a unit operator in accordance with the terms of a unitization contract. Unit operations may include two categories, depending on the manner in which they come into existence. Voluntary Unit Operations. When the owners of the interests in a reservoir agree that all or a major portion of the reservoir is to be operated as a single unit regardless of property or lease lines, a voluntary unit operation comes into existence. The preparation of a unitization agreement acceptable to all the parties is a major undertaking. Two contracts are entered into, an operator’s contract and a royalty owner’s contract, sometimes called the unit contract. Many problems are involved regarding the operation of the reservoir and the drilling of additional wells that are best handled in a separate contract among the owners of the working interest. The royalty-unitization agreement must expressly provide for the consolidation of the interests of the lessors. Without such authority, lessors could demand that their tract be drilled to prevent drainage or be developed separately. The working out of a voluntary-unitization agreement requires a thorough knowledge of the conservation statutes. The voluntary-unitization agreement may provide that the contract will not become effective until approved by the appropriate regulatory body. Compulsory Unit Operations. Compulsory unit operations come into being by order of a regulatory body in accordance with specific statutes. Early statutes provided that, if a certain percentage of the lessees in an area to be unitized petitioned the regulatory body to bestow jurisdiction to issue appropriate orders, it would do so. The laws of the states vary as to the percentage of ownership required. There must first be agreement among a majority of the lessees and royalty owners concerned regarding a unit plan. Here again a great deal of work and time are required. Numerous conferences are held among the working-interest owners and studies are made by various committees. Upon finalization of the plan, signatures are obtained from the working-interest and royalty-interest owners. A petition to the regulatory body is made and a hearing is held after proper notice has been given to all the interested parties. Upon issuance of the appropriate orders, accounting adjustments are made among the working-interest owners and the appointed unit operator assumes operations of the area.
Getting the Well Drilled Lease Purchases. Oil and gas leases are purchased for a variety of reasons. Lease purchases are often of a trend nature, with no drillable prospect having been shown to exist. Such lease purchases could be in a sedimentary basin considered likely to contain accumulation of hydrocarbons, or as extensions to discovery wells. The owners of the leases might then plan to conduct seismic operations in an effort to isolate and define likely structures on large lease blocks or spreads of acreage. However, the owner of a geological idea or unleased prospect may have sufficient subsurface and/or seismic
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data to justify the drilling of a well. In this instance, leases are acquired for the very definite purpose of drilling in the immediate future. Under such considerations, the amount of the rentals or the extent of the primary term becomes of secondary importance in negotiating the leases. A landman or lease broker will then be employed to review the records of the clerk of court to determine surface and mineral ownerships of all the tracts of land in the prospect including county roads, state and federal highways, rivers, school lands, canals, etc. Mineral leases will then be negotiated and acquired. Capital to Drill the Well. Major oil companies have no real problem in raising the necessary capital to drill wells. Such funds are, to a large extent, available from earnings, and to a lesser extent, from borrowings. However, independents have been historically short of cash to drill wells. An “independent” is a small corporation or a partnership or perhaps an individual engaged in oil and gas exploration only. That is, an independent is not engaged in the transportation and refining of petroleum or in the marketing of petroleum products. Independents drill approximately 85% of all wells drilled in the U.S. and there are thousands of small companies and individuals engaged flu11 time in oil and gas exploration. In recent years, the limited partnership has been the primary source of venture capital for the independent. Investors buy units of a drilling fund and become limited partners. An experienced and successful independent becomes the general partner. Another significant source of venture capital for drilling wells has been the utility companies and end-users, such as the chemical industry. A typical independent may spend $5 to $15 million a year in drilling money, almost none of which belongs to the independent. The capital comes fmm investors and from persons who buy into drilling deals. Regardless of the source of the capital, the independent invariably promotes or lays off a part of his deal, usually on a third for a quarter basis. This means that the patty being promoted or who buys into the deal will pay one-third of the cost of drilling the well for a one-quarter interest in the well. Variations of this type of promotion are endless; but by and large this type of promotion is standard between independents and investors as well.
Sources of Prospects. Major oil companies maintain large staffs of geologists, seismologists, paleontologists, and other supporting personnel engaged in development and exploration efforts. Major oil companies rarely participate in drilling on prospects not generated by them. On the other hand, most independents do not generate their own prospects but must buy them from geologists and others who generate geological prospects. The geologists, landmen, and others who can generate prospects and buy leases on them are then in a position, to a limited extent, to promote their prospect in dealing with an independent. Invariably, a nominal overriding royalty can be retained on the leases and occasionally a carried working interest to casing point. In this case it is difficult to obtain a carried working interest of as much as onequarter because the independent taking the deal must
OIL AND GAS LEASES
itself plan on laying off perhaps half of the deal and there must be some room left in the structuring of the deal to permit all concerned to realize some economic benefit. Abstracts and Title Examination. Abstracts will be ordered on at least the proposed drillsite and offsetting tracts, and perhaps even on the entire prospect. The abstract will usually contain exact copies of all instruments of public record pertinent to the land from patent to date. Qualified oil and gas attorneys will review the abstracts and render a title opinion. There are usually numerous title deficiencies, most of which can be met by appropriate curative effort by the landman or title man. Supplemental title opinions will be obtained after the curative materials have been procured. Rarely can every requirement be met and the lessee may have to elect to waive such unmet remaining requirements and assume the business risk of proceeding with the drilling of the well. Full-Interest Wells. When a lessee controls the entire acreage on all of the prospects it is fortunate indeed. The well can be drilled as the lessee pleases, being restricted only by appropriate regulations. Should the well result in being a producer the lessee will have control of the entire reservoir, assuming the lessee has more or less correctly anticipated the extent of the reservoir in the lease purchases. However, this situation is rarely found. Considerable work has yet to be done when a lessee is planning to drill a well and finds that all of the prospective acreage is not controlled. Joint-Operating Agreements. Generally a lessee thinking of drilling a well will have at least some leases on the prospect. The remaining leases will be owned by one or more competitors, presumably people who are also interested in drilling wells and establishing production. Since the owners of the leases covering the prospect will all benefit in the event of production, it would seem equitable that each pay a proportionate part of a well or make a suitable contribution to the well. However, it is not often that two or more lessees have the same data, or interpret the data in the same way. A lessee may elect to farm out its acreage, do nothing, or join in the drilling of a well. The other lessees will be contacted in an attempt to determine their interest in getting a well drilled. The other lessees may not have sufticient information to justify their joining in the drilling of a well. The party desiring to drill the well may find it desirable to make any information available to the adjacent lessees. This seismic or other control may represent a sizable investment, and the other lessees may be willing to pay for the data, exchange similar data of their own in another area, or negotiate almost any kind of agreement with the owner of the control. If all the lessees are eventually agreed that a joint well should be drilled, they will define a contract area that will be jointly owned. A joint-operating agreement will be entered into and the interests of the parties to the agreement determined on the basis of the surface acreage owned by each as compared with the total acres in the contract area. The joint-operating agreement will stipulate the interests of the participating parties, specify the operator, limit cer-
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tain expenditures, establish liabilities, provide for the drilling of the first and subsequent wells, provide for nonconsent operations, etc. Certain operating costs are agreed on and an accounting procedure is attached to the joint-operating agreement. The joint-operating agreement is a very useful tool in exploratory operations, particularly where the tracts of land are small or where it may be desirable to share the risk of an expensive exploratory well. Contract areas can be of practically any size but for exploratory purposes usually run from about 640 to several thousand acres in size. The joint-operating agreement is also used occasionally in development drilling. It finds frequent application in a unit or pool ordered by a regulatory body after a well has been completed as a producer. Cash Contributions. A lessee may find it necessary to drill a well on a reduced-acreage basis with cash support from the adjacent lessees who might not be willing to farm out or enter into a joint operation. The most common type of cash contribution is the dry-hole contribution. It is usually a sum of money per foot drilled, determined by reservoir participation, discounted for lack of ownership in the well, etc. This type of contribution gets its name from the fact that no money is payable in the event the well is completed as a producer. The idea here is that the offset lessee is willing to make a cash contribution toward the drilling of a well that in all probability will be dry but which will at least partially evaluate the leases. In the unlikely event the well is completed as a producer it is thought that the rewards are sufficiently great for the owner of the well to make cash payment from the offset lessee unnecessary. A variation of the dry-hole contribution is the bottombole contribution, which is payable upon reaching a specified depth regardless of whether or not the well is completed as a producer. Both types of cash contributions are used infrequently. Farmouts. A transfer of the working interest with the obligation to drill a well is called a farmout. There are any number of ways in which a farmout can be negotiated. A farmout agreement provides for the drilling of a well, or the option to drill a well, at a mutually agreed location and to a mutually agreed depth on one of the leases owned by the party making the farmout. Upon completion of the well in accordance with the terms of the farmout agreement, the lessee will assign or sublease a portion of the leases and retain an interest, usually an overriding royalty. The amount of the overriding royalty will vary widely from area to area and will depend on a number of factors including the available geological and geophysical control, the amount of the working interest, the proximity of production, producing history in the area, lifting problems, suitable markets, size of the anticipated reservoir, the number of acres being farmed out, well costs, etc. The operator that takes the farmout will be looking to the net revenue interest to recover costs. Gross income from the sale of production less royalty, overriding royalty, and any other burdens on the leases determines net revenue interest. Acceptable net revenue interests on farmouts vary widely: a net revenue interest in Oklahoma under a pooled section might be considered
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unacceptable if less than 81.25%; in North Dakota in a wildcat well, 75%; in Louisiana in a low risk, close-in prospect, 68 % A more complicated version of the farmout is found in the better producing areas. Such farmouts are often made on the basis of a portion of the working interest being retained by the party making the farmout. A typical arrangement might be the farmout of perhaps 2,000 acres on a 60/40 basis for a free well into the tanks to 12,000 ft. The party taking the farmout would agree to drill and complete a 12,000-ft test at the party’s sole cost and risk and thereby earn an assignment of an undivided 60 % interest in the 2,000-acre block. If the well is productive the party making the farmout owns 40% interest in the well and in the production, usually after the operator has recovered the costs to take full advantage of available tax deductions. The party taking the farmout will obtain payout from the proceeds of the sale of production from the earning well less any royalties and overriding royalties. Subsequent operations on the farmout block would be under the terms of a joint-operating agreement. Variations of this type of deal are countless. The well could be a free well through the wellhead rather than into the tanks. This means the operator would pay for all completion costs through the well head but would share on a 60140 basis in erecting tanks and treating equipment. Another variation is the free well to the sand. This means the operator would drill the well (at sole cost and risk) to the objective horizon, run an electrical log, and core and test as might be required to determine the possibility of production. If a decision is made to attempt a completion the operator will pay a negotiated fraction of the cost of running a production string of casing and setting subsurface production equipment, with the party making the farmout paying the remainder of the cost. Any interest may be negotiated; one-quarter and onethird interest deals are commonly made. Other variations might allow the operator to recover completion costs before the party making the farmout would be entitled to any share of the production. The party making the farmout might keep an overriding royalty during partial or complete payout and at the time of the payout would have the option to exchange the overriding royalty for a working interest. Carried Interest. A carried-interest contract is an arrangement between co-owners of a working interest, whereby one agrees to advance all or some part of the development or operating costs on behalf of the others and to recover such advances from future production, if any, accruing to the other owners’ shares of the working interest. The co-owner advancing such costs is referred to as the carrying party and the co-owners for whom costs are so advanced are referred to as the carried parties. A carried interest usually comes into being in connection with a farmout. The carried-interest contract may apply not only to the first well but to subsequent wells. The party making the farmout may assign a portion of the working interest to an operator who will pay all the costs of drilling and equipping the first well, and possibly additional development wells. The grantee must look to the production, if any, attributable to the grantor’s share of the working interest to recovery the gran-
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tor’s share of such costs. A carried interest is a share in the net and not the gross production. Net-profits Interest. A net-profits interest is an interest in gross production measured by the net profits fmm the operation of an oil and gas property. A net-profits interest is similar to an overriding royalty in that it is created out of the working interest. The proceeds accruing to a net-profits interest are reducible by certain development and operating costs, which are specified in the net-profits contract. The net-profits interest is subject to such expenses to the extent of its share of the income. The owner of a net-profits interest is not required to pay out or advance money for development or operating costs, as in the case of the owner of a working interest, and is not liable for such costs. If no net profit is realized from the operation of the property the net-profits-interest owner receives no income but neither is the owner liable to the operator for a share of the loss. A net-profits interest can be regarded as a non-operating interest similar to an overriding royalty. The net-profits agreement finds its principal application in farmouts. Equitable as it may sound, this type of agreement is seldom used.
Lease Problems During Development The lessor is often pleased and even overwhelmed by the discovery of hydrocarbons on the land and the sudden cash flow of royalty. Problems early in the development phase, such as the use of the surface for tank batteries, gathering lines, treating equipment, and roads are usually settled quickly. After a period of time, new problems arise of a subtle and sophisticated nature. As some lessors seek to maximize their royalty income, they turn to petroleum consultants and oil and gas attorneys for advice. From this effort come legal demands for additional development or release of undeveloped acreage. While development can occur both horizontally and vertically, lessor demands for development have generally been sustained by the courts in a horizontal sense only, A more recent and more complex problem relates to the gas royalty clause and market value. The typical lease refers to the lessors’ royalty as a fraction of market value. When a lessee discovers gas and enters into a long term contract for the sale of gas, the market value of gas and the contract price for gas are almost identical. However, the price of natural gas in recent years has risen dramatically. The lessee is sometimes contractually bound to a gas price with the purchaser and at the same time faces a demand from the lessor for gas prices at market value. The courts are not uniform from state to state on this issue. The U.S. Natural Gas Policy Act of 1978, with its price ceilings on categories of natural gas, may have been of some use in defending lessor suits for market value on royalty gas. Lessees now appear to be leaning to short-term gas contracts, provisions for frequent renegotiation of price, rewriting the gas royalty clause to provide for “price received” rather than market value, providing for in-kind royalty on gas, etc. Whether or not lessees will be successful in negotiating such gas contracts in periods of falling demand remains to be seen. Similarly, it can be expected that lessors and their attorneys will resist any changes in the lease form from the conventional wording on gas royalty. Resolution of this problem lies ahead.
OIL AND GAS LEASES
Taxation* The taxation of income related to oil and gas is a highly specialized field. The increasing complexity of tax laws and the very real effect that taxes have on the successful conduct of any business make it imperative that competent tax advice be sought out by any operator. however small his organization may hc. The importance of tax planning can hardly be overestimated. Improper ~tructuring of a drilling deal or a sale of a property from a tax standpoint can have the most serious of consequences. The larger organizations and major oil companies have tax departments comprised of specialists in the various subdivisions of taxation. Independents and small organizations must retain the services of tax consultants on a continuing basis. Very briefly, all income less certain exclusions exempt from tax is gross income. Taxable income is gross income less deductions. Tax rates vary for individuals and corporations, as do long-term capital gains rates for individuals and corporations. Items of tax preference are deductions such as the excluded portion of capital gains, depletion, accelerated depreciation, and excess intangible drilling costs on productive property, all of which are subject to a minimum tax. Capital expenditures are not immediately deductible as are expenses, and must be recovered through depreciation or depletion. Some expenses. such as accelerated depreciation, are recaptured at sale, that is, become taxable at ordinary rates. The cost of tangible property used in business results in certain tax credits that are subtracted directly from the taxes due and are not a deduction. Capital expenditures include the bonus costs of purchasing mineral leases. well and lease equipment, and most geological and geophysical exploration costs. Deductible expense items include overhead, lease rentals. abandoned leases, most intangible drilling costs, and geological and geophysical costs not resulting in lease acquisitions. The enormous sums of money put into oil and gas exploration by private investors through limited partnerships deserve further comment. The private investor has taken advantage of the tax provisions in three principal areas: depletion, intangible drilling and development costs, and capital gains. Depletion. A producing reservoir gradually suffers a reduction in the quantity and value of hydrocarbons in place. Depletion laws were enacted to provide for a return of capital because of mineral extraction. The taxpayer has a choice of two methods. Cost depletion provides for a reduction in basis as related to production and sale of minerals. Percentage depletion provides for a deduction of a percentage of the gross income from the property, which is limited to 50% of the net income from the property, and to 65 % of net income from all sources. The U.S. Tax Reduction Act of 1975 effectively repealed percentage depletion, with certain exceptions. An exemption was allowed for independent producers and royalty owners as a percentage of qualified production, except as to transfers of producing property. For 1984 ‘Written More Ihe Tax Reform Act of 1986. which lmplementschanges I” alternal~ve m,n,mum tax. depletion. depreclatlan. ~n~eslment tax cred# and deducton 01
losses
57-11
that percentage will be 15% of the first 1,000 BOPD produced, or 6 million cu ft/D gas. Intangible Drilling and Development Costs. Taxpayers owning operating rights and incurring intangible costs may elect to expense or capitalize such costs. If the taxpayer elects to capitalize, the intangible drilling costs may be recovered through depreciation over 5 years, and are subject to an investment tax credit. Such capitalized costs do not represent a tax preference item. Since capitalization of such costs offers no real tax benefits, most taxpayers elect to expense such costs. Intangible drilling costs may represent 80 to 90% of the cost of an exploratory well; the remaining portion representing tangible costs of equipment with salvage value. It is no surprise to note the enormous success of drilling funds through limited partnerships as such large deductions are made available to investors. Capital Gains. A sale of a capital asset after a holding period set by law will subject the taxpayer to greatly reduced tax rates of a maximum of 20% of the profits of the sale. The sale of leases, either producing or nonproducing, is subject to these favorable capital gains tax rates. The attraction of such favorable tax treatment in the event of future sales of properties has been a further inducement to investors in oil and gas exploration
Offshore Leasing Jurisdiction. Fifteenth and sixteenth century explorers claimed vast areas of waters, entire gulfs, seas, and oceans. However, these early claims, as a practical matter, were unenforceable. The extent of national sovereignty over the waters has not been resolved in international law. By presidential proclamation in 1945, the U.S. regards the natural resources of the Outer Continental Shelf (OCS) as a territory owned by the nation. The Submerged Lands Act of 1953 confirmed the jurisdiction and control of the U.S. over the natural resources of the seabed of the continental shelf seaward of the state boundaries. Producing and Leasing History. The first commercial oil production in the Gulf of Mexico was discovered in 1947 on a Louisiana state lease. Drilling on federal lands under the OCS Lands Act began in 1954. Since 1956, the OCS (Atlantic, Pacific, Gulf of Mexico, and Alaska, comprising over more than 1 billion acres) has produced about 6 billion bbl of oil and about 55 Tcf gas. Leasing has proceeded at a snail’s pace. For years, into the early 1970’s, the abundance of oil and gas onshore and in world markets suppressed offshore leasing exploration with its high costs. As the search intensified, efforts to schedule lease sales met with great opposition from environmental groups. The time required for environmental assessment, state and local government comment, and so on, sometimes exceeded 3 years. The U.S. Dept. of Interior recently has moved to accelerate lease sales; almost the entire continental shelf will have been offered for lease at scheduled dates through 1987. Leasing Procedure. The interior secretary prepares a proposed 5-year leasing program. In the preparation phase, the secretary invites and considers suggestions
57-12
from the governors of affected states, local government, industry, federal agencies, and all interested parties, including the general public. Time is provided for a response from the governors and others after preparation of a draft of a proposed program, and prior to publication in the Federal Register. Time is again provided for a response following publication and prior to submission to the president and congress for approval. The director of the Bureau of Land Management issues calls for nominations pursuant to an approved program, conferring with the governors where indicated. A list of tracts tentatively selected for leasing is drawn up. The director is free to make deletions or additions from the tentative selection of tracts. A selected tract will, in general, not exceed 5,760 acres. Upon approval by the secretary, the proposed notice of sale will be published in the Federal Register. The governors and local governments concerned again have an opportunity to comment. The secretary will make the final decision and will publish the notice of sale in the Federal Register. The sale itself will be held no sooner than 30 days after publication. Tracts are offered for lease by competitive sealed bidding. Leases are issued only to qualified bidders. Leases are issued for an initial period of 5 years, although longer times are provided for where unusually deep water or adverse conditions would discourage exploration and development. Annual rentals are due in advance to maintain the lease in the absence of production. Royalties bid are variable with one-eighth royalty being a minimum. Royalties on all leases in the Gulf of Mexico average about one-sixth. After being awarded a lease, a lessee seeks to obtain the necessary permits. The lessee or operator will usually drill one or more test wells to determine whether hydrocarbons are present. If oil and/or gas is discovered, the operator, as a matter of common practice, will abandon the exploratory holes without attempting to complete
PETROLEUM
ENGINEERING
HANDBOOK
or produce from them. Exploratory wells are usually used to obtain information about potential oil and gas accumulation. Development or production wells are normally drilled from a production platform. Economic Impact of Offshore Leasing. The interior secretary has stated that 85% of America’s untapped oil wealth is on publicly owned lands, of which two-thirds is ‘thought to be offshore. The economic implications for the future in exploring and developing such reserves are truly significant. The amount of capital required for such exploration and development is staggering. But consider the recent past: the OCS has produced about 6 billion bbl oil and 55 Tcf gas. There would appear to be little question about the ever-increasing significance of the leasing, exploration, and development of lands comprising the ocs.
General References Hardy, George W. III: Louisiana Petroleum Land Operarims, Inst. for Energy Development Inc., Oklahoma City (1980). Kunrz, Eugene: Kuna Oil and OH (1960).
Gas, W.H. AndersonCo., Cincinnati,
Mosburg, Lewis G. Jr.: Perroleum Land Pracrices, IED Exploration Inc., Tulsa (1978). Mosburg, Lewis G. Jr.: Basics ofSwucturing fiplorabn Exploration Inc., Tulsa (1979).
Deals, IED
“Outer Continental Shelf Mineral Leasmg and Rights-of-Way Granting Programs,” Circular No. 2446, U.S. Dept. of the Interior, Bureau of Land Management (1979). Prentice-Hull Federul Tux Handbor~k, Prentice-Hall Inc., Enplewood Cliffs. NJ (1986). Woodard, Robert G.: Basic Land Management, Development Inc., Oklahoma City (1982).
Inst. for Energy
Chapter 58
The SI Metric System of Units and SPE Metric Standard Society of Petroleum
Engineers
Adopted
standard
for use as a voluntary
by the SPE Board
of Directors,
June 1982.
Contents Preface............... Part 1: S&The
lnternahonal System of Units
Introduction SI Units and Unit Symbols Application of the Metric System Rules for Conversion and Rounding Special Terms and Quantities Involving Mass and Amount of Substance. Mental Guides for Using Metric Units Appendix A (Terminology) Appendix B (SI Units) Appendrx C (Style Gurde for Metnc Usage) Appendix D (General Conversion Factors) Appendix E (Tables 1.8 and 1.9)
58-7 58-a 50-8 58-9 58-11
58-14 58-20
Part 2: Discussion of Metric Unit Standards
.58-21
Introduction ...... ............... Review of Selected Units ............. Umt Standards Under Discussion ....... Notes for Table 2.2 ... ............... Notes for Table 2.3 .................
58-21 .58-22 58-24 58-25 .58-25
58-2
PETROLEUM
ENGINEERING
HANDBOOK
Preface The SPE Board in June 1982 endorsed revisions to “SPE Tentative Metric Standard” (Dec. 1977 JPT. Pages
proposed and/or adopted by other groups involved in the metrication exercise, including those agencies charged
1575
with
161 1) and adopted
it for
Members
of
the
implementation
as this
is the final product of 12 years’ and Metrication Committee.
Metrication
Subcommittee
included
John M. Campbell, chairman. John M. Campbell & Co.: Robert A. Campbell. Magnum Engineenng Inc.; Robert E. Carlile. Texas Tech U.; J. Donald Clark, petroleum consultant; Hank Groeneveld, Mobil Oil Canada:
Terry
Pollard.
Howard B. consultant. With
very
retired.
Bradley.
et--c@io
member:
professional/technical
few exceptions.
and
training
the units shown
Part 1: SI-The
are those
mercial
still to be decided,
and internationally)
standards.
These few exceptions,
are summarized
in the introduction
to
Part 2 of this report. These standards include most of the units used commonly by SPE members. The subcommittee is aware that some will find the list incomplete for their area of specialty.
Additions
will
continue
lo be made but too
long a list can become cumbersome. believes that these standards provide
The subcommittee a basis for metric
practice beyond the units listed. So long as one maintains these standards a new unit can be “coined” that should prove
acceptable.
SI Units and Unit Symbols3
scientific,
groups
(nationally
metric
International System of Units*
Introduction Worldwide
the responsibility
for establishing
“SPE Metric Standard.” The following standard work by the Symbols
engineering,
are converting
industrial.
to SI metric
and cotnunits.
Many
The short-form kg for
designations
kilograms,
m for
of units (such as ti for feet. meters,
mol
for moles,
etc.)
in the U.S. arc now active in such conversion. based on work accomplished by national ’ and international’ authorities. Various U.S. associations. professional
have heretofore been called unit “abbreviations” in SPE terminology to avoid confusion with the tetm “sym bols” applied to letter symbols used in mathematical
societies.
equations.
and agencies
are involved
in this process.
in-
cluding. but not limited to. the American Sot. for Testing and Materials (ASTM)? American Petroleum Inst. (API).‘.’ American Nat]. Standards Inst. (ANof Mechanical Engineers SI), ‘.’ American Sot. and
(ASME).’
American
Natl.
Metric
Council
practice bols”;
However, is to call
international these unit
the latter usage will
and national
designations
be followed
standard
“unit
sym-
in this report.
SI Units SI
is based
on seven
well-defined
“base
units”
that
(ANMC).X The Canadian Petroleutn Assn. (CPA) and other Canadian groups have been especially active in conversion work. ” SPE intends to hccp its worldwide
quantify seven hn.sc~ ymntitic~ that hi c,orz~wztiorz are regarded as dimensionally independent. It is a matter ot choice how many and which quantities arc considered
memberahlp
base quantities.’ SI has chosen the seven babe quantities and base units listed in Table I. I * as the basis of the lntcrnational System. In addition, there arc two “sup-
metric
informed
on the conversion
to and use of SI
unit,.
The term “SI” ternational
is an abbreviation
d’Unit&
Units. SI is not identical
or
The
for Le Systgme
International
In-
System
of
Tables with any of the former
cgs, mks, or
mksA systems of metric units but is closely related to them and is an extension of and improvement over them. SI measurement
symbols
are identical
As in any other language,
in all languages.
rules of spelling,
punctuation,
and pronunciation are essential to avoid errors in numerical work and to make the system easier to use and understand on a worldwide basis. These rules, together with decimal usage, units coherence, and a series of standard
prefixes
for multiples
and submultiples
of most
SI units, provide a rational system with minimum difficulty of transition from English units or older systems of metric units. Refs. 1 through 4 of this paper are recommended to the reader wishing official information, development history, or more detail on SI: material from these and other references this report. Appendix
plcmentary
A provides
cited has been used freely
definitions
in
for some of the terms
used. ‘Prepared by T A Pollard for the subcommittee Based on paper SPE 6212 presented by T A Pollard at Ihe ,976 SPE Annual Techn~ca, Conference and EXhlb, ho”. New Orleans. act 3-6
quantities” 1. I
and
(Table 1.2
designating the dimensions physical quantities, plus mathematical SI “&rived
I .2).
show
current
practices
equations. units”
arc a third claxs.
boning. as needed, base units. other derived units according
formed
by con-
supplementary units. and to fhe algebraic relations
linking
the corresponding
derived
units that do not have their own individual
bols arc obtained by using multiplication and division. exponent> I11 s
I
rad.\-‘). Table cluding
for
of base and supplementary letter symbols for use in
(e.g..
SI velocity.
SI anoular e I.3 contains
velocity.
quantities.
symbols
for sytn-
the mathematical signs for together with appropriate meter per second. radian per second.
a number
all the I9 approved
The
of SI derived
m/s or radis or
unit>.
in-
units assigned special names
and individual unit hymbolh. Appendix B provides a more dctallcd cxplanatmn their dct’initions. the S! system of unils.
oi Xld
ahhr-aviations. ‘Table and flgure numbers of Ihe or,glnal SPE publ,cat,on chapter
are used fhroughout
,h,s
58-3
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
Style and Usage
SI Unit Prefixes* The Sl unit prefixes.
multiplication
symbols
in Table
are shown
factors,
and SI prefix
1.4. Some of the prefixes
Take care to use unit symbols in international
and national
properly: standards
the agreements provide
uniform
may seem strange at first, but there are enough familiar ones in the list to make it relatively easy for technical
rules (summarized in Appendix C). It is essential that these rules be followed closely to provide maximum ease
personnel
of communication and to avoid costly errors. of unit names varies somewhat among different
milli, and scientists.
to adjust to their use; kilo, micro
One particular
are
known
warning
to
mega, deci, centi,
most
is required
engineers
and
about the prefixes:
because of language differences, Appendix C should minimize
in the SI system, k and M (kilo and mega) stand for 1000 and 1 000 000, respectively, whereas M and MM or m
communication.
and mm have been used previously designating thousands and millions
Usage for Selected Quantities
in the oil industry for of gas volumes. Note
is the use of explicitly
while the customary M and MM prefixes were not. Examples: km’ means cubic kilometers, not thousands of cubic meters; cm* means square centimeters, nor one-
nebtlton is (kg. m)/s’,
hundredth
of a square meter.
The designation
for 1000
cubic meters is
10’ m’--not km3 and Mm’, respectively. Appendix C gives examples of the vital importance of following the precise use of upper-case and lower-case letters for prefixes
Application
and for unit symbols.
SI is the form
distinct
is restricted
engineering
units
units for mass and force. to the unit
of mass.
The
the only SI unit of force, defined as I to be used wherever force is designated, in-
cluding derived units that contain force-e.g., pressure or stress (N/m* =Pa), energy (N.m=J), and power [(N.m)/s=W]. There is confusion
over the use of the term weight as a
quantity to mean either force or mass. In science and technology, the term weight ofa body usually means the if applied
to the body,
would
give
it an ac-
system preferred
for all ap-
varies in time and space; weight,
that this modernized
version be
and properly applied. Appendix material,
This secprovides
varies also. The term force of gravity (mass times celeration of gravity) is more accurate than weight this meaning.
of the metric
It is important
thoroughly understood tion, together with
In SI. kilogram
system of metric
celeration equal to the local acceleration of free fall (g, when referring to the earth’s surface). This acceleration
General plications.
from the gravimetric
force that,
of the Metric System
but using the rules in most difficulties of
Mass, Force, and Weight. The principal departure of SI
carefully. however, that there is no parallelism because SI prefixes are raised to the power of the unit employed,
cubic meters is IO’ m3 and for I million
Handling countries
guidance and recommendations concerning usage of the SI form of the metric system.
style
length mass time” electric current* * thermodynamic temperature amount of substance luminous intensity
In commercial the term weight
TABLE 1.1 -
Base Quantity or “Dimension”
and
SI BASE WANTiTlES
SI Unit
always
ac-
for
use, on the other hand, means mass. Thus,
when
AND UNITS
SI Unit Symbol (“Abbreviation”), Use Roman - (Upright) Type
meter kilogram second ampere kelvin mole + candela
‘The seven base unrls. two supplementary units and other terms are “SPE heretofore has arbrlrar~ly used charge q. the product of sfectrlc tWh%nthe moleis used.the eler~ntaryentitw rWSt be Spenhed;they the terms kilogram m&.““pound mole.” etc., often are shortened
and everyday nearly
if used to mean force,
k” i K mol cd
SPE Letter Symbol for Mathematical Equations, Use Italic (Sloping) Type L m t
r n
deiined I” Appendixes A and 6. Part 1. current and time, as a basic dunenslon. In untt symbols this would be A.s. m SPE mathematical symbols. IV r~ybeatOrt~s. rm%WeS. iOnS.el8c1rOnS.other partlCla% OrSpW&l groupsof suchpartides. In petroleum work. erroneously to “mole.”
TABLE 1.2 -
SI SUPPLEMENTARY
UNITS’
Supplementary Quantity or “Dimension”
SI Unit
SI Unit Symbol (“Abbreviation”), Use Roman (Upright) Type
plane angle” solid angle’ ’
radian steradran
rad sr
‘The seven base umts, two supplementary units. and other terms are defmed I” Appendaxes A and 8. Part 1 “IS0 speafn?s these two angles as dlmensnnless wth respect to the seven base quanhties
SPE Letter Symbol for Mathematical Eauations. Use Italic’ (Sloping) Type
h
PETROLEUM ENGINEERING
58-4
TABLE 1.3 -
SOME COMMON SI DERIVED UNITS SI Unit Symbol (“Abbreviation”), Use Roman Type
Unit
Quantity
gray meter per second squared becquerel radian per second squared radian per second square meter degree Celsius kilogram per cubic meter sieverl farad coulomb siemens volt per meter henry volt ohm volt joule joule per kelvin newton hertz Iux candela per square meter lumen ampere per meter weber tesla volt watt Pascal coulomb joule watt watt per steradian joule per kilogram kelvin Pascal watt per meter kelvin meter per second Pascal second square meter per second volt cubic meter 1 per meter joule
absorbed dose acceleration activity (of radionuclides) angular acceleration angular velocity area Celsius temperature density dose equivalent electric capacitance electric charge electrical conductance electric field strength electric inductance electric potential electric resistance electromotive force energy entropy force frequency illuminance luminance luminous flux magnetic field strength magnetic flux magnetic flux density potential difference power pressure quantity of electricity quantity of heat radiant flux radiant intensity specific heat stress thermal conductivity velocity viscosity, dynamic viscosity, kinematic voltage volume* wave number work
HANDBOOK
GY Bq
“C .., sv E S Ii V n V J N HZ lx Im Wb T V W Pa C J W .
Formula, Use Roman Type J/kg ml.9 1Is rad/s2 rad/s m2 K kg/m3 J/kg A.sN ( = GN) As AN V/m V&A ( = Wb/A) W/A VIA W/A N.m J/K kgm/$ l/s lm/m2 cd/m2 cdsr A/m vs Wb/m2 W/A J/s N/m2 As N*m J/s Wlsr
J(kgW Pa .
,.. V .. . J
Nlm2 W/(m.K) m/s Pas ml/s WIA m3 l/m N.m
‘In 1964, the General Conference on Welghls and Measures adopted liter as a special name for the cubic decimeter but discouraged the use of later for volume measurement 01 extreme precision (see Appendix 8).
TABLE 1.4 -
SI Prefix
Multiplication Factor 1 000 OOLl000 000 000 000 = 1 ooo 000 000 000 000 = 1 000 000 000 000 = 1 000 000 000 = 1000000 = lOOO= 100 = 10 = 0.1 = 0.01 = 0.001 = 0.000001 = 0.000 000 001 = 0.000 000 000 001 = 0.000 000 000 000 001 =
10’8 10’5 10’2 1OQ 106 103 102 10 10-l 10m2 10m3 1Om6 10eg lo-l2 lo-l5
exa** peta” tera giga mega kilo hectot deka$ deci$ centi* milli micro nano pica femto
0.000 000 000 000 000 001 = 1Om’8 atto
SI UNIT PREFIXES
SI Prefix Symbol, Use Roman
TypeE P T G M k h da
a
Pronunciation (U.S.)” ex’ a (a as in a bout) as in p eta1 as in terra ce jig’ a (a as in a bout) as in mega phone as in kilo watt heck’ toe deck’ a (a as in a bout) as in deci mal as in senri ment as in mili tary as in micro phone nan’ oh (an as in an t) peek’ oh fern’ toe (tern as in fern inine) as in anafo my
Meaning (U.S.)
Meaning In Other Countries
one quintillion timest one quadrillion timest one trillion timest one billion times7 one million limes one thousand times one hundred times ten times one tenth of one hundredth of one thousandth of one millionth of one billionth oft one trillionth oft one quadrillionth oft
milliardth billionth thousand billionth
one quintillionth oft
trillionth
trillion thousand billion billion milliard
‘The l~rsl syllable of every prehx IS accented lo assure that the prellx will retain Its Ideniiiy Therefore. the prelerred pronunxlion of kllomeler places the accent on the first syllable, not the second. “Approved by the 15th General Conlerencs of WaghIs and Measures (CGPM). May-June ,975. tThese terms should be avoided in technaal wrong because the denomlnatnns above 1 millon are dlflerent in most other countries. as lndlcated I” the last column. tWhtle hecto, deka.dect, and cents are St prehxes. their use generally should be avolded except for the SI UN mult~pleslorarea. volume, moment, and nontechmcal use of centmwer, as for body and clothing meas”reme”t.
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
one speaks of a person’s
weight,
the quantity
referred
to
58-5
Energy. The SI unit of energy,
the joule,
together
with
is mass. Because of the dual use, the term weight should be avoided in technical practice except under cir-
its multiples, kilowatt-hour
cumstances in which its meaning is completely clear. When the term is used, it is important to know whether
energy,
mass or force is intended and to use SI units properly as described above by using kilograms for mass and
megajoule.
newtons
Torque and Bending Moment. The vector product of
for force.
Gravity
is involved
or scale.
When
in determining
a standard
mass with a balance
mass is used to balance
the
new
but this unit
areas;
force (N
is preferred for all applications. The is used widely as a measure of electric should
eventually
and moment
it
not be introduced should
be
arm is expressed
m) by SPE as a convention
into any
replaced
when
by
the
in newton
meters
expressing
torque
measured mass, the effect of gravity on the two masses is canceled except for the indirect effect of air or fluid
energies.
buoyancy.
indirect-
Pressure and Stress. The SI unit for pressure and stress
ly since the instrument responds to the force of gravity. Such scales may be calibrated in mass units if the variation in acceleration of gravity and buoyancy corrections
is the Pascal (newton per square meter); with proper SI prefixes it is applicable to all such measurements. Use of
On a spring scale, mass is measured
are not significant
in their use.
the old metric gravitational units-kilogram-force per square centimeter, kilogram-force per square millimeter, torr,
etc.-is
to be discontinued.
Use
of
the
bar
is
The use of the same name for units of force and mass causes confusion. When non-9 units are being con-
discouraged
verted to SI units, distinction ,forcr and mass-e.g., use
should be made between Ibf to denote force in
It has been recommended internationally that pressure units themselves should not be modified to indicate
gravimetnc
and use Ibm for mass.
whether the pressure is “absolute” (above zero) or “gauge” (above atmospheric pressure). If the context is meant, the word leaves any doubt as to which
engineering
Use of the metric common.
units,
ton, also called
mnne
(1.0 Mg),
is
by the standards
“pressure”
Linear Dimensions.
Ref.
3 provides
discussions
length units applied to linear dimensions of materials and equipment, primarily engineers
of
and tolerances of interest to
Temperature. The SI temperature unit is the kelvin (not “degree Kelvin”); it is the preferred unit to express therderived
must
pressure
be qualified of
appropriately:
13 kPa,”
pressure of 13 kPa,”
or
“. . .at
“...at an
a
absolute
etc.
Units and Names To Be Avoided or Abandoned
in that field.
modynamic
gauge
organizations.
temperature.
Degrees
Celsius
(“C)
is an SI
Tables
1.1 through
formal
names,
their
all SI units identified
individual
unit symbols.
by Vir-
tually all other named metric units formerly in use (as well as nonmetric units) are to be avoided or abandoned.
and temperature
There
called centigrade)
“esu,”
unit used to express temperature
1.3 include
with
is a long
list of such units
(e.g.,
dyne.
stokes.
is related directly to the kelvin scale as follows: the temperature interval 1 “C= 1 K, exactly. Celsius temperature (Tot) is related to thermodynamic
gauss, gilbert, abampere, statvolt, angstrom. fermi, micron, mho, candle, calorie, atmosphere, mm Hg, and metric horsepower). The reasons for abandoning the non-9 units are discussed in Appendix B. Two of
temperature (Tx) where To =273.1.5
coherence
intervals.
symbol
The Celsius
scale (formerly
as follows: Tot =TK --To exactly, K by definition. Note that the SI unit
for the kelvin
whereas
the
older
degrees
Fahrenheit,
Celsius, with degree (“F, “R, “C).
is K without
temperature degrees marks
the degree
units
are
Rankine,
shown
on the unit
reasons are the relative
simplicity
as
degrees symbol
Rules for Conversion
and Rounding3
Conversion Table 1.7, Appendix
D, contains
general conversion
tors that give exact values or seven-digit
Time. The SI unit for time is the second, and this is preferred, but use of the minute, permissible.
hour,
day, and year is
Angles. The SI unit for plane angle is the radian. The use of the arc degree and its decimal submultiples is permissible when the radian is not a convenient unit. Use of the minute and second is discouraged cartography. steradians.
Solid
angles
should
except possibly be
expressed
for in
plementing dimension
ferred
for all applications.
but use of the liter is restricted uids and gases.
The
special
for the cubic decimeter
name liter
has
(see Appendix
B),
to the measurement
of liq-
for im-
the nature
of the
all conversions, the number of significant should be such that accuracy is neither
digits
retained
sacrificed nor
exaggerated. Proper specified given
Volume. The SI unit of volume is the cubic meter. This unit, or one of its regularly formed multiples, is pre-
these rules except where makes this impractical.
fac-
accuracy
The conversion of quantities should be handled with careful regard to the implied correspondence between the accuracy of the data and the given number of digits. In
11.4
conversion procedure is quantity by the conversion
in Table
number
been approved
and the
of the SI units.
mark,
known
and
the principal
1.7 and then
of significant ft
to
meters:
rounds to 3.47
digits.
round
to multiply the factor exactly as to the appropriate
For example,
11.4x0.3048=3.474
to convert 72,
which
m.
Accuracy and Rounding Do not round either the conversion before
performing
the multiplication;
factor or the quantity this
reduces
ac-
PETROLEUM ENGINEERING
56-6
curacy. Proper conversion procedure the converfed quantity to the proper cant digits
commensurate
with
includes rounding number of signifi-
its intended
precision.
or “maximum,”
HANDBOOK
is not violated.
must be handled so that the stated limit For example, a specimen “at least 4 in.
wide”
a width
requires
of at least 101.6 mm, or (round-
The practical aspects of measuring must be considered when using SI equivalents. If a scale divided into six-
ed) at least 102 mm.
teenths of an inch was suitable for making the original measurements, a metric scale having divisions of 1 mm
Significant Digits. Any digit that is necessuy
is obviously equivalents
suitable
for measuring
in SI units,
and the
should not be reported closer than the nearest
the specific For example, have
to drjne is said to he significant.
vulue or quantity a distance
been recorded
measured to the nearest I m may
as 157 m; this
number
has three
1 mm. Similarly, a gauge or caliper graduated in divisions of 0.02 mm is comparable to one graduated in divi-
significant digits. If the measurement had been made to the nearest 0.1 m, the distance may have been 157.4
sions of 0.001
m-four
in. Analogous
situations
exist
for mass,
force, and other measurements. A technique to determine the proper number of significant digits in rounding converted values is described here for general use.
significant
digits.
In each case, the value of the
right-hand digit was determined by measuring the value of an additional digit and then rounding to the desired degree of accuracy. In other words, 157.4 was rounded to 1.57; in the second case, the measurement
General Conversion. establishing quantity
This approach depends on first the intended precision or accuracy of the
as a necessary
retain.
The
guide to the number
precision
should
digits in the original. but reliable indicator. A figure curate
decimalization
relate
to the
ed
It is theretbre
to
Importance of Zeros. Zeros may be used either to in-
of
dicate a specific
I xh that
precision
cstitnale
of
before
precisiorl
should
fhur7
one-tend7
the precision
Digits) smaller
should
of significant
be
digits
converting. he
771;s
dicate the population
as does any other digit, of
a number.
rounded
to
The
or to in-
1970
U.S.
thousands
was
203 185 000. The six left-hand digits of this number are significant; each measures a value. The three right-hand digits are zeros that merely indicate the magnitude of the number
rounded
to the nearest
further, each of measurements is of specified
stnullet
value,
magnitude figure
thousand.
To illustrate
the following estimates and different magnitude, but each is
to have only
one significant
digit:
txrr 1r.s14a11\ .s17014Id hc
tcrlrrtrt7c~e
of the dimension
dimension
number
the
the intend-
.~/7011/rl twlw
flrc’ut-flc~\’ c~f’tr7f~L4.slr~emrft
.vt~ul/cr
verted
a quantity
of ititertdnl
thctt1 l/l?
necessary to determine
may have
to 157.4.
number
have been expressed as I. 19. On the other hand. the value 2 may mean “about 2” or it may mean a very accurate value of 2, which should then have been written as 2.0000.
rounded
of digits
in many cases that is not a of 1. I875 may be a very ac-
of a noncritical
been 157.36,
~f’otw exists.
is estimated. rounded
to
(see section
After
1 000 100
the con-
a minimum
10
on Significant
0.01
such that a unit of the last place is equal to or than the converted precision.
0.001 0.000 It
is also
important
1.
to note
that,
for
the
first
three
‘/z in.
numbers, the identification of significant digits is possible only through knowledge of the circumstances. For
is 12.7 mm. The convened 6-in. dimension of 152.4 mm should be rounded to the nearest IO mm, or I50 mm.
example, the number 1000 may have been rounded from about 965, or it may have been rounded from 999.7, in
1. A stirring estimated
rod 6 in. long:
to be about
In this case, precision
% in. (+ i/4 in.).
2. SO,OO@psi tensile strength: estimated
Converted.
is
In this case, precision
to be about t_200 psi (i
I .4
is
MPa) based on an
accuracy of _+0.25% for the tension tester and other factors. Therefore, the converted dimension, 344.7379 MPa. should be rounded to the nearest whole unit, 345 MPa. 3. Test pressure 2OOk 15 psi: Since one-tenth of the tolerance is + 1.5 psi (10.34 kPa). the converted dimenhion should
be rounded
1378.9514-t
103.421
to the nearest
35 kPa becomes
10 kPa. 138Oi
Thus.
100 kPa.
which
case all three zeros are significant.
Data of Varying Precision. Occasionally, for an investigation
must
be drawn
the minimum tain from
values
should
number of significant
the required this practice
may be feasible. must be used
be rounded
to
digits that will main-
accuracy. In certain cases, deviation to use convenient or whole numbers
when such data are to be added, or divided.
of three numbers
drawn
rounded
subtracted,
stated as a limit,
such as “not
multiplied,
Consider
three sources,
the addition the first of
the second in thousands,
163 000 000 217 885 000 96 432 768 477 317 768
to whole
number. A quantity
from
which reported data in millions, and the third in units:
In that case, the word “approximate” following the conversion-e.g., I%
48 mm (approximate)
of
The rule for addition and subtraction is that the answer shall contain no significant digits farther to the right than
in. =47.625 mm exact, 47.6 mm normal rounding, 47.5 mm (approximate) rounded to preferred or convenient half-millimeter.
a variety
sources where they have been recorded with varying degrees of ref-mement. Specific rules must be observed
occurs in the least precise number.
Special Cases. Converted
data required
from
more than”
This total indicates numbers should jirst
a precision
that is not valid.
be rounded to one significant
The digit
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
farther
to the right than that of the least precise number,
and the sum taken as follows. 163 Ooo 000 217 900 000 96 400 000 477 300 ooo Then, the total is rounded by the rule.
to 477 000 000 as called for
Note that if the second of the figures
to be
added had been 217 985 000, the rounding before addition would have produced 218 000 000, in which case the zero following 218 would have been a significant digit. The rule for multiplication and division is that the product or quotient shall contain no more significant digits
than arc contained
in the number
with
the fewest
signijcant digits used in the multiplication or division. The difference between this rule and the rule for addition and subtraction traction,
should
the rule merely
be noted; requires
for addition rounding
and sub-
digits
to the
right of the last significant digit in the least precise number. The following illustration highlights this
58-7
Examples: 4.463 25 if rounded
to three places would
be 4.463.
8.376
52 if rounded
to three places would
be 8.377.
4.365
00 if rounded
to
4.355
00 if rounded
to two places would
two places would be 4.36. be 4.36.
Conversion of Linear Dimensions of Interchangeable Parts Detailed
discussions
of
this
subject
are provided
ASTM,” API,” and ASME’ publications recommended to the interested reader.
Other Units Temperature. tolerances Celsius
General
guidance
from degrees Fahrenheit
is given
in Table
for
by arc
converting
to kelvins
1.5. Normally,
and
or degrees
temperatures
expressed in a whole number of degrees Fahrenheit should be converted to the nearest 0.5 K (or 0.5”C). As with other quantities, the number of significant digits to retain will depend on implied accuracy of the original dimension:
e.g.,*
difference. 100*5”F Multiplication:
113.2~1.43=161.876
Division:
113.2+1.43=79.16
Addition:
to 79.2 113.2+1.43=114.63
rounded
Subtraction:
to 114.6 113.2-1.43=111.77
rounded
to 162.
1.000~50”F estimated
rounded
above
product
and
quotient
are limited
to three
digits because 1.43 contains only three digits. In contrast. the rounded answers in the
addition and subtraction cant digits. Numbers
examples
contain
used in the illustration
four
signifi-
are all estimates
or
measurements. Numben that ure cxwt counts (and conthat arc exuct) at-c treated as though thq aversion ,firctors cmsist of’otlinjrzitr rumher oj’.sip$cant digit.,. Stated more simply.
when a
unmt is used in computation
with a
measurement. the number of significant digits in the answer is the same as the number of significant digit?, in rhe measurement. If a count of 40 is multiplied by a measurement of 10.2. the product is 408. However, if 40 wcrc an estimate accurate only to the nearest IO and, hence. contained be 300.
one significant
digit.
the product
would
Rounding Values lo
When the First Digit Discarded is less than 5 more than 5 5 followed only by zeros*
estimated
(tolerance): implied accuracy. total 20°F (nearest 10°C) rounds
bc
by the same prmciple
Values
to 54Ok3O”C.
with
converted
an uncertainty
used for other
without
rounding
by
factors
see Table
I .7.
the
approximate
1 psi=7
kPa.
For conversion
Special Length Unit-the E, provides the problems
conversion ofconverting
Vara. Table 1.8* Appendix
factors
and explanatory
notes on
the several kinds of vara units
to mctcrs.
Special Terms and Quantities Involving Mass and Amount of Substance The Intl. Union of Pure and Applied Chemistry. Union of Pure and Applied Physics. and
A and pnor paragraph
on “General
the lntl. the Intl.
Conversion.”
digits than the should be as
The Last Digit Retained
is
unchanged increased by 1 unchanged increased
if even, by I if odd
‘Unless a number of rounded values are lo appear I” a gfven problem, mosl roundlngs conform lo the ,,is, two procedures - 1.e rounding upward when the llrst dlgll dw carded IS 5 or hlg”er
quan-
of more than 2% may
factor:
‘See Appendlx
When a figure is to be rounded to fewer total number available, the procedure follows.
accuracy.
Pressure or Stress. Pressure or stress values may be converted tities.
The
implied
I “C) 37.7778&2.7778”C
537.7778k27.7778”C
to 111.8.
significant significant
(tolerance);
total 2°F (nearest rounds to 38+3”C.
rounded
TABLE 1.5 -CONVERSION OF TEMPERATURE TOLERANCE REQUIREMENTS Tolerance (“F) 21 z-2 -c5 210 A15 220 k-25
Tolerance (K or “C) X0.5 *I +3 + 5.5 -8.5 k-11 t 14
PETROLEUM
58-8
Organization
for
Standardization
provide
4
clarifying
usages for some of the terms involving the base quantities “mass” and “amount of substance.” Two of these require modifying the terminology appearing previously in SPE’s Table
Symbols
10.
Standards.
1.6 shows the old and the revised
usages.
Mental Guides for Using Metric Units Table
1.9. Appendix
F, is offered
as a “memory
jog-
ballpark” ger’ ’ or guide to help locate the “metric relative to customary units. Table 1.9 is not a conversion table. For accurate conversions, refer to Table 1.7, or to Tables
2.2
and 2.3
for
round off the converted described earlier.
petroleum-industry values
units,
to practical
II. 12.
and
precision
as 13.
References*
14.
I. “The lntematmnal System of Units (Sl).” NBS Special Publication 330. U.S. Dept. of Commerce, Natl. Bureau of Standards, Superintendent of Documents. U.S. Government Printing Office, Washmgton. D.C. (1981). (Order by SD Catalog No. c13.10:330/3.) 7. “S1 Units and Recommendations for the Use of Thctr Multtplca and of Certain Other Units,” wcond edition, 1981.02-15. Intl. Standard IS0 1000. lntl. Oganlzation for Standardlzatton. American Natl. Standards Inst. (ANSI). New York (1981). 3 “Standard for Metrtc Practtce,” E 380-82. Amencan Sot. ftir Testing and Materials. Philadelphia. (Slmdar matcrlal published in 1EEE Std. 268-1982.) 4
IS.
16.
APPENDIX Terminology
A3
To ensure consistently
reliable
practices,
understanding
a
clear
Accuracy
Metric
to some
standard
recognized
on any 01 these references.
Cantact the Book Order Dept
at SPE
A characteristic
atomic weight (SPE Symbols Standard) atomic weight (elsewhere) equivalent mass of molecule molar molar@ molecular weight (SPE Symbols Standard) molecular weight (elsewhere) normal - obsolete mDimensonless
precision). or calculated
error
in Appendix
M M l
cor-
Term mass of atom relative atomic mass mole molecular mass molar (means, “divided by amount of substance”) concentration molar mass relative molecular mass
system
of
is the unit of the
Standardized Usage Dimensions (IS0 Symbols, See Table 1 .l)
.
This
B, such that the product
SPECIAL TERMS AND QUANTITIES INVOLVING MASS AND AMOUNT OF SUBSTANCE
M
value.
The value
of an operation,
of a coherent
of any two unit quantities
Old Usage
Term
certain
A value that is nearly but not exactly
units, as described or quotient
TABLE 1.6 -
related
as follows.
or specified
the systematic negligible.
the
rect or accurate.
Coherence. ‘For information headquarters
from
of a measured
Approximate. Natl.
are defined
(as distinguished
and rounding
of
Accordingly,
degree of conformity concept involves which is seldom
.&w~c Edirorid G&P. thlrd edition. American Councd (ANMC). Washington. D.C. (July 1981).
conversion
terms is prerequisite.
terms used in this standard
6. “A Bibliography of Metric Standard,.” ANSI. New York (June 1975). (Alw &ee ANSI‘\ annual catalog of national and intrmaImnal standard\.)
HANDBOOK
“General Principles Concerning Quantities. Unirs and Symbols,” Gm~rcrl fnrroducrion rcj /SO 31. second edition. Intl. Standard IS0 3110. Intl. Organization for Standardization. ANSI. New York City (1981). “American National Standard Practice for Inch-Millimeter Conversion for Industrial Use,” ANSI 848.1-1933 (Rl947). IS0 R370- 1964, Intl. Organization for Standardization. ANSI, New York. (A later edition has been issued: “Toleranced Dimensions--Conversion From Inches to Millimeters and Vice Versa.” IS0 370-1975.) “Factors for High-Precision Conversion.” NBS LC1071 (July 1976). “Information Processing-Representation5 of SI and Other Units for Uae in Systems With Limited Character Sets.” lntl. Standard IS0 2955-1974. Intl. Organization for Stdndardization. ANSI. New York Ctty. (Ref. 5 reproduces the 1973 editton of this standard in its entirety.) “Supplementary Metnc Practxe Guide for the Canadian Petroleum Industry.” fourth edition. P.F. Moore (ed.). Canadian Petroleum Assn. (Oct. 1979). “Letter Symbols for Units of Measurement,” ANSI/IEEE Std. 260-1978. Available from American Natl. Standards Inst.. New York City. Mechtly. E.A.: “The International System trt Units-Physical Constants and Conversion Factors,” NASA SP-7012. Scientific and Technical Information Office, NASA, Washmgton. D C. 1973 edition available from U.S. Government Printing Office, Washington. D.C. McElwee, P.G.: The Terns Vlrrcj. Available from Commissioner. General Land Office, State of Texas. Auatm (April 30. 1940).
nontechnical
5
ENGINEERING
SI Unit Symbol kg . mol kg l/m01 mo1/m3 kg/mol l
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
resulting quantity. units, and derived
Deviation. design limits
The SI base units, units form a coherent
Variation
from
supplementary set.
a specified
requirement, usually (see also Tolerance).
dimension
defining
upper
numerals
(0 to 9).
58-9
assigned to each; in some cases, special names and unit symbols are given-e.g., the newton (N). or
and lower
One Unit per Quantity. The great advantage
of SI is
that there is one, and only one, unit for each physical quantity-the meter for length (L), kilogram (instead of gram) for mass (m). second for time (r). etc. From these
Digit. One of the 10 Arabic Dimension(s).
Two
meanings:
(1)
A
elemental units, units for all other mechanical are derived. These derived units are defined
group
of
fun-
equations
in or
(velocity),
damental (physical) quantities, arbitrarily selected, terms of which all other quantities can be measured identified. 9 Dimensions or the basic components
identify the physical nature of, making up. a physical quantity.
They are the bases for the formation of useful dimensionless groups and dimensionless numbers and for the powerful
tool of dimensional
for the arbitrarily
analysis.
The dimensions
selected base units of the SI are length,
mass, time, electric current. thermodynamic temperature, amount of substance. and luminous intensity. SI has two supplementary less-plane
quantities
considered
angle and solid angle.
dimension-
(2) A geometric
ment in a design, such as length magnitude of such a quantity.
and angle.
Figure (numerical).
value
one or more digits
An arithmetic
expressed
by
Precision
(as distinguished
degree
of
mutual
measurements
Quantity. titative
a value
from
agreement
(repeatability
A concept
descriptions
existing
used
quantities,
such
(acceleration),
as
F=ma
tB=dLldt (force),
W=FL (work or energy), and P= Wit (power). Some of these units have only generic names. such as meter per second for velocity; others have special names and symbols, such as newton
(N) for force, joule
(J) for work
nuclear.
A force of 1 N applied
for a distance of 1 m can
produce 1 J of heat, which is identical with what 1 W of electric power can produce in 1 second.
Unique Unit Symbols. Corresponding to the SI advantages of a unique unit for each physical quantity are the advantages resulting from the use of a unique and welldefined
set of symbols.
Such symbols
that can arise from
current
eliminate
practices
the con-
in different
disciplines, such as the use of “b” for both the hur (a unit of pressure) and barn (a unit of area).
in name only.
accuracy).
The individual
between
Decimal Relation. Another
advantage
tion of the decimal
between
multiples
relation
of the base units
of SI is its retenmultiples
and sub-
for each physical
quantity.
and reproducibility).
Prefixes
for
multi le units from “exa” (10”) down to “atto” (I 0 Ps) for convenience in writing and speaking.
of a physical
or
energy. and watt (W) for power. The SI units.fi,r jbrce, energy, and power are the same regardless of \r>hether the process is mechanical, electrid, chemiccd, or
fusion
Nominal Value. A value assigned for the purpose of designation;
the
u=dv/dt
ele-
or the
or a fraction.
convenient
among
quantities by simple
qualitative
and
phenomenon.
quan-
are established
for designating
multiple
and sub-
9
Coherence.
Another major advantage of SI is its This system of units has been chosen in such
Significant Digit. Any digit that is necessary to define a
coherence.
value or quantity
a way that the equations between numerical values, including the numerical factors, have the same form as the corresponding equations between the quantities: this
Tolerance. bilateral) quantity; dimension
(see text discussion).
The
total
range
of
variation
(usually
permitted for a size, position, or other required the upper and lower limits between which a must be held.
constitutes
a “coherent”
units of a coherent tors only the number or quotient
U.S. Customary Units. Units based on the foot and the pound, commonly used in the U.S. and defined by the Natl. Bureau of Standards. ” Some of these units have the same name as similar units in the U.K. (British, English,
or U.K.
units)
but are not necessarily
equal to
them.
APPENDIX SI Units
Equations
1. In a coherent
system,
of any two unit quantities
between
as numerical
fac-
the product
is the unit of the
resulting quantity. For example, in any coherent system, unit area results when unit length is multiplied by unit length (1 m x 1 m= 1 m*), unit force when unit mass* is multiplied by unit acceleration (1 kgx 1 m/s* = 1 N), unit work when unit force is multiplied by unit length (1 N x 1 m= 1 J), and unit power when unit work is divided by unit time (I J+ 1 second= 1 W). Thus, in a coherent system in which the meter is the unit of length, the
B3
square meter is the unit of area, but the are** are
Advantages of SI Units SI is a rationalized selection of units from the metric system that individually are not new. They include a unit of force (the newton), which was introduced in place of the kilogram-force to indicate by its name that it is a unit of force and not of mass. SI is a coherent system with seven base units for which
system.
unit system contain
names, symbols,
definitions have been established. Many arc defined in terms of the base units,
and precise
derived units with symbols
not
coherent.
Much
worse
disparities
and hectare occur
in
systems of “customary units” (both nonmetric and older metric) that require many numerical adjustment factors in equations.
Base Units. Whatever coherent
the system of units, whether it be or noncoherent, particular samples of some
PETROLEUM ENGINEERING
58-10
physical
quantities
must be selected arbitrarily
as units of
those quantities. The remaining units are defined by appropriate cxperimcnts related to the theoretical intcrrclations of all the quantities. units pertaining tior7 rc~~crrrld
For convenience
to c~r-fuin hrrsc>ylrrrfztitics us
(I~C crr//c~! basr
of analysis.
(Table
unirs
units) can be cxprcsscd
tl7c.w
ur7it.s
I I ). and all others (derived
algebraically
and placed one mctcr apart in vacuum. would product hctwecn these conductors a force equal to 2 x IO -’ newton
in temls of the base
units. In SI. the unit of mass. the kilogram,
is defined
as
per meter of length.”
(Adopted
by Ninth
CGPM
lY48.)
~Irf’ by (~~171*0-
dir77~~r7siot7all~~ ir7tlqxwder7t;
HANDBOOK
“Kchi77
temperature. modynamic
(K)-The kelvin. unit of thermodynamic is the fraction 11273. IS of the thertemperature of the triple point of water.” ’
(Adopted by 13th CGPM 1967.) “MCI/C (mol)-The mole is the amount
of substance of
the mass of a prototype kilogram preserved by the Intl. Bureau of Weights and Measures (BIPM) in Paris. All
a system which contains as many clcmcntary entities as thcrc are atoms in 0.012 kilograms of carbon-12.”
other
(Adopted
base units
are defined
phenomena-e.g., specified
the wave
atomic
in terms lengths
of reproducible
and frequencies
of
transitions.
ions, electrons. other such particles. ”
Metric Units
Non-S1
Various other units are associated with SI but are not a part thereof. They are related to units of the system by powers
of
by 14th CGPM
10 and are used in specialized
branches
of
physics. An example is the bar, a unit of pressure. approximately equivalent to 1 atm and exactly equal to 100
1971.)
“Note-When the mole is used. the elementary entities must be specified and may be atoms. molecules.
in
particles.
or specified
“Crrn&/u (cd)-The candela a given direction of
monochromatic
radiation
intensity
540 (E + 12) hertz In that direction
watt per steradian.” “Rudiurz (rad)-The radian is the plane angle between
two radii of a circle
tion of 0.01 m/s?. It is used in geodetic work. however. are not coherent units-i.e., equations
an arc equal in length to the radius.” “Sr~~&iu~? (sr)-The stcradian i\
ing
both
thcsc
units
and
SI units
cannot
be written
without a factor of proportionality even though that fattor may be a simple power of 10. Originally (1795). the liter was intended to be identical to the cubic on Weights
decimeter.
The Third
and Measures
(CGPM)
General
ly
pressure.
established
Careful
the
liter
determinations
so defined
which.
having
its vertex
an area of the surface square with sphere.”
the
subsequent-
as equivalent
to
special name for the cubic decimeter. Thus. its use is pemlitted in Sl but is discouraged because it creates two same quantity might conflict
Physical
Quantity
Absorbed
dose
Activity
follow’
(parenthetical
temperature
French definitions units
Dose equivalent
of infinite
length.
ampere is that constant current in tw’o straight parallel conductors of ncgliglble
circular
cross-section.
to
matter
by
is I J/kg.
transition
per second,
temperature
(symbol
by Tot =T,
-To,
where TK is the thermodynamic temperature and To =273. IS K by definition. The sievcrt is the dose when the absorbed ionizing radiation by the dimensionless
factors Q (quality factor) and N (product of any other multiplying factors) stipulated by the
of 9 192 63 I to the transi-
1967.)
radiation
defined
multiplied
1889 and 1901.)
tion between the two hyperfine levels of the ground state of the cesium- 133 atom.*” (Adopted by 13th CGPM “Atnper~~ (A)-The which. if maintained
imparted
equivalent dose of
(and is the coherent SI unit); it is equal to the mass of the international prototype of the kilogram.” (Adopted by CGPM
of the
The degree Ce1siu.s (“C) is equal to the kelvin and is used in place of the kelvin for expressing Tot)
5d5 of the krypton-86 atom.” (Adopted by I lth CGPM 1960.) “Kilogmn7 (kg)-The kilogram is the unit of mass
“Sc~nrzci (s)-The second is the duration 770 periods of the radiation corresponding
to that of a
to the radius
The gray (Gy) is the absorbed dose when the energy per unit
Celsius
of SI
items added).
“Mrfer cm)-The meter is the length equal to I 650 763.73 wavelengths in vacuum of the radiation corresponding to the transition between the levels 2p I~) and
First and Third
angle
Unit and Definition
nuclear
supplementary
solid
The hrcyuerrl (Bq) is the activity of a radionuclide decaying at the rate of one spontaneous
and its use in precision with measurements record-
of the original
base and two
equal
ionizing
SI Base Unit Definitions translations
of the sphere equal
mass
Celsius Authorized
the
at the center of a sphere. cuts oft
Definitions of SI Derived Units Having Special Names3
ed under the old definition.
of the seven
cut off on the circumfcrencc
sides of length
1.000 028 dm’. In 1964. the CGPM withdrew this definition of the liter and declared that “liter” was a
units for the measurements
which
Conference
in 1901 defined
liter as the volume occupied by the mass of 1 kilogram of pure water at its maximum density under normal atmospheric
ol
l/683
kPa. The bar is used extensively by meteorologists. Another such unit is the gal. equal exactly to an acceleraThese. involv-
of
is the luminous intensity a source that emits
of frequency
(Hz) and that has a radiant
groups
Intl. Commission on Radiological Protection is I J/kg. Electric
capacitance
The&r& (F) is the capacitance of a capacitor between the plates of which there appears a difference of potential of I V when it is charged by a quantity electricity equal to I C.
of
WE
SI METRIC
SYSTEM
The
Electric conductance
Electric
Electric
Electric
& SPE METRIC
siemens
conductance
inductance
potential
difference, tromotive
OF UNITS
elecforce
resistance
(S) is the electric
the force exerted
of
of current
which
a current
duced
by
a conductor of
in
1 A is pro-
an electric
Power
electromotive
represents a rate transfer of I J/s.
Electric
ly at a rate of 1 A/s. The volr (V) is the difference
quantity of electricity
electric
potential
1 V
between
is
of
points of a conductor carrying a constant current of 1 A when the power dissipated between these points is equal to 1 W. The ohm (Q) is the electric between
two points of
when a constant
the
source
of
charge,
dif-
any
elec-
No other SI derived names at this time.
APPENDIX
is that
force
always
capitalized.
which
phenomenon
the period
of
is 1 second.
The Iu.r (Ix) is the illuminance produced by a luminous flux of I Im uniformly distributed over a surface of I m2 The lumen
(Im)
is the luminous
flux emitted in a solid angle of 1 sr by a point source having a uniform intensity of 1 cd. Magnetic
flux
The ember,
is the magnetic
flux that, liriking
a circuit
of one
turn, produces in it an electromotive force of 1 V as it is reduced to zero at a uniform rate in I s. Magnetic
flux
density magnetic
induction
The teslu (T) is the magnetic flux density of 1 Wb/m2. In an alternative approach to defining the magnetic field quantities the
tesla may also be defined as the magnetic flux density that produces on a l-m length of wire carrying
a
current
of
1 A,
oriented normal to the flux density, a force of 1 N, magnetic flux density being defined as an axial vector quantity such that
names, including
The
prefixes,
are not
“degree
short forms
centrigrade”
for metric
is now
units are called
unit symbols. They are lower case except that the first letter is upper case when the unit is named for a person. to this rule in the U.S.
Examples:
an acceleration of I m/s’. The hertz (Hz) is the frequency a periodic
special
capitalized except at the beginning of a sentence or in titles. Note that for “degree Celsius” the word “degree” is lower case; the modifier “Celsius” is
that, when applied to a body having a mass of 1 kg. gives it
of
units have been assigned
C3’**
Capitals. I/nits-Unit
(An exception liter.)
(N)
to 1
Rules for Writing Metric Quantities
distance
nr~r~~
is equal
Style Guide for Metric Usage
obsolete. Symbols-The
The
(C),
A.s.
tromotive force. The joule (J) is the work done when the point of application of a force of 1 N is displaced a of 1 m in the direction
(Pa) is the pressure
the coulomb
two
of the force.
flux
energy
The pascul
being
Luminous
of
or stress of I Nim2. Electric charge is the time integral of electric current; its unit,
of
produces in this conductor a current of I A, this conductor not
Illuminance
wutt (W) is the power that
The
Pressure or stress
force
ference of potential of I V, applied between these two points,
Frequency
and the
produced when the electric current in the circuit varies uniform-
resistance
Force
on an element
is equal to the vector
product of this element magnetic flux density.
potential
difference of 1 V. The hpn~l (H) is the inductance of a closed circuit in which an
a conductor
Energy
58-l 1
STANDARD
is the symbol
Unit Name
Unit Symbol
meter**
m
mm newton Pascal
6
L for
Pa
Printed unit symbols should ters, because italic (sloping
have Roman (upright) letor slanted) letters are re-
served
such as m for mass and L
for quantity
for length. Prejx Symbols-All pronunciation
symbols, prefix
names, their symbols,
are listed in Table
I .4. Notice
and
that the top
five are upper case and all the rest lower case. The importance of following the precise use of uppercase and lower-case amples
of prefixes
letters is shown by the following
ex-
and units.
G for giga; g for gram. K for kelvin; k for kilo. M for mega; m for milli. N for newton; n for nano. T for tera: t for tonne (metric information Prefixes
ton).
Processing-Limited
and unit symbols
Character
retain their
prescribed
Setsforms
regardless of the surrounding typography, except systems with limited character sets. IS0 has provided standard” for such systems; this standard
for a is
recommended.
Plurals and Fractions.
Names
plurals in the usual manner, siemens.
of SI units
except
for lux,
‘The spellings “metre” and “l~tre” are preferred by IS0 but “meter” ottlclal u s QcNernmenl spelhngs.
form hertz,
their and
and “liter” are
PETROLEUM
58-12
Values less than one take the singular form of the unit name; for example, 0.5 kilogram or % kilogram. While decimal
notation
(0.5, 0.35,
the most simple
fractions
where the denominator Symbols of units plural-e.g.,
6.87) is generally are acceptable,
preferred,
Compound Units. For a unit name (not a symbol)
derived as a quotient (e.g., for kilometers per hour), it is preferable not to use a slash (/) as a substitute for “per”
except
singular
understood. Avoid other mixtures of words and symbols. Examples: Use meter per second, not m/s. Use only one
and
where space is limited
“per”
I m and 100 m.
in any combination
ond squared,
Periods. A period is nof used after a symbol,
except at current of 1.5 mA is
Examples:
“A
found..
measured
350x
” “The
field
125 m.”
ty;
W/m/K.
overlooked). seven five”
decimal
Example: The oral is written 0.75 or 0,75.
sign
expression
will
be
counting
from
the
examples For a unit
“point
decimal
marker.
A comma
should not be used between the groups of three9 ; instead, a space is left to avoid confusion, since the comma is the IS0 standard for the decimal marker. In a four-digit number, the space is not required unless the four-digit number is in a column with numbers of five digits or more:
For
4,720,525
write
4 720 525
For For For
0.52875 6,875 0.6875
write write write
0.528 75 6875 or 6 875 0.6875 or 0.687
for
milligram. When a symbol
letters making kA,
m/s*,
name
time,
not
derived
plane
not kglft3
decimal)
space must be left between
not
a space or a
angle,
up the symbol
to which
the number
or
units,
except
rotation-e.g.,
use
or kg/gal.
not 10 mm/m
the slope is l/l00
or
or 10 m/km.
5
kiloampere;
a number
W/(m.K),
as a product,
Prefix Usage. General--S1
and
or mg,
orders
of
it refers, a
and the symbol,
prefixes
magnitude,
thus
should be used to eliminating
non-
significant digits and leading zeros in decimal fractions and providing a convenient alternative to the powersof-10 notation preferred in computation. For example, 12 300 m (in computations)
follows
m/s/s;
or as a percentage-e.g.,
0.01 or l%,
Spacing. In symbols or names for units having prefixes, are
are
A quantity that constitutes a ratio of two like quantities should be expressed as a fraction (either common or
SI
Examples
whereas
km/h also can
calculations-e.g., use 6.2~5, not 6.2.5. Do not mix nonmetric units with metric
indicate
name.
language,
The symbol
For a unit symbol derived as a product, use a product dot-e.g., N.m. For computer printouts, automatic typewriter work, etc., a dot on the line may be used. Do not use the product dot as a multiplier symbol for
kg/m3,
no space is left between
in the English
meter or newton-meter, not newton.meter. In the case of the watt hour, the space may be omitted-watthour.
those
the
meter per sec-
hyphen is recommended but never a “product dot” (a period raised to a centered position)-e.g., write newton
Grouping of Numbers. Separate digits into groups of three,
not be
be written with a negative exponent-e.g., km. h -’ . Never use more than one slash (/) in any combination of symbols unless parentheses are used to avoid ambigui-
vent
a faint
only
is used in all languages.
decimal marker9 ; in English-language documents a dot on the line is acceptable. In numbers less than one, a zero should be written before the decimal sign (to prethat
of units-e.g.,
might
not meter per second per second.
are understood
The Decimal Marker. IS0 specifies the comma as the
and a symbol
For a unit symbol derived as a quotient do not, for example, write k.p.h. or kph for km/h because the first two km/h
the possibility
HANDBOOK
such as those
is 2, 3, 4, or 5. are the same in
the end of a sentence.
ENGINEERING
computation
situations);
becomes
0.0123
12.3 km (in non-
hA (12.3 x 10m9 A for
except when the symbol (such as “) appears in the superscript position. Examples: 455 kHz, 22 mg, 20
computations) becomes 12.3 nA (in noncomputation situations). Selection-When expressing a quantity by a numerical
mm,
value
lo6
When
N, 30 K, 20°C. a quantity
is used as an adjective,
a hyphen
should be used between the number and the symbol (except “C). Examples: It is a 35-mm film; the film width is 35 mm. I bought a 6-kg turkey; the turkey weighs 6 kg. Leave a space on each side of signs for multiplication, division,
addition,
pound symbol. kg/m3;
and subtraction,
Examples:
volume)-e.g..
M~ZP.P, use the modifier .rquared or unit name (except for area and
meter
per second
volume,
place a modifier
derived meter.
units:-e.g..
For unit symbols. cm3.
a com-
N.m.
Powers. For unit cubed after the
lowed
except within
4 cm x 3 m (not 4 cm X 3 m);
by the power
squared.
For area or
before the unit name. including
cubic write
meter
and watt
the symbol
superscript-e.g.,
per square
for the unit
fol-
14 m’ and 26
and a unit,
prefixes
should
be chosen
so that the
numerical value lies between 0.1 and 1000. Generally, prefixes representing steps of 1000 are recommended (avoiding hecto, deka, deci, and centi). However, some situations may justify deviation from the above: 1. In expressing units raised to powers (such as area, volume and moment) the prefixes hecto, deka, deci, and centi may be required-e.g., volume and cm4 for moment. 2. In tables discussion of generally
cubic
centimeter
for
of values of the same quantity, or in a such values within a given context, it
is preferable
to use the same unit
multiple
throughout. 3. For certain quantities in particular applications, one certain multiple is used customarily; an example is the millimeter in mechanical engineering drawings, even when the values mm. Powers
lie far outside
of Units-An
the range of 0.1 to 1000
exponent
attached
to a symbol
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
containing a prefix indicates that the multiple or submulripie of the unit (the unit with its prefix) is raised to the power expressed by the exponent. For example, =(10p2m)3 =(10P9s) -1
= 10 -6,3 =109s-’
1 mm*/s
=(10-“m)2/s
= 10-5m2/s
Pre$xes-Double
or multiple
Equations. When customary
units appear in equations, the SI equivalents should be omitted. Instead of inserting the latter in parentheses, as in the case of text or small tables,
1 cm3 1 ns-’
Double
58-13
the equations
should
be restated
using
SI unit
symbols, or a sentence, paragraph, or note should be added stating the factor to be used to convert the
prefixes
calculated units.
result
in customary
units to the preferred
SI
should
not be used. For example,
Pronunciation
of Metric Terms
use GW (gigawatt),
not LMW;
The
use pm (picometer),
not ppm;
known and uniformly described in U.S. dictionaries, but four have been pronounced in various ways. The follow-
use Gg (gigagram), not Mkg; use 13.58 m, not 13 m 580 mm. Prefix
Mixtures-Do
not
use a mixture
candela
of prefixes
-
joule
-
Pascal
-
tain a numerical value of convenient size. Examples of some of these rare exceptions are shown in the tables contained in these standards. Prefixes may be applied to the numerator unit;
thus, megagram
per cubic
of a com-
meter (Mg/m3),
but not kilogram per cubic decimeter (kg/dm3) nor gram per cubic centimeter (g/cm3). Values required outside the range of the prefixes
should be expressed
of 10 applied to the base unit. Unit of Mass-Among the
base
by powers
units
of
SI,
the
The preferred
pronunciation
siemens
syllable. Pronounce
-
For pronunciation
of unit prefixes,
superscripts should be typed ventional keyboard. With
on a machine an
However,
names of decimal
multiples
Prefises
Alone-Do
not
use
a
prefix
unit-e.g., use kilogram, not kilo. Calculations-Errors in calculations if, instead of using derived
prefixes,
without
a
minus sign can be raised to the by rolling the platen half a space
before
numeral,
typing
terference
the
with
using
notation-e.g.,
1 MJ=
values in
lo6 J.
in a prefix
is omitted:
meaning
letters available
megohm,
to
avoid
in-
work,
it is useful
on the typewriter.
for units are to be typed properly,
to
If all SI
a key with the
Greek lower-case p (pronounced “mew.” not is necessary, since this is the symbol for micro. one millionth.
The symbol
can be approximated
the unit name in full. For units of electricity, (Q) for ohm also will
Spelling of Vowel Pairs. There are three cases where the final vowel
symbols
care
the text in the line above.
on a conventional machine by using a lower-case u and adding the tail by hand (p). A third choice is to spell out
can be minimized numerical
a con-
keyboard.
numerals and the superscript position
upright *‘moo”)
the base and the coherent
SI units are used, expressing
powers-of-10
and
by attaching
1.4.
with
ordinary
have Greek
submultiples of the unit of mass are formed prefixes to the word “gram.”
see Table
Typewriting Recommendations Superscripts. The question arises of how numerical
Special Characters. For technical
coherence.)
rhymes
it like sea,nerl ‘.r.
for mass (See Appendices
of
is well
with rascal. An acceptable second choice puts the accent on the second
kilogram is the only one whose name, for historical reasons, contains a prefix; it is also the coherent SI unit A and B for discussions
names
Accent on the second syllable and pronounce it like de/l. Pronounce it to rhyme with pool.
Compound Units--It is preferable that prefixes not be used in the denominators of complex units, except for kilogram (kg) which is a base unit. However, there are cases where the use of such prefixes is necessary to ob-
of the unit
are recommended:
is acceptable.
pound
of most
ing pronunciations
unless the difference in size is extreme. For example, use 40 mm wide and 1500 mm long, not 40 mm wide and 1.5 m long; however, 1500 m of 2-mm-diameter wire
pronunciation
kilohm,
and hectare. In all other cases, both vowels are retained and both are pronounced. No space or hyphen should be
the Greek
be useful;
upper-case
omega
when it is not available,
the word “ohm” can be spelled out. It is fortunate that, except for the more extensive use of the Greek p for micro and Q for ohm, the change to SI units causes preparation.
no
additional
difficulty
in
manuscript
used.
The Letter for Liter. On most U.S. typewriters, Complicated Expressions. To avoid ambiguity plicated
expressions,
symbols
are preferred
in com-
over words.
little
difference
the numerical
between “one”
the lower-case
(“1”).
“cl”
The European
there is (“I”) and
symbol
for
Attachment.
liter is a simple upright bar; the Canadians I3 used a script P but now have adopted the upright capital L; AN-
giving
SI now recommends
Attachment of letters to a unit symbol for information about the nature of the quantity is in-
correct: MWe for “megawatts electrical (power), ” kPag for “kilopascais gauge (pressure),” Paa for “pascals absolute (pressure),” ceptable.
If the context
supplementary making
and Vat
is in doubt
descriptive
the meanings
for “volts
clear.
phrases
ac” are not ac-
on any units used, should
be added
to
the upright
Typewriter Modification. thllowing
symbols
superscripts micro; symbols
could
capital
Where
L.
frequently
be included
’ and ’ for squared and cubed;
’ for degree; derived
. for a product
as a product;
used, the
on typewriters: Greek p for
dot (not a period)
and Greek
Q for ohm.
for
58-l 4
PETROLEUM
A special type-ball Q, and vailable
that contains
other characters used for some typewriters.
replaceable
character
all the superscripts,
FL,
in technical reports is Some machines have
Where
of the symbols m, n. and that these three symbols be written
to resemble
printing.
For example.
The symbol
p should have a long distinct form
are quicker
write
(not sloping
Shorthand. Stenographers generally
places are shown,
more
is not warranted.
The following
Longhand. To assure legibility
have the upright
than six decimal
HANDBOOK
is a further
example
of the use of Table
1.7.
keys.
p. it is recommended
fewer
precision
ENGINEERING
will
to write
nm, not ,I~,,. tail and should
or italic).
To Convert
From
pound-force
per
To
Multiply
By
square foot pound-force per
Pa
4.788
square inch inch
Pa m
6.894 757 E+03 2.540* E-02
026 E+OI
find that the SI symbols than the shorthand
forms
These conversions
mean that
for the unit names. I Ibf/ft’
APPENDIX D General Conversion
I inch becomes
1.7 is intended
1. To mcasurc
“m&c” units. the fundamental Relationships arc
the
that are not followed
result
prcssions
of
of
physical tnultiplying
and metric
by an astcrlsk
measurements factors
measurements
or miscellaneous
numbers
units of coherent
Relationships that are exact in terms of SI unit arc followed by an asterisk.
appmximatc. 2. To provide 2encral
to serve two purposes:
express the definitions of general ah exact numerical multiples of
given units
either
or arc only
for converting
cx-
by
and
numbers
to corresponding
0.0254
m (exactly).
The unit symbol for pound-force sometimes is written Ibf and sometimes lb, or lb/: the form Ibf is recommended.
Organization The conversion
factors generally
arc liatcd alphabetically
by units having specific names and compound units derived from these specific units. A number of units starting with the pound “p” section of the list. Conversion
new
listed
units.
26 Pa,
becomes 6894.757 Pa or 6.894 757 kPa, and
Factors”
General Table
becomes 47.880
I Ibf/in.’
be
symbol
(lb)
factors classified
in Refs.
by physical
alphabetical
examples follow. I. Find the conversion
factor
factors are written
as a number
(B/D)/psi
Convert
one and less than
IO, with
(i.e..
seven or fewer
decimal
places
(E-01)
Each number
is fol-
substitute
six or fewer
total digits).
lowed by the letter E (for exponent), a plus or minus symbol, and two digits that indicate the power of 10 by which the number must be multiplied to obtain the correct value.
list by substitution
to (mj/d)/Pa. m”/d
[ 1.589 873 (E-01)]/]6.894 =2.305
arc
units. Two
for productivity 1 B/D
to
7.57 (E+03)
in&x, I.589
873
Pa. Then.
757 (E-03)]
916 (E-OS)
(m3/d)/Pa.
For example, 2. Find the MJim. Convert
0.035 239 07. Similarly,
1.609 344” (E+03) Then. substitute
3.386
of converted
and I psi to 6.894
or
3.523
quantities
The conversion factors for other compound units can generated easily from numbers given in the
Notation
than
In the
3 and 4.
Conversion factors are presented for ready adaptation to computer readout and electronic data transmission. The equal to or greater
arc located
907 (E-02)
389 (E+03)
is 3.523
is 3.386
907~
389~
IO-’
I ii to 3.048*
[I.609
344 (E+03)]
18.896 444 (E+03)] +[3.048 (E-O])]
3 386.389.
the conversion
m; and
(*) after the numbers factor
is exact
(E-01)
m.
IO3
or
An asterisk
conversion factor for tonf.mile/ft to I tonf to 8.896 444 (E+03) N: 1 mile to
shown
indicates
that
=4.697
322 (E+07)
(N.m)/m
=4.697
322 (E+Ol)
MJim.
or J/m
and that all subsequent
digits (for rounding purposes) are zero. All other conversion factors have been rounded to the figures given in ac-
When conversion factors for complex compound units are being calculated from Table I .7. numerical uncer-
cordance
tainties
with procedures
outlined
in the preceding
text.
may
“significant”) ‘Based on ASTM Pub E380-82 @?I 3), values Of CO”“elSlO” IaCtOrs tabulated herewth are identical with those in E380-82, generally slm~far material IS found m Ref 4 Conversion values in earlier edltlons of E 380 (for example E 380.74) are based on Ref 15 wh,ch has available some faclors w,,h more than seven d,g,,s
already Mechtly \cvcn
be present digit
in the seventh
of the answer
(or lesser
last
because of roundings
taken for the last digit of tabulated values. ” provides conversion factors of more than digits
for certain
quantities.
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
58-15
TABLE 1.7-ALPHABETICAL LIST OF UNITS (symbols of SI units given in parentheses) To Convert From
To
Multiply By
abampere abcoulomb abfarad abhenry abmho
ampere (A) coulomb (C) farad (F) henry (H) siemens (S)
1.O’ 1.O’ 1.O’ 1.0 1.O’
E+Ol E+Ol E+O9 E-09 E+09
abohm abvolt acrefoot (U.S. survey)“’ acre (U.S survey)“’ ampere hour
ohm (0) volt (V) meter3 (m3) mete? (m’) coulomb (C)
1.0’ 1.0’ 1.233489 4.046 873 3.6’
E-09 E-08 E+03 E + 03 E+03
are angstrom astronomical unit atmosphere (standard) atmosphere (technical = 1 kgf/cm2)
meter* (m2) meter (m) meter (m) Pascal (Pa) Pascal (Pa)
1.O’ 1.O’ 1.495979 1.013250’ 9.806 650’
E+02 E-10 E+ll E+05 E + 04
bar barn barrel (for petroleum, 42 gal) board foot
Pascal (Pa) meter* (m*) meter3 (m”) meter3 (m”)
1.O’ 1.O’ 1.589873 2.359 737
E+05 E-28 E-01 E - 03
Elntish thermal Bntish thermal Bntish thermal Bntish thermal Bntish thermal Bntlsh thermal
joule loule joule joule joule joule
1.055 056 1.05587 1.054 350 1.05967 1.05480 1.05468
E + 03 E+03 E + 03 E+03 E+03 E+03
watt per meter kelvin [W/(mK)]
1.730 735
E f 00
watt per meter kelvin [W/(mK)]
1.729 577
E + 00
watt per meter kelvin [W/(m.K)]
1.442 279
E ~ 01
watt per meter kelvin [Wl(m.K)]
1.441 314
E-01
watt per meter kelvin [W/(m.K)]
5.192 204
E +02
unit unit unit unit umt unit
(International Table)“’ (mean) (thermochemical) (39°F) (59°F) (60°F)
Btu (International Table)-fV(hr-ft2-“F) (thermal conductlvrty) Btu (thermochemical)-ft/(hr-ft*-OF) (thermal conductlvtty) Btu (International Table)-m.i(hr-R*-“F) (thermal conductlvrty) Btu (thermochemical)-in.‘(hr-RZ-“F) (thermal conductivity) Btu (International Table)-in.i(s-Hz-“F) (thermal conductivity) Btu (thermochemical)-in./(s-f12-“F) (thermal conductlvily)
(J) (J) (J) (J) (J) (J)
watt per meter kelvin [Wl(m.K)]
5.188 732
E+02
B1u (International Table)/hr Btu (thermochemical)/hr Btu (thermochemical):mm Btu (thermochemical)%
watt(W) watt (W) watt(W) watt (W)
2.930711 2.928 751 1.757250 1.054350
E-01 E - 01 E+Ol E+03
Btu Btu Btu Btu Btu
(International Table)ift? (thermochemlcai)ifV (thermochemical)i(ft*-hr) (thermochemical)i(H2-min) (thermochemical)i(ft*-s)
joule per meter2 (Jim*) joule per meter2 (Jim*) watt per mete? (W/ml) watt per meter2 (W/m’) watt per mete? (W/m*)
1.135653 1.134893 3.152481 1.891 489 1.134893
E+04 E+04 E-00 E + 02 E+04
Btu (thermochemical)/(irxZ-s) Btu (International Table)I(hr-V-OF) (thermal conductance) Btu (thermochemical)i(hr-V-OF) (thermal conductance) Btu (International Table)i(s-R*-“F) Btu (thermochemical)@tt*-OF)
watt per mete? (W/m’)
1.634 246
E + 06
watt per meter* kelvin [W/(m’.K)]
5.678 263
E + 00
watt per meter* kelvin [W/(m*.K)] watt per meter* kelvin [W/(m*.K)] watt per meter2 kelvin [W/(m’.K)]
5.674 466 E + 00 2.044 175 E + 04 2.042 808 E + 04
Btu (International Table)ilbm Btu (thermochemical):lbm Btu (International Table)i(lbm-“F) (heat capacity) Btu (thermochemical)i(lbm-“F) (heat capaaty)
joule per kilogram (J/kg) joule per kilogram (J/kg)
2.326’ 2.324 444
E+03 E + 03
joule per kilogram kelvin [J/(kg.K)]
4.186 8’
E+03
joule per ktlogram kelvin [J/(kgeK)]
4.184 000
E +03
“Fence 1893 the U S bass 01 length measurement has been dewed IrOm metric standards In 1959 a small rellnement was made I” the defimlmn of the yard to resolve d,screpanc,es both I” this country and abroad. which changed ,ts length from 3600 3937 m lo 0 9144 m exactly This resulted I” the new value being shorter by two parts I” a rrvlnn At the same time it was deaded that any data r leet derived from and publIshed as a result of geodetic surveys withm the U S would wna~n with the old standard (1 f, = ,200 3937 m) unt,l further dec,s,on Th,s loot IS named the U S suvey loot As a result, all U S land measurements I” U S. c”stoma~ ““1,s WIIIrelate tothe meter by the old standard All the mnvers~on factors I” these tables for umts relerenced to thus loatnote are based on the U.S survey foot. ratherthaiihe inlernatu,nal loot Con&on Iactors for me land measure glen below may be delemned from the loltowlng relatlonships 1 league = 3 miles (exactly) 1 rod = 16”~ fl (exactly] 1 chain = 66 fl (exactly) 1 SectIon 1 sq mile 1 townsh,p = 36 sq m,les @This value was adopted m 1956. Some of the older lnlernatlonal
Tables use Ihe value 1 055 D4 E + 03 The exact con~ers!on factor IS 1 055 055 852 62‘ E + 03
PETROLEUM ENGINEERING
58-16
HANDBOOK
TABLE 1.7-ALPHABETICAL LIST OF UNITS (continued) (symbols of SI units given in parentheses) To
To Convert From
Multiply By”
bushel caliber calorie calorie calorie
(U.S.) (inchj (International Table) (mean) (thermochemical)
mete? (ml) meter (m) joule (J) joule (J) joule (J)
3.523 907 2.54 4.1868’ 4.19002 4.184’
E - 02 E-02 E+OO E+OO E+OO
calorie calorie calorie calorie calorie
(15°C) (20°C) (kilogram, International Table) (kilogram, mean) (kilogram, thermochemical)
joule joule joule joule joule
(J) (J) (J) (J) (J)
4.185 80 4.181 90 4.186 8’ 4.190 02 4.184’
E+OO E+OO E+03 E+03 E+03
joule joule joule joule joule
per per per per per
4.184’ 4.186’ 4.184’ 4.186 8 4.184’
E+04 E+03 E+03 E+03 E+03
cal cal cal cal cal
(thermochemical)/cm* (International Table)/g (thermochemical)ig (International Table)/(gX) (thermochemical)/(gX)
meter* (J/m’) kilogram (J/kg) kilogram (J/kg) kilogram kelvin [Jl(kgK)] kilogram kelvin [J/(kg.K)]
cal (thermochemical)imin cal (thermochemical)is cal (thermochemical)/(cmz.min) cal (thermochemical)/(cm**s) cal (thermochemical)~(cm+‘C) capture unit (cu. = 10m3cm-‘)
watt (W) watt (W) watt per meter’ (W/m*) watt per mete? (W/m2) watt per meter kelvin [W/(m.K)] per meter (m-l)
6.973 333 4.184’ 6.973 333 4.184’ 4.184’ 1.O’
E - 02 E+OO E + 02 E+O4 E+02 E-01
carat (metric) centimeter of mercury (0°C) centimeter of water (4°C) centipoise centistokes
kilogram (kg) Pascal (Pa) Pascal (Pa) Pascal second (Pas) mete? per second (m*/s)
2.0’ 1.33322 9.806 38 1.O’ 1.O’
E-04 Et03 E + 01 E-03 E-06
circular mil cl0 cup curie cycle per second
mete? (m2) kelvin mete? per watt [(Km*)/W] meteP (m3) becquerel (Bq) hertz (Hz)
5.067 075 2.003 712 2.365 882 3.7’ 1 .O’
E - 10 E-01 E - 04 Et10 E+OO
day (mean solar) day (sidereal) degree (angle)
second (s) second (s) radian (rad)
8.640 000 8.616 409 1745329
E + 04 E+04 E-02
degree degree degree degree degree
kelvin (K)
T, = T,c + 273.15
degree Celsius kelvin (K) kelvin (K)
r, = (T, - 32)11.8 T, = (T, + 459.67)/1.8
Celsius centigrade (see degree Celsius) Fahrenheit Fahrenheit Rankine
r, = J41.8
“Fshr-ft2/Btu(International Table) (thermal resistance) “F.hr-ftVBtu (thermochemical) (thermal resistance) denier dyne dynecm dyne/cm2 electronvolt
kelvin mete? per watt [(Km*)/W]
1.781 102 E-01
kelvin meter’ per watt [(K.m*)IW] kilogram per meter (kg/m) newton (N) newton meter (N.m) Pascal (Pa) joule (J)
1.762 250 1.111 111 1.O’ 1.O’ 1.O’ 1.602 19
E - 01 E-07 E-05 E-07 E-01 E-19
EMU EMU EMU EMU EMU
of of of of of
capacitance current electric potential inductance resistance
farad (F) ampere (A) volt (V) henry U-V ohm (0)
1.O’ 1.O’ 1.O’ 1.O’ 1.O’
E+O9 E+Ol E-08 E-09 E-09
ESU ESU ESU ESU ESU
of of of of of
capacitance current electnc potential inductance resistance
farad (F) ampere (A) volt (V) henry 0-U ohm (0)
1.112650 3.335 6 2.997 9 8.987554 8.987 554
E-12 E- 10 E+02 E+ll E + 11
erg erg/cm% erg/s faraday (based on carbon-l 2) faraday (chemical) faraday (physical) fathom fermi (femtometer) fluid ounce (U.S.)
joule (J) watt per meter* (W/m>) watt (W) coulomb (C) coulomb (C) coulomb (C) meter (m) meter (m) meter’ (m3)
1.o 1.O’ 1.O’ 9.648 9.649 9.652 1.828 1.o 2.957
E-07 E-03 E-07 E + 04 E + 04 E+04 E+OO E-15 E - 05
foot foot (U.S. survey)“1
meter (m) meter (m)
3.048’ 3.048 006
70 57 19 8 353
E-01 E -01
58-17
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
TABLE 1.7-ALPHABETICAL LIST OF UNITS (continued) (symbols of SI units given in parentheses) To
To Convert From
Multiply By”
Pascal (Pa) meter2 (m’) mete? per second (m*is) meter? per second (m’is)
2.988 9.290 2.580 9.290
98 304’ 640’ 304’
E +03 E - 02 E - 05 E - 02
mete? mete? mete? mete?
2.831 4.719 2.831 8.630
685 474 685 975
E - 02 E -04 E -02 E -03
footcandle footlambert
meter per second (m/s) meter per second (m/s) meter per second (m/s) meter per second2 (misz) Iux (lx) candela per meter2 (cdim2)
8.466 667 5.080’ 3.048’ 3.048’ 1.076391 3.426 259
E - 05 E-03 E-01 E-01 E+Ol E + 00
ft-lbf ft-lbf/hr ft-lbfimin ft-lbf/s ft-poundal free fall, standard (g)
joule (J) watf (W) watt (wj watt (W) joule (J) meter per second’ (m/s’)
1.355818 3.766 161 2.259 697 1.355818 4.214 011 9.806 650’
E+OO E -04 E - 02 E+OO E -02 E + 00
cm/s? qallon (Canadian liquid) gallon (U.K. liquid) gallon (U.S. dry) gallon (US liquid) gal (U.S. liquid)iday gal (US. liquid)/min gal (U.S. liquid)/hphr (SFC, specific fuel consumption)
meter per second2 (m/s’) mete? (m3) mete? (m3) mete? (m3) mete? (mJ) mete? per second (mVs) mete? per second (m%)
1.O’ 4.546 090 4.546 092 4.404 884 3.785412 4.381 264 6.309 020
E-02 E - 03 E - 03 E - 03 E-03 E - 08 E - 05
mete? per joule (mYJ)
1.410089
E-09
gamma (magnetic field strength) gamma (magnetic flux density) gauss gilbert gill (U.K.) gill (U.S.)
ampere per meter (Aim) tesla (T) tesla (T) ampere (A) mete? (m3) mete? (ma)
7.957 747 1.O’ 1.o 7.957 747 1.420 654 1.182941
E - 04 E-09 E-04 E - 01 E - 04 E-04
grad grad grain (117000 Ibm avoirdupois) grain (Ibm avoirdupoisi7000)lgaI (U.S. liquid)
degree (angular) radian (rad) kilogram (kg)
9.0’ 1.570796 6.479 891
E-01 E-02 E - 05
kilogram per mete? (kg/m3)
1.711 806
gram glcm3 gram-force/cm2 hectare horsepower (550 ft-lbfis)
kilogram (kg) kilogram per mete? (kg/m3) Pascal (Pa) meter* (m2) watt (W)
1.O’ E-03 1.O’ Et03 9.806 650’ E + 01 1.O’ E+04 7.456 999 E + 02
horsepower horsepower horsepower horsepower horsepower
watt watt watt watt watt
9.809 50 7.460’ 7.354 99 7.460 43 7.457 0
foot of water (39.2”F) sq ft ft*/hr (thermal diffusivity) ftV3
cu ft (volume; section modulus) ftYmin W/S
ff (moment of section)@) fUhr ft/min ftk ft/SZ
(boiler) (electric) (metric) (water) (U.K.)
(m3) per second (m’1.s) per second (mVs) (ml)
(W) (W) (W) (W) (W)
l
E-02
E + 03 E+02 E+02 E + 02 E+O2
hour (mean solar) hour (sidereal) hundredweight (long) hundredweight (short)
second (s) second (s) kilogram (kg) kilogram (kg)
3.600 3.590 5.080 4.535
000 E + 03 170 E + 03 235 E + 01 924 E + 01
inch inch inch inch inch
meter (m) Pascal (Pa) Pascal (Pa) Pascal (Pa) Pascal (Pa)
2.54’ 3.386 3.376 2.490 2.488
38 85 82 4
E-02 E + 03 E + 03 E + 02 E+02
sq in. cu in. (volume; section modulus)i41 in.3/min in4 (moment of section)13’
meter* meteP mete? meteP
6.451 1.638 2.731 4.162
6’ 706 177 314
E-04 E ~ 05 E-07 E-07
in/s in .I$ kayser kelvin
meter per second (m/s) meter per second* (m/s2) 1 per meter (1 /m) degree Celsius
of of of of
mercury (32°F) mercury (60°F) water (39.2”F) water (60°F)
(m*) (m”) per second (m%) (ma)
I31Thus sometimes IS tailed the rrwment of merha of a plane sechon about a spafled 14’The exact c~nwrslon factor IS 1.636 706 4’E-05
~XIS
2.54’ E-02 2.54’ E-02 1.O’ E+02 T., = T, - 273.15
PETROLEUM ENGINEERING
58-18
HANDBOOK
TABLE 1.7-ALPHABETICAL LIST OF UNITS (continued) (symbols of SI units given in parentheses) To
To Convert From
Multiply By”
joule (J) joule (J) joule (J) watt (W) watt (W)
4.186 8’ 4.190 02 4.184’ 6.973 333 4.184’
kilogram-force (kgf) kgf.m kgfs*im (mass) kgf/cm2 kgf/m* kgf/mm?
newton (N) newton meter (N.m) kilogram (kg) Pascal (Pa) Pascal (Pa) Pascal (Pa)
9.806 9.806 9.806 9.806 9.806 9.806
km/h kilopond kilowatthour (kW-hr) kip (1000 Ibf) kip/in.* (ksi) knot (international)
meter per second (m/s) newton (N) joule (J) newton (N) Pascal (Pa) meter per second (m/s)
2.777 778 E - 01 9.806 65’ E + 00 3.6 E+06 4.448 222 E + 03 6.894 757 E + 06 5.144444 E-01
lambert lambert langley league light year IiteV’
candela per meteP (cd/m*) candela per mete? (cd/m*) joule per mete? (J/mz) meter (m) meter (m) meter-l (ml)
1in’ E+04 3.183099 E+03 4.184 E+04 (see Footnote 1) 9.46055 E+15 1.0 E-03
maxwell mho microinch microsecond/foot (@ft) micron mil
weber (Wb) siemens (S) meter (m) microsecond/meter (&m) meter (m) meter (m)
1.o 1.o 2.54’ 3.280 840 1.O’ 2.54’
E-08 E+OO E-08 E + 00 E-06 E-05
mile mile mile mile mile mile
meter meter meter meter meter meter
1.609 344’ 1.609 3 1.609 347 1.852 1.853 184’ 1.852’
E + 03 E+03 E + 03 E+03 E+03 E+03 E + 06 E + 06 E-01 E + 00 E +Ol E+03
kilocalorie kilocalorie kilocalorie kilocalorie kilocalorie
(International Table) (mean) (thermochemical) (thermochemical)imin (thermochemical)/s
(international) (statute) (U.S. survey)“) (international nautical) (U.K. nautical) (U.S. nautical)
(m) (m) (m) (m) (m) (m)
E+03 E+03 E+03 E + 01 E+03
65’ E + 00 65’ E + 00 65’ E + 00 65’ E + 04 65’ E + 00 65’ E + 06
sq mile (international) sq mile (U.S. survey)“’ mileihr (international) mileihr (international) mileimin (international) mile/s (international)
mete? (m2) mete? (m2) meter per second (m/s) kilometer per hour (kmih) meter per second (m/s) meter per second (m/s)
2.589 2.589 4.470 1.609 2.682 1.609
millibar millimeter of mercury (0°C) minute (angle) minute (mean solar) mcnute (sidereal) month (mean calendar)
Pascal (Pa) Pascal (Pa) radian (rad) second (s) second (s) second (s)
1.O’ 1.33322 2.908 882 6.0’ 5.983617 2.628 000
E+02 E+02 E - 04 E+Ol E+Ol E + 06
oersted ohm centimeter ohm circular-mil per ft
ampere per meter (A/m) ohm meter (0.m) ohm millimeter* per meter [(0.mm2)m]
7.957 747 1.O’
E + 01 E-02
1.662 426
E ~ 03
ounce (avoirdupois) ounce {troy or apothecary) ounce (U.K. fluid) ounce (U.S. fluidj ounce-force ozf.in.
kilogram (kg) kilogram (kg) meter3 (m”) mete? (m3) newton (N) newton meter (N.m)
2.834 952 3.110348 2.841 307 2.957 353 2.780 139 7.061 552
E ~ G2 E-02 E-05 E - 05 E-01 E - 03
oz (avoirdupois)igal (U.K. liquid) oz (avoirdupois)/qal (U.S. liquid) oz (avoirdupois)&? oz (avoirdupois)/fF oz (avoirdupois)/yd2 parsec peck (U.S.)
kilogram per kilogram per kilogram per kilogram per kilogram per meter (m) mete? (m3)
6.236 021 7.489 152 1.729994 3.051 517 3.390 575 3.085 678 8.809 768
E + 00 E+OO E+03 E-01 E - 02 E + 16 E ~ 03
pennyweight perm (‘C)@)
kilogram (kg) kilogram per Pascal second meter* [kg!(Pas.m2)]
meterj (kg/m>) metep (kgimJ) meterj (kg/mJ) meter2 (kg/m2) meter’ (kg/m’)
‘%, 1964 the General Conference on Weights and Measures adopted the name liter as a special name for the c,,blc decr,,eter slightly (prewous value, 1 WO 028 dm3 and m expression of preclslon volume measurement this lact must be kept I” mind t61Not the sameas resewmr “per”, ”
988 998 4’ 344’ 24’ 344’
1.555 174 E-03 5.721 35
E-11
Before ,h,s dec,s,on ,be ,,ter d,f,e,ed
58-19
THE Sf METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
TABLE 1.7-ALPHABETICAL LIST OF UNITS (continued) (symbols of SI units given in parentheses) Multiply By”
To Convert From perm (23”C)16’ perm.in. (OC)c71 perm.in. (23°C)“’
kilogram per Pascal second mete? [kg/( Pasm2)] krlogram per Pascal second meter [kg/(Pasm)] kilogram per Pascal second meter [kmi(Pasm)]
5.74525
E-11
1.45322
E-12
1.459 29
E- 12
phol oica (orinter’s) pint (U.S. dryj oint (U.S. liauid) point (printers)’ poise (absolute viscosity)
lumen per mete? (lm/m2) meter (m) metep (m3) mete? (m3) meter (m) Pascal second (Pas)
1.O’ 4.217518 5.506 105 4.731 765 3.514 598’ 1.o
E+04 E-03 E-04 E - 04 E - 04 E-01
pound (lbm avoirdupois)@’ pound (troy or apothecary) Ibm-ftz (moment of Inertia) Ibm-in.? (moment of inertia)
kilogram kilogram kilogram kilogram
4.535 924 3.732417 4.214 011 2.926 397
E - 01 E-01 E-02 E - 04
Ibmift-hr lbmift -s IbmW Ibm/ft3 Ibm/gal (U.K. liquid) lbmigal (U.S. liquid)
Pascal second (Pas.) Pascal second (Pas) kilogram per mete? (kg/m2) kilogram per mete? (kg/m3) kilogram per mete? (kg/m3) kilogram per meter3 (kg/m3)
4.133 789 1.488 164 4.882 428 1.601 846 9.977 633 1.198264
E -04 E+OO E + 00 E +Ol E + 01 E+02
lbmihr Ibm/(hp hr) (SFC, specific fuel consumption) Ibmlin.3 lbmimin lbmis Ibm/yd3
kilogram per second (kg/s)
1.259979
E-04
krlogram krlogram ktlogram kilogram kilogram
1.689 2.767 7.559 4.535 5.932
E - 07 E + 04 E - 03 E - 01 E - 01
poundal poundalift’ poundal-s/R2
newton (N) Pascal (Pa) Pascal second (Pas)
1.382 550 E - 01 1.488 164 E+OO 1.488 164 E+OO
pound-force (lbf)‘91 IbfWO’ Ibf-ft:in.“‘J lbf-in.“‘l Ibf-rn.:ln.l”’ Ibf-sift’ lbfift IbfW Ibfiin. Ibf/itxz (psi) lbfllbm (thrust/weight [mass] ratio)
newton (N) newton meter (N.m) newton meter per meter [(N-m)/m)] newton meter (N.m) newton meter per meter [(N-m)/mj Pascal second (Pas) newton per meter (N/m) Pascal (Pa) newton per meter (N/m) Pascal (Pa) newton per kilogram (N/kg)
4.448 222 1.355818 5.337 866 1.129848 4.448 222 4.788 026 1.459 390 4.788 026 1.751 268 6.894 757 9.806 650
quart (U.S. dry) quart (U.S. liauid) rad (radiation’dose absorbed) rhe rod roentgen
mete? (m3) meter3 (m3) gray (GY) 1 per Pascal second [ 1/(Pas)] meter (m) coulomb per kilogram (C/kg)
1.101 221 E-03 9.463 529 E - 04 1.0’ E-02 1.O’ E+Ol (see Footnote 1) 2.58 E-04
second (angle) second (sidereal) section shake
radian (rad) second (s) meter2 (m*) second (s)
4.848 137 E -06 9.972 696 E -01 (see Footnote 1) 1.000 000’ E - 08
slug slug/(ft-s) slug/fV
kilogram (kg) Pascal second (Pas) kilogram per metel3 (kg/m3)
1.459 390 4.788 026 5.153 788
E t 01 E t 01 E+02
statampere statcoulomb statfarad stathenry statmho
ampere (A) coulomb (C) farad (F) henry (H) sremens (S)
3.335 640 3.335 640 1.112650 8.987 554 1.112650
E 110 E - 10 E-12 E + 11 E-12
statohm statvolt stere
ohm (It) volt (V) mete? (m”)
8.987 554 2.997 925 1.O’
Et 11 E + 02 E+OO
“‘Not the same dlmenslons as “m#!darcy-foot” 01. ‘BJThe exacf conversion factor IS 4 535 923 7’E lg’The exact conversion factor IS 4 448 221 615 260 5’E + 00 “@‘Torque unit. see text dwzusslon of “Torque and Bending Moment” ““Torque dlwded by length see fexf d!scuss!on 01 Torque and Bendmg
Moment
(kg) (kg) meter’ (kg-m’) mete? (kg-m*)
per per per per per
Joule (kg/J) mete? (kg/ma) second (kg/s) second (kg/s) meter] (kgim3)
659 990 873 924 764
E + 00 E+OO E +Ot E-01 E t 00 E + 01 E t 01 E + 01 Et 02 E + 03 E t 00
58-20
PETROLEUM ENGINEERING
HANDBOOK
TABLE 1.7-ALPHABETICAL LIST OF UNITS (continued) (symbols of SI units given in parentheses) To Convert From
To
Multiply By”
stilb stokes (kinematic viscosity)
candela per meter* (cd/m*) meter* per second (m*/s)
1.O’ 1.O’
E+04 E-04
tablespoon teaspoon tex therm
metef (m3) mete? (m3) kilogram per meter (kg/m) joule (J)
1.470 676 4.928 922 1.O’ 1.055 056
E - 05 E - 06 E-06 E + 08
ton (assay) ton (tong, 2,240 Ibm)
kilogram (kg) kilogram (kg) kilogram (kg) joule (J) watt (W) metep (m3)
2.916 667 1.016047 1.o 4.184 3.516 800 2.831 685
E-02 E+03 E+03 E+09”” E +03 E + 00
ton (short, 2000 Ibm) ton (long)/ydJ ton (shott)/hr ton-force (2000 Ibf) tonne
kllogram (kg) kilogram per mete? (kg/m3) kilogram per second (kg/s) newton (N) kilogram (kg)
9.071 847 1.328 939 2.519958 8.896 444 1.O’
E + 02 E + 03 E-01 E + 03 E+03
torr (mm Hg, 0°C) township unit pole watthour (W-hr) w.s W/cm2 W/in.?
Pascal (Pa) mete? (mz) weber (Wb) joule (J) joule (J) watt per meter? (W/m’) watt per meter2 (W/m2)
1.33322 E+02 (see Footnote 1) 1.256 637 E - 67 3.60’ E+03 1.O’ E+OO 1.O’ Et04 1.550003 E+03
yard yd2 Yd3 ydJ/min
meter (m) mete? (m2) mete? (m3) mete? per second (m%)
9.144’ 8.361 274 7.645 549 1.274 258
E-01 E - 01 E - 01 E - 02
year (calendar) year (sidereal) year (tropical)
second (s) second (s) second (s)
3.153600 3.155 815 3.155693
Et07 Ei07 E+07
ton ton ton ton
(metric) (nuclear equivalent of TNT) (refrigeration) (register)
“2JOet~ned (not measured)
value
APPENDIX E TABLE 1.8 -
CONVERSION FACTORS FOR THE VARA’
Location Argentina, Paraguay Cadiz, Chile, Peru California, except San Francisco San Francisco Central America Colombia Honduras Mexico Portugal, Brazil Spain, Cuba, Venezuela, Philippine Islands Texas Jan. 26, 1801, to Jan. 27, 1838 Jan. 27, 1838 to June 17, 1919, for surveys of state land made for Land Office Jan. 27, 1838 lo June 17, 1919, on private surveys (unless changed to 33-113 in. by custom arising to dignity of law and overcoming former law) June 17, 1919, to present
Value of Vara in Inches
Conversion Factor, Varas to Meters
Source
34.12 33.37
8.666 8.476
E-01 E-01
Ref. 16 Ref. 16
33.3720 33.0 33.87 31.5 33.0 43.0 33.38”
8.478 49 8.38 8.603 8.00 8.38 8.380 1.09 8.479
E-01 E-01 E-01 E-01 E-01 E-01 Et00 E-01
Ref. 16 Ref. 16 Ref. 16 Ref. 16 Ref. 16 Refs. 16 and 17 Ref. 16 Ref. 17
32.8748
8.350 20
E-01
Ref. 16
33-113
8.466 667
E-01
Ref. 16
32.8748 33-113
8.350 20 8.466 667
E-01 E-01
Ref. 16 Ref. 16
*It IS evident from Ref 16 that accurate defined lengths 01 the vala varied slgnlflcantly, according to hlslotlcal date and localay used Co”“ers~~“s. the user should check Closely lnlo Lhe dale and localIon of the wrveys mvolved, with due regard lo what local ,x,cl,ce and place “This value quoted horn Webster’s New lnternakmal D~chona~
For work rqulrlng accura& may have been at that t,me
58-21
THE St METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
TABLE l.Q-“MEMORY
JOGGER”-METRIC
UNITS
“BallPark” Metnc Values; (Do Not Use As Conversion Factors) 4000 -i barrel British thermal unit British thermal unit per pound-mass calorie centipoise centistokes darcy degree Fahrenheit (temperature difference) dyne per centimeter foot cubic foot (cu ft) cubic foot per pound-mass (fWbm) square foot (sq ft) foot per minute
0.16 1000 1 2300 2.3 4 1’ 1’ 1 0.5 1’ -i 30 0.3 0.03 0.06 0.1 {
foot-pound-force foot-pound-force per minute foot-pound-force per second horsepower horsepower, boiler inch kilowatthour mile ounce (avoirdupois) ounce (fluid) pound-force pound-force per square inch (pressure, psi) pound-mass pound-mass per cubic foot section ton, long (2240 pounds-mass) ton, metric (tonne) ton, short ‘Exactaqulvalents
0.4
g’” 1.4 0.02 1.4 750 10 2.5 3.6’ 1.6 28 30 4.5 7 0.5 16 260 2.6 2.6 1000 1000’ 900
square meters
hectare cubic meter joules joules per kilogram kilojoules per kilogram joules millipascal-second square millimeter per second
square micrometer kelvin millinewton per meter centimeters meter cubic meter cubic meter per kilogram square meter ~i%%&n$%cond joules watt watts watts (% kilowatt)
kilowatts centimeters megajoules kilometers grams cubic centimeters newtons kilopascals kilogram kilograms per cubic meter hectares million square meters square kilometers kilograms kilograms kilograms
APPENDIX F
Part 2: Discussion of Metric Unit Standards* Introduction The standards and conventions shown in Part I are part of the SPE tentative standards. Table 2. I presents nomenclature for Tables 2.2 and 2.3. Table 2.2 is a modified form of a table in API 2564 reflecting SPE recommendations. Table 2.3 shows a few units commonly used in the petroleum industry that are not shown in Table 1.7 and 2.2. The columns in these tables are based on the following. Quantity and SI Unit. The quantity and the base or derived SI unit that describes that quantity. Customary Unit. The unit most commonly used in expressing the quantity in English units. SPE Preferred. The base or derived SI unit plus the approved prefix, if any, that probably will be used most ‘Prepared
by John M Campbell
for the subcommftfee
commonly to achieve convenient unit size. Any approved prefix may be used in combination with an approved SI unit without violation of these standards except where otherwise noted. Other Allowable. A small, selected list of non-3 that are approved temporuril~~ for the convenience English-metric transition. Use of the allowable may be discouraged but is not prohibited. Any tional. non-9 unit not shown is prohibited under standards.
units
of the units tradithese
Conversion Factor. For certain commonly used units, a conversion factor is shown. The primary purpose in these tables is to show how the preferrelf metric unit compares in size with the traditional unit. An effort has been made to keep the unit sizes comparable to minimize transition difficulties.
PETROLEUM ENGINEERING
58-22
A detailed summary of general conversion factors is included as Table 1.7 in Part 1 of this report. The notation for conversion factors in Tables 2.2 and 2.3 is explained in the introduction to Table 1.7. Fig. 2. I shows graphically how SI units are related in a very coherent manner. Although it may not be readily apparent, this internal coherence is a primary reason for adoption of the metric system of units. The SPE Metrication Subcommittee is endeavoring to provide SPE members with all information needed on the International System of Units and to provide tentative standards (compatible with SI coherence, decimal, and other principles) for the application of the SI system to SPE fields of interest. The tentative SPE standards are intended to reflect reasonable input from many sources, and we solicit your positive input with the assurance that all ideas will receive careful consideration.
Review of Selected Units Certain of the quantities and units shown in Tables 2.2 and 2.3 may require clarification of usage (see also the notes preceding Tables 2.2 and 2.3).
HANDBOOK
(a). Note that (a) is used as the abbreviation for year (annum) instead of (yr). The use of the minute as a &me unit is discouraged because of abbreviation problems. It should be used only when another time unit is absolutciy inappropriate. Date and Time Designation The Subcommittee proposes to recommend a standard date and time designation to the American Nat]. Standards Inst., as shown below. This form already has been introduced in Canada. 76
-
year
10
month
-
03
-
16
:
24
hour minute day (76-IO-03-16:24: 14)
:
I4
second
The sequence is orderly and easy to remember: only needed portions of the sequence would be used - most documents would use the first three. No recommendation has been made for distinguishing the century, such as 1976 vs. 1876 vs. 2076.
Time
Area
Although second(s) is the base time unit, any unit of time may be used - minute (min), hour(h), day (d), and year
The hectare (ha) is allowable but its use should be confined to large areas that describe the area1 extent of a por-
TABLE 2.1 -NOMENCLATURE Unit Symbol A 4 bar C cd “C d F GY
9
H h Hz ha J K kg kn L Im IX
m
min N
naut. mile R Pa rad S s sr T v W
Wb
Quantitv
Name ampere annum (year) becquerel bar coulomb candela degree Celsius degree day
farad gray gram henry
hour hertz hectare joule kelvin kilogram knot liter lumen Iux meter minute minute newton U.S. nautical mile ohm Pascal radian siemens second second steradian tesla
tonne volt watt weber
electric current time activity (of radionuclides)
pressure quantity of electricity luminous intensity temperature plane angle time electric capacitance absorbed dose mass inductance time frequency area work, energy temperature mass velocity volume luminous flux illuminance length time plane angle force length electric resistance pressure plane angle electrical conductance time plane angle solid angle magnetic flux density mass electric potential power magnetic flux
FOR TABLES 2.2 AND 2.3 Tvpe of Unit base SI unit allowable (not official SI) unit derived SI unit = l/s allowable (not official SI) unit, derived SI unit, = 1 As base SI unit derived SI unit = 1.0 K allowable (not official SI) unit allowable (not officialSI) unit, derived SI unit, = 1 A.sN derived SI unit, = J/kg allowable (not official SI) unit, derived SI unit, = 1 Vs/A allowable (not official SI) unit, derived SI unit, = 1 cycle/s allowable (not official SI) unit, derived SI unit, = 1 N.m base SI unit base SI unit allowable (not official Sl) unit,
= lo5 Pa
= 24 hours = 10~3 kg = 3.6 x 10’s = lo4 m2
= 5.144 444 x 10-j m/s = 1.852 km/h allowable (not official Sl) unit, = 1 dm3 derived SI unit, = 1 cd.sr derived SI unit, = 1 Im/mZ base SI unit allowable (not official SI) unit Allowable cartography (not official SI) unit derived SI unit, = 1 kg,m/s2 allowable (not official SI) unit, = 1.652 x lo3 m derived SI unit, = 1 V/A derived SI unit, = 1 N/m* supplementary SI unit derived SI unit, = 1 AN base SI unit allowable cartography (not official 9) unit supplementary SI unit derived SI unit, = 1 Wb/mZ allowable (not official SI) unit, = lo3 kg = 1 Mg derived SI unit, = 1 W/A derived SI unit, = 1 J/s derived SI unit, = 1 V..s
58-23
THE Sf METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
tion of the earth’s crust (normally replacing the acre or section). Volume The liter is an allowable unit for small volumes only. It should be used for volumes not exceeding 100 L. Above this volume (or volume rate), cubic meters should be used. The only two prefixes allowed with the liter are “milli” and “micro:’
In the U.S., the “ -er” ending for meter and liter is official. The official symbol for the liter is “L.” In other countries the symbol may be written as “Y” and spelled out with the “ -re” ending (metre, litre). Since SPE is international. it is expected that members will use local conventions. Notice that “API barrel” or simply “barrel” disappears as an allowable volume term.
DERIVED UNITS WITH SPECIAL NAMES
BASE UNITS
MASS
HEAT
CONOUCTINCE
ELECTRIC
CURRENT
INDUCTANCE
SUPPLEMENTARY
OENSITV
UNITS
LUMINOUS
SOLID
FLUX
lLLUMlNANCE
ANGLE SOLID BROKEN
Fig. Xl-Graphic
LINES
INDICATE
LINES.
MULTIPLICATION.
OIVISION
relationships of SI units with names
FLOW
RATE
PETROLEUM
58-24
ENGINEERING
HANDBOOK
Force
Unit Standards Under Discussion
Any force term will use the newton (N). Derived units involving force also require the newton. The expression of force using a mass term (like the kilogram) is absolutely forbidden under these standards.
There are some quantities for which the unit standards have not been clarified to the satisfaction of all parties and some controversy remains. These primary quantities are summarized below.
Mass
Permeability
The kilogram is the base unit, but the gram, alone or with any approved prefix, is an acceptable SI unit. For large mass quantities the metric ton (t) may be used. Some call this “tonne:’ However, this spelling sometimes has been used historically to denote a regular short ton (2,000 lbm). A metric ton is also a megagram (Mg). The terms metric ton or Mg are preferred in text references.
The SPE-preferred permeability unit is the square micrometer (pm*). One darcy (the traditional unit) equals 0.986 923 pm*. The fundamental SI unit of permeability (in square meters) is defined as follows: “a permeability of one meter squared will permit a flow of I m’is of fluid of I Pa. s viscosity through an area of I m’ under a pressure gradient of 1 Pa/m.” The traditional terms of “darcy” and “millidarcy” have been approved as preferred units of permeability. Note 11 of Table 2.2 shows the relationships between traditional and SI units and points out that the units of the darcy and the square micrometer can be considered equivalent when high accuracy is not needed or implied.
Energy and Work The joule (J) is the fundamental energy unit; kilojoules (kJ) or megajoules (MJ) will be used most commonly. The calorie (large or small) is no longer an acceptable unit under these standards. The kilowatthour is acceptable for a transition period but eventually should be replaced by the megajoule. Power The term horsepower disappears as an allowable unit. The kilowatt (kW) or megawatt (MW) will be the multiples of the fundamental watt unit used most commonly. Pressure The fundamental pressure unit is the Pascal (Pa) but the kilopascal (kPa) is the most convenient unit. The bar (100 kPa) is an allowable unit. The pressure term kg/cm2 is not allowable under these standards. Viscosity The terms poise, centipoise, stokes, and centistokes are no longer used under these standards. They are replaced by the metric units shown in Table 2.2. Temperature Although it is permissible to use “C in text references, it is recommended that “K” be used in graphical and tabular summaries of data. Density The fundamental SI unit for density is kg/m3. Use of this unit is encouraged. However, a unit like kg/L is permissible. The traditional term “specific gravity” will not be used. It will be replaced by the term “relative density.” API gravity disappears as a measure of relative density. Relative Atomic Mass and Molecular Mass The traditional terms “atomic weight” and “molecular weight” are replaced in the SI system of units by “relative atomic mass” and “relative molecular mass,” respectively. See Table 1.6.
Standard Temperature Some reference temperature is necessary to show certain properties of materials, such as density. volume. viscosity. and energy level. Historically, the petroleum industry almost universally has used 60°F [15.56”C] as this reference temperature, and metric systems have used O”C, 2O”C, and 25°C most commonly, depending on the data and the area of specialty. API has opted for 15°C because it is close to 60°F. ASME has used 20°C in some of its metric guides. The bulk of continental European data used for gas and oil correlations is at O”C, although 15°C is used sometimes. The SPE Subcommittee feels that the choice between 0°C and 15°C is arbitrary. Tentatively, a standard of 15°C has been adopted simply to conform to API standards. It may be desirable to have a flexible temperature standard for various applications. Standard Pressure To date. some groups have opted for a pressure reference of 101.325 kPa, which is the equivalent of I std atm. The Subcommittee considers this an unacceptable number. Its adoption possesses some short-term convenience advantages but condemns future generations to continual odd-number conversions to reflect the change of pressure on properties. It also violates the powersof-10 aspect of the SI system, one of its primary advantages. The current SPE standard is 100 kPa and should be used until further notice. It is our hope that reason will prevail and others will adopt this standard. Gauge and Absolute Pressure There is no provision for differentiating between gauge and absolute pressure, and actions by international bodies prohibit showing the difference by an addendum to the unit symbol. The Subcommittee recommends that gauge and absolute be shown using parentheses following p: p=643
kPa,
p(g)=543
kPa
THE SI METRIC
SYSTEM
OF UNITS
& SPE METRIC
STANDARD
[p is found from p(g) by adding actual barometric pressure. (100 kPa is suitable for most engineering calculations.)] In custody transfer the standard pressure will be specified by contract. Unless there is a special reason not to do so, the standard pressure will be 100 kPa to preserve the “multiples of ten” principle of the metric system. Standard pressure normally is defined and used as an absolute pressure. So, psc = 100 kPa is proper notation. Absolute pressure is implied if no (g) is added to denote gauge pressure specifically. Standard Volumes Cubic meters at standard reference conditions must be equated to a term with the standard “SC” subscript. For example, for a gas production rate of 1 200 000 m3/d, write qx,y,=1.2x
IO6 m3/d or 1.2 (E+06) m3/d read as “1.2 million cubic meters per day.”
If the rate is 1200 cubic meters per day, write q,,Yc=1.2x103
m3/d.
For gas in place, one could write G,,=11.0x10’*
m3.
Notes for Table 2.2 1. The cubem (cubic mile) is used in the measurement of very large volumes, such as the content of a sedimentary basin. 2. In surveying, navigation, etc., angles no doubt will continue to be measured with instruments that read out in degrees, minutes, and seconds and need not be converted into radians. But for calculations involving rotational energy, radians are preferred. 3. The unit of a million years is used in geochronology. The mega-annum is the preferred SI unit, but many prefer simply to use mathematical notation (i.e., X 106). 4. This conversion factor is for an ideal gas. 5. Subsurface pressures can be measured in megapascals or as freshwater heads in meters. If the latter approach is adopted, the hydrostatic gradient becomes dimensionless. 6. Quantities listed under “Facility Throughput, Capacity” are to be used only for characterizing the size or capacity of a plant or piece of equipment. Quantities listed under “Flow Rate” are for use in design calculations. 7. This conversion factor is based on a density of 1.0 kg/dm 3 8. Seismic velocities will be expressed in km/s. 9. The interval transit time unit is used in sonic logging work.
58-25
10. See discussion of “Energy, Torque, and Bending Moment,” Part 1. 11. The permeability conversions shown in Table 2.2 are for the traditional definitions of darcy and millidarcy. In SI units, the square micrometer is the preferred unit of permeability in fluid flow through a porous medium, having the dimensions of viscosity times volume flow rate per unit area divided by pressure gradient, which simplifies to dimensions of length squared. (The fundamental SI unit is the square meter, defined by leaving out the factor of IO-‘* in the equation below). A permeability of 1 pm* will permit a flow of 1 m3/s of fluid of 1 Pa. s viscosity through an area of 1 m2 under a pressure gradient of lo’* Pa/m (neglecting gravity effects): I pm2 = lo-‘* Pa.s [m3/(s.m2)](m/Pa) = 10 ~ I2 Pa. s(m/s)(mlPa) = lo-‘* m2 The range of values in petroleum work is best served by units of 1O-3 pm2. The traditional millidarcy (md) is an informal name for 10 -3 pm*, which may be used where high accuracy is not implied. For virtually all engineering purposes, the familiar darcy and millidarcy units may be taken to be equal to 1 pm2 and 10 -3 pm*. respectively. 12. The ohm-meter is used in borehole geophysical devices. 13. As noted in Sec. 1, the mole is an amount of substance expressible in elementary entities as atoms, molecules, ions, electrons. and other particles or specified groups of such particles. Because the expression “kilogram mole” is inconsistent with other SI practices, we have used the abbreviation “kmol” to designate an amount of substance which contains as many kilograms (groups of molecules) as there are atoms in 0.0 12 kg of carbon 12 multiplied by the relative molecular mass of the substance involved. In effect, the “k” prefix is merely a convenient way to identify the type of entity and facilitate conversion from the traditional pound mole without’violating SI conventions.
Notes for Table 2.3 1. The standard cubic foot (scf) and barrel (bbl) rem ferred to are measured at 60°F and 14.696 psia; the cubic meter is measured at 15°C and 100 kPa (1 bar). 2. The kPa is the preferred SPE unit for pressure. But many are using the bar as a pressure measurement. The bar should be considered as a nonapproved name (or equivalent) for 100 kPa. 3. See discussion of “Torque and Bending Moment , ” Part I.
58-26
PETROLEUM ENGINEERING
TABLE 2.2-TABLES
OF RECOMMENDED SI UNITS Metric Unit
Customary Unit
Quantity and SI Unit
HANDBOOK
SPE Preferred
Other Allowable
Conversion Factor’ Multiply Customary Unit by Factor to Get Metric Unit
SPACE:’ TIME m
Length
naut mile
km
1.852’
E+00
mile
km
1.809 344*
E + 00
chain
m
2.011 68
E+Ol
link
m
2.011 68
E-01 E+OO
fathom
m
1.828 8’
m
m
1.O’
E+OO
yd fl
m
9.144’
E-01
cm
3.048’ 3.048’
E-01 E+nl
cm
2.54’ 2.54’
E+Ol E+OO
cm
1.O’ 1.O’
E+Ol E+00
m
in.
mm mm
cm mm mil
mm
1.O’
E+OO E+Ol E+OO
pm
2.54’
micron (f.~)
bm
1.O’
Length/length
m/m
fUm+
m/km
1.893 939
E-01
Length/volume
m/m3
fUU.S. gal
m/m3
8.051 964
E+Ol
ftw
m/m3
1.078 391
E+Ol
ft/bbl
m/m3
1.917 134
E+OO
Length/temperature
m/K
Area
m2
see “Temperature, Pressure, Vacuum” sq mile
km2
2.589 988
E +00
section
km2 ha
2.589 988 2.589 988
E +00 E+O2
ha
4.046 858 4.046 856
E+03 E-01
acre
m2
ha
m2
1.o
Ec04
sq yd
m2
8.361 274
E-01
sq fl
m2 cm2
9.290 304’ 9.290 304’
E - 02 E + 02
cm2
6.451 8’ 6.451 6’
E+O2 E+OO
cm2
1.0 1.0
Et02 Et00
sq in.
mm2
cm2
mm2
mm2
mm2
1.0
E+OO
Area/volume
m2/m3
ft?in?
m21cm3
5.699 291
E-03
Area/mass
m2/kg
cm2ig
m*/kg mYg
1.0 1.0
E-01 E-04
Volume, capacity
m3
cubem
km’
4.168 182
E+OO””
acre-ft
m3
1.233 489 1.233 489
E+03 E-01
m3
m3
1.o
E+OO
cu vd
m3
7.645 549
E - 01
bbl (42 U.S. aal)
m”
1.589 873
E-01
cu R
m3 dm3
L
2.831 685 2.831 685
E-02 E+Ol
m3 dm3
L
4.546 092 4.546 092
E-03 E+OO
m3 .-tm3
I
3.785 412
E-03
dm3
L
ham
U.K. gal U.S. gal liter
“Conversion
that the conversion
(and related quanblles)
E+OO
U.K. qt
dm3
L
1.136 523_
Finn -,-I
rim3
I
Q AR7 5X _.._-__
J
E-01
dm3
L
4.731 765
E-01
factcf IS exact using the numbers
factors for length. area. and volume
F+rul
1.0’
11s
nt
U.S. pt ‘An asterisk cdcates
37A‘iAl7
shown. all subsequent
numbers
are zeros
I” Table 2.2 are based on the intemabonal
foot See Footnote
1 of Table 1 7. Part 1
-
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
TABLE 2.2-TABLES
58-27
OF RECOMMENDED SI UNITS (continued) Metric Unit Customary Unit
Quantity and SI Unit
SPE Preferred
Other Allowable
Conversion Factor’ Multiply Customary Unit by Factor to Get Metric Unrt
SPACE,” TIME Volume, capacity
Volume/length (linear displacement)
m3
m31m
Volume/mass
m3ikg
Plane angle
rad
E+Ol
U.K. fl oz
cm3
2.841 308
U.S. fl oz
cm3
2.957 353
E+Ol
cu in.
cmJ
1.638 706
E+Ol
mL
cm3
1.O’
E+OO
bbliin.
m31m
6.259 342
Et00
bbl/H
m3/m
5.216 119
E-01
H3/H
m31m
9.290 304’
E - 02
U.S. gal/H
m31m dm31m
1.241 933 1.241 933
E-02 E+Oi
1.O’ 1.745 329
E+OO E -. 02 121
Urn
see “Density, Specific Volume, Concentration, Dosage” rad deg (“1
rad rad
min (‘)
rad
set (“)
rad
0
n
1.O’
E+OO
2.908 882 1.O’
E - 04 12’ E+OO
4.848 137 1.o
E - 06 ‘2’ E+OO E+OO
Solid angle
sr
sr
sr
1.o
Time
S
million years (MY)
Ma
1.o
E + 00 ‘W
v wk
a
1.0
E+OO
d
7.0
E+OO
d
d
1.o
E+OO
hr
h min
1.o 6.0
E+OO E+Ol
h min
6.0 1.666 667 1.O’
E+Ol E-02 E+OO
min
S
S
S
1.o
E+OO
millimicrosecond
ns
1.0
E+OO
MASS, AMOUNT OF SUBSTANCE U.K. ton (long ton)
Mass
Mg
t
1,016 047
E+OO
9.071 847
E-01
U.K. ton
Mg kg
t
5.080 235
E+Ol
U.S. cwt
kg
4.535 924
E+Ol
kg ibm
kg ka
1.o
E+OO
4.535 924
E-01
oz (troy)
9
3.110 348
E+Ol
oz (av)
9
2.834 952
E + 01
9
9
1.o
E+OO
grain
m9
6.479 891
E+Ol
m9 9
m9 9
1.o
E+OO
1.O’
E+OO
US. ton (short ton)
Mass/length
kg/m
Masslarea
kg/m2
Mass/volume
kg/m3
see “Density, Specific Volume, Concentration, Dosage”
Mass/mass
‘Wkg mol
see “Density, Specific Volume, Concentration, Dosage”
Amount of substance
see “Mechanics” see “Mechanics”
Ibm mol
kmol
4.535 924
E-01
g mol std m3 (WC, 1 atm)
kmol kmol
1.O’ 4.461 58
E-03 E - 02 II 131
std m3 (15”C, 1 atm)
kmol
4.229 32
E-
std ft3 (6O”F, 1 atm)
kmol
1.1953
E - 03 II 131
02 II 131
PETROLEUM ENGINEERING
58-28
TABLE 2.2-TABLES
HANDBOOK
OF RECOMMENDED SI UNITS (continued) Conversion Factor’ Multrply Customary Unit by Factor to Get Metric Unit
Metric Unit SPE Preferred
Customary Unit
Quantity and SI Unit
Other Allowable
CALORIFIC VALUE, HEAT, ENTROPY, HEAT CAPACITY Calorific value (mass basis)
J/kg
Btuilbm
MJikg kJ/kg
J’g
Cal/g
kJ/kg
J’g
caklbm kcalig mol
J/kg
9.224 141
E+OO
kJ/kmol
4.184’
c+o3’3
Btu/lbm mol
MJikmol kJ/kmol
2.326 2.326
E-0313 E + OOt3
therm/U.K. gal
MJlm3 kJ/m3
2.320 80 2.320 80 6.446 660
E+04 E+07 E+OO
BtuiUS. gal
MJlm3 kJ/m3
2.787 163 2.787 163 7.742 119
E-01 E+02 E-02
Btu!U.K. gal
MJlm3 kJ/m3
2.320 8 2.320 8 6.446 660
E-01 E+02 E-02
BtuifP
MJlm3 kJ/m3
3.725 895 3.725 895 1.034 971
E-02 E+Ol E-02
kcal/m3
MJlm3 kJ/m3
4.184’ 4.184’
E-03 E+OO
(kW.h)/kg
Calorific value (mole basis)
Jimol
Calorific value (volume basis solids and liquids)
J/m3
kJ/dm3 (kW.h)/dm3 kJ/dm3 (kW,h)/m3 kJ/dm3 (kW.h)/m3 kJidm3 (kW.h)/m3
Calorific value (volume basis gases)
Jim3
Specific entropy
J1kg.K
Specific heat capacity (mass basis)
J/kg.K
Molar heat capacity
Jlmo1.K
Temperature (absolute)
K
Temperature (traditional)
K
Temperature (difference)
K
Temperature/length (geothermal gradient)
K/m
Length/temperature (geothermal step)
m/K
Pressure
Pa
kJidm3
2.326 2.326 6.461 112
E-03 E+OO E-04
4.184’
E+OO
cal/mL
MJ/m3
4.184’
E+OO
ft-1bfiU.S. gal
kJ/m”
3.581 692
E-01
cal/mL
kJ/m3
J/dm3
4.184.
E+03
kcalim3
kJlm”
J/dm3
4.184’
E+OO
BtuiH3
kJ/m”
Jldm3 (kW. h)/m 3
3.725 895 1.034 971
E+Oi E-02
J/b. N J/b. K) J/h. W J4g ’K) J/h. K) J/b. to
4.186 8’
E+OO
4.184’
E+OO
4.184’
E+OO
3.6’
E+03
Btu/(lbm-“R)
kJi(kg.K)
cali(g-“K)
kJi(kg.K)
kcal!( kg%)
kJi(kg.K)
kW-hr/(kg-“C)
kJ/(kg.K)
Btu/(lbm-“F)
kJ/( kg.K)
kcal/(kg-“C)
kJ/( kg.K)
Btui(lbm mol-“F) cal!(g mol-“C)
4.186 8
E+OO
4.184’
E+OO
kJI(kmo1.K)
4.186 8’
E+00r3
kJI(kmo1.K)
4.184’
E - 0013
TEMPERATURE, PRESSURE, VACUUM “R
K
“K
K
1.O’
“F
“C
(“F - 32)/l .8
“C
“C
“F
K
“C
“C
K
“C
“F/100 ft
mWm
ft/‘F
m/K
5.486 4’
E-01
atm (760mm Hg at 0°C or 14.696 (Ibfiin.2)
MPa kPa bar
1.013 25’ 1.013 25’ 1,013 25’
E-01 E+02 E+OO
bar
MPa kPa bar
1.O’ 1.O’ 1.0
E-01 E+02 E+OO
at (technical atm., kgf:cm*)
MPa kPa bar
9.806 65’ 9.806 65’ 9.806 65’
E-02 E+Ol E-01
519 E+OO
1.O’
E+OO
5i9
E+OO
1.O’
E+OO
1.822 689
E+Ol
58-29
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
TABLE 2.2-TABLES
OF RECOMMENDED SI UNITS (continued) Metric Unit SPE Preferred
Customary Unit
Quantity and SI Unit
Other Allowable
Conversion Factor’ Multiply Customary Unit by Factor to Get Metric Unit
TEMPERATURE, PRESSURE, VACUUM Pressure
Pa
Liquid head
Pa
m
in. fig (32’F)
kPa
3.386 38
E+OO
in. Hg (60°F)
kPa
3.376 05
E+OO
in. Hz0 (39.2”F)
kPa
2.490 82
E-01
in. Hz0 (60°F)
kPa
2.408 4
E-01
mm Hg (0°C) = torr
kPa
1.333 224
E-01
cm Hz0 (4°C)
kPa
9.806 38
E-02
Ibf/A* (psf)
kPa
4.788 026
E - 02
v Hg (0°C) pbar
Pa
1.333 224
E-01
Pa
1.O’
E-01
dyne/cm2
Pa
1.O’
E-01
in. Hg (60°F)
kPa
3.376 85
E+OO
in. Hz0 (39.2-F)
kPa
2.490 82
E-01
in. Hz0 (60°F)
kPa
2.488 4
E-01
mm Hg (0°C) = torr
kPa
1.333 224
E-01
cm HZ0 (4°C) R
kPa m
9.806 38
E-02
in.
mm
psi/ft
kPa!m
2.262 059
E + 01
psi/l 00 ft
kPa/m
2.262 059
E - 01 w
1.601 846 1.601 846
E+Ol E +04
g/cm3
1.198 264 1.198264
E+02 E-01
kg/dm3
9.977 633 9.977 633
E + 01 E - 02
g/cm3
1.601 846 1.601 846
E+Ol E-02
kgidm3
1.o* 1.o
E+03 E+OO
cm Pressure drop/length
Pa/m
E - 03 E+OO E - 02
MPa kPa bar
Vacuum, draft
6.894 757 6.894 757 6.894 757
Ibflin.2 (psi)
3.048’
E-01
2.54’ 2.54’
E+Ol E+OO
DENSITY, SPECIFIC VOLUME, CONCENTRATION, DOSAGE Density (gases)
kg/m3
IbmW
Density (liquids)
kg/m3
1bmiU.S. gal Ibm/U.K. gal IbmlfP g/cm3
kg/m3 g/m3 kg/m3 kg/m3 kg/m3 kg/m3
“API
g/cm3
Density (solids)
kg/m3
IbmW
kg/m3
1.601 846
E+Ol
Specific volume
ma/kg
R3/lbm
(gases) Specific volume (liquids)
m31kg m31g
6.242 796 6.242 796
E - 02 E - 05
m%g
fWlbm
dm3/kg
6.242 796
E + 01
U.K. galilbm
dm31kg
cmYg
1.002 242
E+Ol
cm3/g
141.5!(131.5+“API)
U.S. galilbm
dm3/kg
8.345 404
E+OO
Specific volume (mole basis)
m3/mol
Ug mol
m3/kmol
1.O’
E + 00’3
m3ikmol m%
E - 0213
m31kg
fWbm mol bb1iU.S. ton
6.242 796
Specific volume (clay yield)
1.752 535
E-01
bbl/U.K. ton
m%
Yield (shale distillation)
m3/kg
bbliU.S. ton
dm%
ut
1.564 763
E-01
1.752 535
E+02
bb1iU.K. ton
dm%
Lit
1.564 763
E+02
U.S. gal/US. ton
dm311
ut
4.172 702
E+OO
Lit
3.725 627
E+OO
1.O’ 1.0’
E-02 E+Ol
U.S. ga1lU.K. ton
dm3/t
Concentration (mass/mass)
Wb
wt %
Wkg @kg
Concentration (mass/volume)
kg/m3
w mm lbmibbl
w/kg kg/m3
g/US. gal
kg/m3
gIU.K. gal
kg/m3
gidm3 9’L
1.O’
E+OO
2.853 010
E+OO
2.641 720
E-01
2.199 692
E-01
PETROLEUM ENGINEERING
58-30
TABLE 2.2-TABLES
HANDBOOK
OF RECOMMENDED SI UNITS (continued) Metric Unit SPE Preferred
Customary Unit
Quantity and SI Unit
Other Allowable
Conversion Factor’ Multiply Customary Unit by Factor to Gel Metric Unit
DENSITY, SPECIFIC VOLUME, CONCENTRATION, DOSAGE Concentration (mass/volume)
Concentration (volume/volume)
Concentration (mole/volume)
Concentration (volume/mole)
kg/m3
m31mJ
mol/m3
m3/mol
lbmilOO0 U.S. gal
g/m3
mg/dmJ
1.198 264
E+02
IbmilOOO U.K. gal
glm3
mg/dmJ
9.977 633
E + 01
grains/US. gal
gimJ
mg/dm3
1.711 806
E+Ol
grains/W
mg/m3
2.266352
E+O3
IbmilOOO bbl
g/m3
mg/dm3
2.853010
E+OO
mg1U.S. gal
g/m3
mgldm3
2.641 720
E-01
grains000 ft3
mgim3
2.266 352
E+Ol
bbllbbl
m31m3
1.O’
E+OO
ftw
m31m3
1.O’
E+OO
bbl/acreft
m31m3 ma/ham
1.288 923 1.288 923
E-04 E+OO
vol %
m3/m3
1.O’
E-02
U.K. aal/W
dm3/m3
L/m3
1.m=l4R7
F+fP
U.S. aaW
dm3/m3
Urn3
i .336 An8
F+n7
mL/U.S. aal
dm3/m3
L/m3
2.841 720
F-n1
mL/U.K. aal
dm31m3
L/m3
2.199
F-01
vol ppm
cm3im3 dm31m3
L/m3
1.O’ 1.O’
E+OO E-03 E+Ol
Is2
J.K. gal/l000 bbl
cm31m3
2.859 406
J.S. gal11000 bbl IJ.K. pti1000 bbl
cm3im3
2.380 952
E+Ol
cmYm3
3.574 253
E+OO
Ibm mo1iU.S. gal
kmollm3
1.198 264
E+02
Ibm moliU.K. gal
kmol/m3
9.977633
E+Ol
Ibm mol/fP
kmol/m3
1.601 846
E+Ol
std H3(6o”F, 1 atm)/bbl
kmol/m3
7.518 18
E-03
U.S. gall1000 std W (6O”Fi6O”F)
dm3ikmol
Ukmol
3.166 93
E+OO
bbl/million std ft3 f60”Fi60°F)
dm3/kmol
Ukmol
1.330 11
E-01
FACILITY THROUGHPUT, CAPACITY Throughput (mass basis)
Throughput (volume basis)
kg/s
m3/s
million Ibm/yr
ffa
Mg/a
4.535 924
E+02
U.K. toniyr
t/a
Mgla
1.016 047
E+OO
US. toniyr
t/a
Mgla
9.071 847
E-01
U.K. ton/D
Vd
Mgid t/h, Mgih
1.016047 4.233 529
E+OO E-02
U.S. ton/D
t/d tih, Mg/h
9.071 847 3.779 936
E-01 E - 02 E+OO
U.K tonlhr U.S. tonlhr
t/h
Mg/h
1.016 047
t/h
Mglh
9.071 a47
E-01
lbmlhr
kg/h
4.535 924
E-01
bbl/D
t/a
5.603 036 1.589 a73 6.624 471
E+Ol E-01 E-03
1.179 869 2.831 685
E-03 E-02 E-01
maid m3/h W/D
m3/h m31d
bbllhr
mJ/h
I.589 a73
113/h
m31h
2.831 685
E-02
U.K. gallhr
m3/h L/s
4.546 092 1.262 803
E-03 E-03
U.S. gallhr
m31h US
3.785 412 1.051 503
E-03 E-03
US
2.727 655 7.576 819
E-01 E-02
US
2.271 247 6.309 020
E-01 E ~ 02
U.K. gal/min U.S. galimin
m31h m3/h
“I
THE SI METRIC
SYSTEM
OF UNITS
TABLE
& SPE METRIC
2.2-TABLES
STANDARD
OF RECOMMENDED
SI UNITS
(continued) Metric Unit
Customary Unit
Quantity and SI Unit
SPE Preferred
Other Allowable
Conversion Factor” Multiply Customary Unit by Factor to Get Metric Unit
FACILITY THROUGHPUT, CAPACITY Throughput (mole bass)
molis
Ibm mol!hr
kmolih kmolis
4.535 924 1.259 979
FLOW RATE
E - 01 E-04 16,
Pipeline capacity
m31m
bblimile
mVkm
9.879 013
E-02
Flow rate (mass basis)
kg/s
U.K. tonimin
kg/s
1.693412
E+Ol
Flow rate (volume basis)
m%
U.S tonimin
kg/s
1.511 974
E+Ol
U.K. tonihr
kg/s
2.822 353
E-01 E-01
U.S. tonihr
kg/s
2.519 958
U.K. ton/D
kg/s
1.175980
E-02
U.S ton/D
kg/s
1.049 982
E-02
million lbmiyr
kg/s
5.249 912
E+OO
U.K. ton/yr
kg/s
3.221 864
E-05
US toniyr
kg/s
2.876 664
E-05
lbmls
kg/s
4.535 924
E-01
lbmlmin
kg/s
7.559 873
E-03
Ibm/hr
kg/s
1.259 979
E-04
bbl/D
m3id US
1.589 873 1.840 131
E-01 E-03
US
2.831 685 3.277 413
E-02 E-04
US
4.416 314 4.416 314
E-05 E-02
US
7.865 791 7.865 791
E-06 E-03
ftVD bbl/hr RVhr
Flow rate
mol/s
(mole basis) Flow rate/length (mass basis)
kgism
Flow rate/length
m2is
(volume basis)
Flow rate/area (mass basis)
kg/sm*
Flow rate/area (volume basis)
m/s
Flow rate/ pressure drop (productivity index)
mYsPa
m’ld mJls m%
U.K. galihr
dmVs
US
1.262 803
E-03
U.S. galihr
dm%
US
1.051 503
E-03
U.K. gal/min
dmVs
US
7.576 820
E-02
U.S. galimin
dmVs
US
6.309 020
E - 02
ftVmin
dm3!s
US
4.719 474
E-01
ftVS
dm%
US
2.831 685
E+Ol
Ibm molis
kmolis
4.535 924
E-01=
Ibm mol/hr
kmolis
1.259 979
E - 04’5
million scWD
kmolis
1.363 449
E - 02’3
Ibmi(s-ft)
kg/(sm)
1.488 164
E+OO
Ibm/(hr-ft)
kg/(sm)
4.133 789
E-04
U.K. gal!(min-ft)
m%
mV(sm)
2.485 833
E - 04
U.S. gal!(min-ft)
m2is
mV(sm)
2.069 888
E - 04
U.K. gali(hr-in.)
m2/s
mV(sm)
4.971 667
E-05
US. gali(hr-in.)
mVs
mV(sm)
4.139 776
E-05
U.K. gali(hr-ft)
m*/s
mV(sm)
4.143055
E-06
US. gali(hr-ft)
m’ls
m3/(sm)
3.449 814
E-06
lbm/(s-ft’)
kg/sm2
4.882 428
E+OO
lbmi(hr-ft2)
kg/sm2
1.356 230
E-03
W(S4t~)
mis
m’(sm*)
3.048
E-01
Wlmin-ftz)
m/s
mV(sm*)
5.08’
E-03
U.K. gaV(hr-tn2)
m/s
mV(sm*)
1.957 349
E-03
U.S. gal!(hr-rn2)
m/s
m3/(smz)
1.629 833
E-03
U.K. gal!(mm-ft’)
mls
m’/(sm*)
8.155 621
E-04
US. gal!(mmW)
mis
mV(sm*)
6.790 972
E - 04
U.K. gali(hr-ft’)
mls
mV(sm*)
1.359 270
E-05
U.S. gal!(hr#)
m/s
m31(sm2)
1.131 829
E-05
bbli(D-psr)
mV(d.kPa)
2.305 916
E-02
PETROLEUM ENGINEERING
58-32
TABLE 2.2-TABLES
HANDBOOK
OF RECOMMENDED SI UNITS (continued) Metric Unit SPE Preferred
Customary Unit
Quantity and SI Unit
Other Allowable
Conversion Factor* Multiply Customary Unit by Factor to Get Metric Unit
ENERGY, WORK, POWER Energy, work
J
therm
MJ kJ kW.h
1.055 1.055 1.055 2.930 2.930 2.930 1.055 1.055 2.930
U.S. tonf-mile
MJ
1.431 744
E+Ol
hp-hr
MJ kJ kW.h
2.684 520 2.684 520 7.456 999
E+OO E+03 E-01
ch-hr or CV-hr
MJ N kW.h
2.647 796 2.647 796 7.354 99
Et00 E+03 E-01
kW-hr
MJ kJ
3.6’ 3.6’
E+OO E+03
Chu
kJ kW.h
1.899 101 5.275 280
E+OO E-04
kW.h
1.055 056 2.930 711
E+OO E-04
quad
MJ TJ EJ MW*h GW.h TWh
f3tu
Impact energy
J
kJ
056 056 056 711 711 711 056 056 711
E+12 Et06 E+OO Et08 Et05 Et02 E+02 E+05 E+Ol
kcal
kJ
4.184’
E+OO
cal
kJ
4.184’
E-03
ft-lbf
kJ
1.355 818
E-03
Ibf-ft
kJ
1.355 818
E-03
J
kJ
1.O’
E-03
Ibf-ftz/s2
kJ
4.214 011
E-05
erg kgf-m
J
1.O’
E-07
J
9.806 650’
E + 00
Ibf-ft
J
1.355818
E+OO
WorWlength
Jim
U.S. tonf-mileift
MJlm
4.697 322
Et01
Surface energy
J/m2
erg/cm2
mJlmZ
1.O’
E+OO
Specific impact energy
J/m2
kgf.m/cm*
J/cm’
9.806 650’
E - 00
Ibf+t/in.*
J/cm2
2.101 522
E-01
Power
W
quadiyr
MJia TJia EJia TW GW
1.055 056 1.055 056 1.055 056 3.170 979 3.170979
E+12 Et06 E+OO E-27 E-24
erg/a
Power/area
W/m2
million Btu/hr
MW
2.930 711
E-01
ton of refrigeration
kW
3.516 853
E+OO
ml/s
kW
1.055 056
E+OO
kW
kW
1 .O’
E+OO
hydraulic horsepower - hhp
kW
7.460 43
E-01
hp (electric)
kW
7.46’
E-01
hp (550 ft-lbfis)
kW
7.456 999
E-01
ch or CV
kW
7.354 99
E-01
Btuimin
kW
1.758 427
E-02
ft*lbf/s
kW
1.355 818
E-03
kcalihr
W
1.162222
E+OO
Btuihr
W
2.930 711
E-01
Albfimin
W
2.259 697
E-02
Btuis.ft?
kWlmz
1.135653
E+Ol
cal/hrcm?
kWlm2
1.162222
E-02
Btuihrft?
kW/m2 .-
3.154 591
E-03
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
TABLE 2.2-TABLES
58-33
OF RECOMMENDED SI UNITS (continued) Metric Unit Customary Unit
Quantity and SI Unit
SPE Preferred
Other Allowable
Conversion Factor’ Multiply Customary Unit by Factor to Get Metric Unit
ENERGY, WORK, POWER Heat flow unit (geothermics)
~calls’cm2
hfu
Heat release rate, mixing power
W/m3
Heat generation unit - hgu (radioactive rocks)
mWlm2
4.184’
E+Ol
hpift3
kWlm3
2.633 414
E+Ol
cal/(hpcm3)
kW/m3
1.162 222
E+OO
Btu/(sft3)
kW/m3
3.725 895
E+Ol
Btui(hrW)
kWlm3
1.034 971
E-02
cal/(s-cm3)
pWlm3
4.184’
E+12
3.930 148
E-01
Cooling duty (machinery)
WAN
Btu/(bhp-hr)
W/kW
Specific fuel consumption (mass basis)
kg/J
Ibm/(hp-hr)
mg/J
kg/MJ kg/(kW-h)
1.689 659 6.082 774
E-01 E-01
Specific fuel consumption (volume basis)
m3/J
mJ/(kW-hr)
dm31MJ
mm3/J dm?(kW.h)
2.777 778 1.0
E + 02 E+03
U.S. gal/(hp-hr)
dm3/MJ
mm3/J
1.410089
E+OO
Velocity (linear), speed
m/s
MECHANICS knot
km/h
1.852
E+OO
mileihr
km/h
1.609 344’
E + 00
m/s
m/s
1.O’
E+OO
fUS
m/s cm/s mfms
3.048’ 3.048’ 3.048’
E-01 E+Ol E - 04@’
cm/s
5.08’ 5.08’
E-03 E-01
cm/s
8.466 667 8.466 667
E-02 E - 03
m/d
3.527 778 3.048’
E - 03 E-01
cm/s
2.54’ 2.54
E+Ol E+OO
cmls
4.233 333 4.233 333
E-01 E ~ 02
1.047 198 6.283 185 2.908 882
E-01 Et00 E-04
ftlmin ftihr ft/D in.& in./min
m/s mm/s mm/s mm/s mm/s
Velocity (angular)
radls
revlmin rev/s degree/min
radls rad/s radls
Interval transit time
s/m
S/ft
s/m
Corrosion rate
m/s
in./yr (ipy) miliyr
mmla mmla
Rotational frequency
rev/s
rev/s
rev/s
1.O’
E+OO
revimin
rev/s
1.666 667
E-02
Acceleration (linear)
m/s*
Acceleration (rotational)
rad/s2
Momentum
kg.m/s
KS/m
3.280 840
E + OO@
2.54’ 2.54’
E+Ol E-02
revimin
radls
1.047 198
E-01
ftk*
m/s2
3.048’ 3.048’
E-01 E+Ol
cm/s2 gal(cm@)
mls2
1.O’
E-02
radls2
rad/s2
1.O’
E+OO
rpmis
lad/s2
1.047 198
E-01
Ibm.ftJs
kg.m/s
1.382 550
E-01
PETROLEUM ENGINEERING
58-34
TABLE 2.2-TABLES
HANDBOOK
OF RECOMMENDED SI UNITS (continued) Metric Unit Customary Unit
Quantity and SI Unit
SPE Preferred
Other Allowable
Conversion Factor’ Multiply Customary Unit by Factor to Get Metric Unit
MECHANICS
Bending moment, torque
N.m
Bending moment/ length
N.m/m
Elastic moduli (Young’s, Shear bulk)
Pa
LI S. tonf
kN
8.896 443
E+OO
kgf (kp)
N
9.806650’
Et00
Ihf
N
4.448 222
E+OO
N
N
1.O’
E+OO
ndl
mN
1.382 550
E+02
dyne
mN
1.o
E-02 E + OO”O’
US. tonf-ft
kN.m
2.711 636
kgf-m
N.m
9.806 650’
E + 00”01
Ibf-ft
N.m
1.355 818
Ibf-in.
N-m
1.129848
E + OO”o E - ,,,“O’
odl-ft
N.m
4.214011
E- 021’0’
(Ibf-ft)/in.
(N.m)/m
5.337 866
E + Ol”O1
(kgf-m)/m
(N.m)/m
9.806 650’
E + OO”O1
(Ibf-in.)/in.
(N.m)/m
4.448 222
E + OO”O’
Ibf!in.’
GPa
6.894 757
E-06 E-02
Moment of inertia
kqm*
Ibm-ft2
kg.m2
4.214 011
Moment of section
m4
in.4
cm*
4.162 314
E+Ol
Section modulus
m3
cu in. cu fi
cm3 cm3
1.638 1.638 2.831 2.831
E+Ol E+04 E+04 E-02
mm3 m3 Stress
Pa
Mass/area structural loading, bearing capacity (mass basis)
U.S. tonf/in.2
MPa
N/mm2
1.378 951
E+Ol
kgWmm2
MPa
N/mm2
9.806 650’
E + 00
US. tonf/ft2
MPa
N/mm2
9.576 052
E - 02
IbWin.?(osi)
MPa
N/mm2
6.894 757
E-03
Ibf/ft2 (psf)
kPa
4.788 026
E-02
dyne/cm2
Pa
1.O’
E-01
Ibf/lOO ft2
Pa
4.788 026
E-01
kg/m
Ibm/ft
kg/m
1.488 164
E+OO
kg/m2
U.S. ton/ft2
Mgim2
9.764 855
E+OO
Ibm/ft2
kg/m2
4.882 428
E+OO
mm/(mm.K)
5.555 556
E-01
Yield point, gel strength Ldrillina fluid) Mass/length
706 706 685 685
Coefficient of thermal expansion
m/(m.K)
In./(in.-“F)
Diffusivity
m21s
fV/S
mm2/s
9.290 304’
E + 04
cm2’s
mm21s
1.O’
E+02
ft2/hr
mm2/s
2.580 64’
E+Ol
(“C-m2.hr)/kcal
(K.m2)/kW
8.604 208
E +02
TRANSPORT PROPERTIES
Thermal resistance
(k.m*)/W
(“F-ft2 hr)iBtu
(K.m2VkW
1.761 102
E+O2
Heat flux
Wlm2
Btu/(hr-R*)
kW/mz
3.154 591
E-03
Thermal conductivity
W/(m.K)
(Cal/s-cm2-%)/cm
W/(m.K)
4.184*
E+02
Btu/(hr-ft-“Fift)
W/(m.K)
1.730 735 6.230 646
E+OO E+OO
kcali(hr-mz-“Cim)
W/(m.K)
1.162 222
E+OO
Btu/(hr-R2-“Fiin.)
W/(m.K)
1.442 279
E-01
cal/(hr-cm’-“C/cm)
W/(m.K)
1.162222
E-01
kJ.m/(h.m2.K)
-
58-35
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
TABLE 2.2-TABLES
OF RECOMMENDED SI UNITS (continued) Metric Unit Customary Unit
Quantity and SI Unit
SPE Preferred
Other Allowable
Conversion Factor’ Multiolv Customarv Unii dy Factor to’ Get Metric Unit
TRANSPORT PROPERTIES Heat transfer coefficient
W/(m2.K)
cal/(s-cm?-“C)
4.184’
E+Ol
Btu/(s-ft2-“F)
2.044 175
E +Ol
cal/(hr-cm2-“C)
1.162 222
E-02
5.678 263 2.044 175
E - 03 E+Ol E-03
Btu/(hr-ft2-“F)
kWi(m2.K) kJ/(h.m>.K)
Btu/(hr-f&OR)
kW/(m*.K)
5.678 263
kcal/(hr-m2-“C)
kWi(m*.K)
1.162222
E-03
6.706 611
E+Ol
Volumetric heat transfer coefficient
W/(m3.K)
Btui(s-ft3-“F)
kW/(m3.K)
Btu/(hr-f13-“F)
kW/(m3.K)
1.862 947
E-02
Surface tension
N/m
dyne/cm
mN/m
1.O’
E+OO
Viscosity
P&S
(Ibf-s)iin.2
Pas
(Ns)im2
6.894 757
E + 03
(Ibf-s)ift2
Pas
(N.s)/m’
4.788 026
E+Ol
(kgf-s)/m*
Pas
(Ns)/m2
9.806 650’
E + 00
Ibm/(ft-s)
Pas
(Ns)/m*
1.488 164
E+OO
(dyne-@/cm2
Pas
(Ns):m2
1.O’
E-01
cP Ibm/(ft.hr)
Pa.s
(Ns)/m*
1.O’
E-03
Pas
(N+m2
4.133 789
E-04
(dynamic)
Viscosity
m21s
(kinematic)
Permeability
m2
ft%
mm%
9.290 304’
E + 04
in.*/s
mm%
6.451 6
E+02 E+O2
m2/hr
mm2is
2.777 778
cm21s
mm2/s
1.o
E+02
ft*/hr
mm2is
2.580 64’
E+Ol
cst
mm%
1.O’
darcy
km2 km2
9.869 233
E+OO E -01’“’
9.869 233 9.869 233
E - 04’“’ E-O,‘“,
millidarcy
10m3pm2 ELECTRICITY, MAGNETISM Admittance
S
S
S
1.O’
E+OO
Capacitance
F
E+OO
C
)LF kC
1.O’
Capacity, storage battery
CLF A-hr
3.6’
E+OO
Charge density
C/m3
C/mm3
C/mm3
1.O’
E+OO
Conductance
S
S
S
1.O’
E+OO
U (mho)
S
1.O’
E+OO
Conductivity
S/m
S/m
S/m
1.O’
E+OO
u/m
S/m
1.O’
E+OO
mu/m
mS/m
1.o
E+OO
Current density
A/m2
Almm’
A/mm2
1.O’
E+OO
Displacement
C/m2
C/cm2
C/cm?
1.o
E+OO
Electric charge
C
C
C
1.O’
E+OO
Electric current
A
A
A
1.o
E+OO
Electric dipole moment
C*m
C.m
C.m
1.o
E+OO
Electric field strength
V/m
Vim
V/m
1.O’
E+OO
Electric flux
C
C
C
1.O’
E+OO
Electric polarization
C/m2
C/cm2
C/cm2
1.O’
E+OO
Electric potential
V
V
V
1.O’
E+OO
mV
mV
1.O’
E+OO
A.m2
A.m2
1.O’
E+OO
Electromagnetic moment
A.m2
Electromolive force
V
V
V
1.O’
E+OO
Flux of displacement
C
C
C
1.O’
E+OO
PETROLEUM ENGINEERING
58-36
TABLE 2.2-TABLES
HANDBOOK
OF RECOMMENDED SI UNITS (continued) Conversion Factor’ Multiply Customary Unit by Factor to Get Metric Unit
Metric Unit Customary Unit
Quantity and SI Unit
SPE Preferred
Other Allowable
ELECTRICITY, MAGNETISM Frequency
HZ
cycles/s
HZ
1.O’
E+OO
Impedance
n
n
n
1.O’
E+OO
Interval transit time
slm
@ft
t&m
3.280 840
E+OO
Linear current densitv
Aim
A/mm
Aimm
1.O’
E+OO
Magnetic dipole moment
Wbsm
Wb.m
Wbm
1.o
E+OO
Magnetic field strength
A/m
A/mm
Aimm
1.O’
E+OO
oersted
Aim
7.957 747
E+Ol
gamma
Aim
7.957 747
E-04
Magnetic flux
Wb
mWb
mWb
1.O’
E+OO
Magnetic flux density
T
Magnetic induction
mT
mT
1.O’
E+OO
gauss
T
1.o*
E-04
T
mT
mT
1.O’
E+OO
Magnetic moment
A*mZ
A-m2
A.m2
1.o*
E+OO
Magnetic oolarization
T
mT
mT
1.O’
E+OO
Magnetic potential difference
A
A
A
1.O’
E+OO
Magnetic vector potential
Wb/m
Wbimm
Wblmm
1
Magnetization
Aim
A/mm
A/mm
1
Modulus of admittance
S
S
S
1
Modulus of impedance
R
n
n
1
Mutual inductance
H
H
H
1
Permeability
H/m
pH/m
PHim
1
Permeance
H
H
H
1
Permittivity
F/m
WFlm
kF/m
1
Potential difference
V
V
V
1
Quantity of electricitv
C
C
C
1
Reactance
n
cl
n
1
Reluctance
H-’
H-1
H-’
1
Resistance
n
R
R
1
Resistivity
Darn
1
@cm
fkm
Dm
Drn
1
Self inductance
H
mH
mH
1
Surface density of charge
C/m*
mClm*
mClmz
1
Susceptance
S
S
S
1
Volume density of charae
C/m3
C/mm3
C/mm3
1
W,
ACOUSTICS, LIGHT, RADIATION Absorbed dose
rad
1.o
E-02
Acoustical enerav
GY J
J
GY J
Acoustical intensity
Wfm2
W/cm2
Wlm*
1.o
Acoustical Dower
W
W
W
1
Sound oressure
N/m*
Nim2
N/m2
1
llluminance
lx
footcandle
lx
1.076 391
E+Ol
Illumination
lx
footcandle
lx
1.076 391
E+Ol
lrradiance
Wlm*
W/m2
Wlm*
1
Light exposure
1x3
footcandles
1x.s
1.076 391
Luminance
cd/m*
cd/m2
cd/m2
1
Luminous efficacv
ImiW
ImiW
ImiW
1
1 E+O4
E + 01
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
TABLE 2.2-TABLES
58-37
OF RECOMMENDED SI UNITS (continued) Conversion Factor’ Multiply Customary Unit by Factor to Get Metric Unit
Metric Unit SPE Preferred
Customary Unrt
Quantity and SI Unit
Other Allowable
ACOUSTICS, LIGHT, RADIATION Luminous exitance
Im/mz
lmim2
lm/mZ
Luminous flux
Im
Im
Im
1
Luminous intensity
cd
cd
cd
1
Quantity of light
I’m.s
1.O’
W/(m%r)
talbot Wl(m%r)
t’m.s
Radiance
W/(m%r)
1
Radiant energy
J
J
J
1
Radiant flux
W
W
W
1
Radiant intensity
Wisr
Wlsr
W/sr
1
Radiant power
W
W
1
nm
1.O’
E-01
m-1
1.O’ 1
Et01
3.7’
E+lO
Wave length
m
r
Capture unit
mm’
lo-km
1
1
10.“cm-’ Radioactivity
curie
E+OO -
PETROLEUM ENGINEERING
58-38
TABLE 2.3~SOME
ADDITIONAL APPLICATION STANDARDS Metric Unit Customary Unit
Quantity and SI Unit Pa Capillary pressure Pa-’
Compressibility of reservoir fluid
HANDBOOK
ft (fluid)
SPE Preferred m (fluid)
psi-’
Pa-’
Other Allowable
kPa ’
Conversion Factor’ Multiply Customary Unit by Factor to Get Metric Unit 3.048' E-01 1.450 377 1.450 377
E-04 E-01
Corrosion allowance
m
in.
mm
2.54'
E+Ol
Corrosion rate
mls
mm/a
2.54'
E-02
Differential orifice pressure
Pa
miliyr hw) in. f-l,0 (at 60°F)
2.488 4 2.54'
Gas-oil ratio
m3/m’
scfibbl
“standard” m3/m3
1.801 175
E-01 E+OO E -0,“‘”
Gas rate
mYs
sci/D
“standard” m31d
2.863 640
E-02"'
Geologic time
S
Head (fluid mechanics)
m
Yr fl
cm
3.048' 3.048'
E-01 E+Ol
kJ/h
2.930 711 1.055 056
E-04 E+OO
km21Pa.s
9.869 233 9.669233
E-01 E+02 E-01
Heat exchange rate
W
cm Hz0
Ma m
Btu/hr
m?Pas
Mobility
kPa
kW
dicp
~m*/mPas
Net pay thickness
m
fl
m
3.048
Oil rate
m3ls
bbl/D
m31d
1.589 873
E-01
short toniyr
Mgla
Va
9.071 847
E-01
pm2.rn
3.008 142
E-04
mm
2.54 2.54'
E-c00 E+Oi
Particle size
m
micron
Permeability-thickness
m3
md-ft
w md.m
Pipe diameter (actual)
m
in.
cm
Pressure buildup per cycle
Pa
psi
kPa
6.894 757
E + OO’*’
Productivity index
m3iPes
bbli(psi-D)
mY(kPad)
2.305 916
E - 0212’
Pumping rate
m%
U.S. galimin
m3/h US
2.271 247 6.309 020
E-01 E-02
radlm
1.047 198 6.283 185
E-01 E+OO
mYha*m
1.286 931 1.288 931
E-04 E+OO
Revolutions per minute
radls
Recovery/unit volume (oil)
m31m3
Reservoir area
m2
rad/s
vm bbl/(acre-ft)
m3/m3 km*
sq mile acre
m3
Reservoir volume
1.0’
acre-ft
2.589 988
E+OO
ha
4.046856
E-01
hem
1.233 482 1.233 482
E+03 E-01
m3
Specific productivity index
m3/Pasm
bbl/(D-psi-R)
mY(kPa-d.m)
7.565 341
E - 02’>’
Surface or interfacial tension in reservoir caoillaries
N/m
dyne/cm
mN/m
1.O’
E+OO
Torque
N.m
Ibf-ft
Nom
1.355 818
E + 0013’
Velocity (fluid flow)
m/s
ws
m/s
3.048'
E-01
Vessel diameter l-100 cm
m in.
cm
2.54'
E+OO
ft
m
3.048'
E-01
above 100 cm ‘An asterisk mdlcates “See
Notes
1 through
the cowersum
lactor IS exact wng
3 on page 58-E
the numbers
shown, all subsequent
numbers
are zeros
THE SI METRIC SYSTEM OF UNITS & SPE METRIC STANDARD
TABLE 2.4-FAHRENHEIT
- 459.67 to - 19
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Chapter 59
SPE Letter and Computer Symbols Standard for Economics, Well Logging and Formation Evaluation, Natural Gas Engineering, and Petroleum Reservoir Engineering Prepared by the Symbols Committee of the Society of Petroleum Engineers
Contents Symbols in Alphabetical Order..
.59-Z
Quantities in Alphabetical
.59-18
Order ..............................................
Subscript Definitions in Alphabetical Subscript Symbols in Alphabetical
Order. ....................................... Order
.59-52 .59-63
PETROLEUM ENGINEERING
59-2
HANDBOOK
Symbols in Alphabetical Order
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
Quantity
Dimensions
-
English
A A A A A
a a a
ARA HWF AMP AWT ARA AMPC AMPR AMPS ACT AIR DEC DLW
aE
AIREX
aR
AIRR
B
COR
B
FVF
4 A, 4 a
Fg Fgb Fgb
FVFG
FO F ob F ob
FVFO FVFOB FVFOB
4
F,
&
FW
FVFT FVFW
b
W
WTH
FVFGB FVFGB
b b
ICP RVF
b
WTH RVFG RVFGB RVFO
c Dimensions: L=length.
ECQ m=mass,
q=electrical
area Helmholtz function (work function) amplitude atomic weight cross section (area) amplitude, compressional wave amplitude, relative amplitude, shear wave activity air requirement decline factor, nominal distance between like wells (injection or production) in a row air requirement, unit, in laboratory experimental run, volumes of air per unit mass of pack air requirement, unit, in reservoir, volumes of air per unit bulk volume of reservoir rock correction term or correction factor (either additive or multiplicative) formation volume factor, volume at reservoir conditions divided by volume at standard conditions formation volume factor, gas bubblepoint formation volume factor, gas formation volume factor at bubblepoint conditions, gas formation volume factor, oil bubblepoint formation volume factor, oil formation volume factor at bubble point conditions, oil formation volume factor, total (two-phase) formation volume factor, water breadth, width, or (primarily in fracturing) thickness intercept reciprocal formation volume factor, volume at standard conditions divided by volume at reservoir conditions (shrinkage factor) width, breadth, or (primarily in fracturing) thickness reciprocal gas formation volume factor reciprocal gas formation volume factor at bubblepoint conditions reciprocal oil formation volume factor (shrinkage factor) capacitance
charge, t =tirne. T=temperature,
and M=money.
L2 mL2/ t2 various m L2 various various various various L L3/m
L various
L
q2t2/mL2
59-3
WE LETTER AND COMPUTER SYMBOLS STANDARD
Letter Symbol
C c C c C C C c
Reserve SPE Letter Symbol
G k c,n u K c, n C
C 5
cc1
CL
cL,nL
CL
C
G p
02
co2
I
ck G c uk
Cw C Cf
C Wg’hg
k,K kfJ Kf kg* Kg ko>Ko kPr’% k w> Kw
Computer Letter Symbol INVT CGW NMBC CNC ECN CND CNC HSP WDC CNCCl
CNTL WDCL CNC02
ECNA CNOFD INVI INVK CNCFU INVUK CNTWG CMP CMPF
DC 4
CMPG CMPO CMPPRD CMPW DLV DPH DFN DSC oscc DSCSP
D SPC
DSCSPC
5 co CPT CW
D D D D
d d d 4 dh a: E E
YA CL,6
D Ld,L2
4 dH& dl,Di we
V
DECE DIA DUW DIAAVP OIAH OlAl EFF EMF
-
Quantity
capital investments, summation of all coefficient of gas-well backpressure curve components, number of concentration conductivity (electrical logging) conductivity, other than electrical (with subscripts) salinity specific heat (always with phase or system subscripts) water-drive constant concentration, methane (concentration of other paraffin hydrocarbons would be indicated similarly, Cc,, Cc3, etc.)
Dimensions
M ~3-2n
t4n/m2n
various tq2/mL3 various various L2/ t2T L4t2/m various
content, condensate or natural gas liquids water-drive constant, linear aquifer concentration, oxygen (concentration of other elements or compounds would be indicated similarly, Cco2, CN2, etc.)
various L4t2/m various
conductivity, apparent conductivity, fracture, dimensionless capital investment, initial capital investment, subsequent, in year k fuel concentration, unit (see symbol m) unamortized investment over year k content, wet-gas compressibility compressibility, formation or rock compressibility, gas compressibility, oil compressibility, pseudo reduced compressibility, water deliverability (gas well) depth diffusion coefficient discount factor, general discount factor, constant-income discount factor, single-payment [l/(l+i)k; ore-jk, j=ln(l+i)l discount factor, single-payment (constant annual rate) [e-jk(ej - 1)/j] decline factor, effective diameter distance between adjacent rows of injection and production wells diameter, mean particle diameter, hole diameter, invaded zone (electrically equivalent) efficiency electromotive force
tq2/mL3 M M various various Lt2/m Lt2/m Lt2/m Lt2/m Lt2/m L3/t L L2/t
L L L L L mL2/t2q
PETROLEUM ENGINEERING
59-4
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
E E
u Y
EA
?AFeA
ENG ELMY EFFA
ED
?lDJeD
EFFO
Em
EFFOB
ED,
EFFDU
El
EFFI
cl EP
wep
EFFP
ER
7)RpeR
EFFR
E SP
QSP
ESSP
QSSP
EMFSP EMFSSP
EV
qv,ev
EFFV
Quantity
energy modulus of elasticity (Young’s modulus) efficiency, area1 (used in describing results of model studies only): area swept in a model divided by total model reservoir area (see Ep) efficiency, displacement: volume of hydrocarbons (oil or gas) displaced from individual pores or small groups of pores divided by the volume of hydrocarbon in the same pores just prior to
HANDBOOK
Dimensions
mL*/ t* n-l/L+
efficiency, displacement, from burned portion of in-situ combustion pattern efficiency, displacement, from unburned portion of in-situ combustion pattern efficiency, invasion (vertical) : hydrocarbon pore space invaded (affected, contacted) by the injection fluid or heat front divided by the hydrocarbon pore space enclosed in all layers behind the injected fluid or heat front Euler’s number efficiency, pattern sweep (developed from area1 efficiency by proper weighting for variations in net pay thickness, porosity, and hydrocarbon saturation): hydrocarbon pore space enclosed behind the injected fluid or heat front divided by total hydrocarbon pore space of the reservoir or project efficiency, overall reservoir recovery: volume of hydrocarbons recovered divided by volume of hydrocarbons in place at start of project (ER=EpEfED=EvED)
-Ei (-x )
SP (measured SP) (Self Potential) SSP (static SP) efficiency, volumetric: product of pattern sweep and invasion efficiencies efficiency, volumetric, for burned portion only, in-situ combustion pattern electrochemical component of the SP electrokinetic component of the SP kinetic energy pseudo-SP m e-’ exponential integral, sx 7 dt, x positive
Ei (x)
exponential integral, modified
Em
EFFVB
EC Ek Ek
EMFC EMFK ENGK
EPSP
EMFP
e e%
ZO,
ENC UTLOZ
x positive EzO[J$dt+qfdt], -ca encroachment or influx rate oxygen utilization
mL2/ t2q mL2/t2q
mL2/t2q mL2/t2q mL2/ t2 mL2/qt2
L3/t
59-5
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Letter Symbol
Reserve SPE Letter Symbol
eE
‘E
e.
lo
e, ez
exp z
b
F F F F F
f Q
FACB FACHR
FR
F llF F,
Fd
WGTS FACAFU OMRS
F
FACWO FACWOP FRC
Y
F WF F WD p/J
FACWFU
FON FACF FUG FIGSH
V
fL fL
&nfshd
FIMSHD
4Krw
FIGW
r;,,ff
script 1 FRCL
FL,fpscript 1 MFRTL PRAPK
fPk
fv P i
ENCG ENCO ENCW EXP OGF FAC FLU FCE FAC
FB
Fwv
Computer Letter Symbol
f Vbt 4 4
0~
vhf
FRCVB FRCG MFRTV
G G G
g g
OLTS GFE GASTI GAS
G
fG
GMF
G
4
ELMS
F
Quantity
encroachment or influx rate, gas encroachment or influx rate, oil encroachment or influx rate, water exponential function degrees of freedom factor in general, including ratios (always with identifying subscripts) fluid (generalized) force, mechanical ratio or factor in general (always with identifying subscripts) factor, turbulence formation resistivity factor-equals R ,,/R, (a numerical subscript to F indicates the value R,) specific weight air/fuel ratio damage ratio or condition ratio (conditions relative to formation conditions unaffected by well operations) water/fuel ratio water/oil ratio, producing, instantaneous water/oil ratio, cumulative fraction (such as the fraction of a flow stream consisting of a particular phase) frequency friction factor fugacity fraction of intergranular space (“porosity”) occupied by all shales fraction of intermatrix space (“porosity”) occupied by nonstructural dispersed shale fraction of intergranular space (“porosity”) occupied by water fraction liquid mole fraction liquid, LI(L+ v) profit, annual, over year k, fraction of unamortized investment fraction of bulk (total) volume fraction gas mole fraction gas, V/(L+ V, quality (usually of steam) free energy (Gibbs function) gas in place in reservoir, total initial gas(any gas, including air) always with identifying subscripts geometrical factor (multiplier) (electrical logging) shear modulus
Dimensions
L3/t L3/t L%
various various mL/ t2 various
mL2/ t2 various
various
l/t rn/Lt2
mLZ/ t2 L3 various
m/L?
PETROLEUM ENGINEERING
59-6
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
GL
SF, gL
G LP Gon
fGon
GASFI GASFP NGLTI NGLP GMFAN
G an
fG,n
GMFAN
GFi GFP
G Gi G
GPE
gF;
gLP
fc,
GASE GASI GMFI
fGm
GMFM
gP
GASP
f&
GMFP
& gi
GASPEX
Gpa
&E gP
Gt
fGt
GASPUL GMFT
G WP Gx0
h-P f Gxo
GASWGP GMFXO
g g
Y
gG
g&T
gT
gh
g,
GRV GRD GRDGT GRDT GRVC
I 4
HEN HENS
d,e
THK HENS HTCC ZHT HPC
hnhr d.e
Quantity
-
free-gas volume, initial reservoir (=miW,;) free gas produced, cumulative condensate liquids in place in reservoir, initial condensate liquids produced, cumulative factor, geometrical (multiplier), annulus (electrical logging) geometrical factor (multiplier), annulus (electrical logging) gas influx (encroachment), cumulative gas injected, cumulative geometrical factor (multiplier), invaded zoned (electrical logging) geometrical factor (multiplier), mud (electrical logging) gas produced, cumulative geometrical factor (multiplier), pseudo (electrical logging) gas produced from experimental tube run gas recovery, ultimate geometrical factor, (multiplier), true (noninvaded zone) (electrical logging) wet gas produced, cumulative geometrical factor (multiplier), flushed zone (electrical logging) acceleration of gravity gradient gradient, geothermal gradient, temperature conversion factor in Newton’s Second Law of Motion enthalpy (always with phase or system subscripts) enthalpy (net) of steam or enthalpy above reservoir temperature bed thickness, individual enthalpy, specific heat-transfer coefficient, convective height (other than elevation) hyperboli,c declinF,,constaht (from equation)
HANDBOOK
Dimensions
$ L3 L3
L3
1:
L3
L/t2 various T/L T/L
mL2/ t2 mL2/ t2 L L2/ t2 m/t3T L
q =qi/
h hmc h h, I I I I I
THK THKMC
i script i,i i script i,i JTJ,
THKN THKT INC CUR CUR HTCI X
I,? I I thickness- (general and individual bed) thickness, mudcake thickness, net pay thickness, gross pay (total) cash income, operating current, electric electric current heat transfer coefficient, radiation index (use subscripts as needed)
L L L L
3: m/t3T
59-7
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Reserve SPE Letter Symbol
Letter Symbol I
9 (z) script I
I, Ibl I,2
i
IJX
i, ibl
PRX PRXPR
i,2
PRXSE FFX
bf
iFf
IH
iH
JR
iR
4 lb :f t I shGR
i i i i
ki
h4 ia ‘K 4 4v J Js j j K K
K K K K KR
K fItI, KC k k
Computer Letter Symbol
HYX RSXH INCA INCB FRX INCK IJXS SHXGR RTEO INJ IRCE RTE
IRPE INJA INJG RORI
j
JS
r
INJW POX PDXS IRA
ib
BKM KSP
M
COE DSP EQR COE COER COEANI COEC
d Me‘,, M MR,a,C Mani McXec
k
;; r,j
kK kglb kh
4 Kg I&? h
SUSM PRM RRC PRMG PRMGD HCN
ko
&
PRMO
-
Quantity
injectivity index imaginary part of complex number z porosity index porosity index, primary porosity index, secondary free fluid index hydrogen index hydrocarbon resistivity index R,/R ,, cash income, operating, after taxes cash income, operating, before taxes fracture index cash income, annual operating, over year k injectivity index, specific shaliness gamma ray index, (ylOg-Y~~)/(Y,,, --yo) discount rate injection rate interest rate, effective compound (usually annual) rate: discount, effective profit, of return, reinvestment, etc; use symbol iwith suitable subscripts interest rate, effective, per period injection rate, air injection rate, gas rate of return (internal, true, or discounted cash flow) or earning power injection rate, water productivity index productivity index, specific interest rate, nominal annual reciprocal permeability bulk modulus coefficient in the equation of the electrochemical component of the SP (spontaneous electromotive force) coefficient or multiplier dispersion coefficient equilibrium ratio (Jo/x> multiplier or coefficient formation resistivity factor coefficient (FR4”) anisotropy coefficient electrochemical coefficient magnetic susceptibility permeability, absolute (fluid flow) reaction rate constant effective permeability to gas gas/oil permeability ratio thermal conductivity (always with additional phase or system subscripts) effective permeability to oil
Dimensions
L4t/m
M M M L’t/m
LJ/t
L3/t L3/t
L3/t L4t/m L3t/m l/L2 m/L+ mL2/t2q
various L2/t various
mL2/t2q
ml-/s2 L2
L/t L2 mL/t3T L2
PETROLEUM ENGINEERING
59-8
Letter Symbol
kw
Reserve SPE Letter Symbol
Computer Letter Symbol
kIO
&I
PRMRG PRMRD
kw/ko
KW KW Kw/&
PRMRW PRMW PRMWD
k k’,”
Krg
S(v) script L s, P script 1 s, P script 1
L”f
Xf
4 L
s,,& script 1
LENS HLTV
I FA F,
MAG MBR MBR MWT NMBCP SAD
M M M M M M
nL
s, P script 1
m moD
M
Mm
J&u
Fht
m
MBRSAV
MAGF MBRT
MXP
m m m
F~olFgo
m
A
45 m.%
LTH LTH MDLL LTH LTHFH
HSPV MWTAVL
ML
MS
Quantity
FF
FFE FFE~
FCM MAS MGD SLP FCMEX FCMEXG
Dimensions
relative permeability to gas relative permeability to oil relative permeability to water effective permeability to water water/oil permeability ratio transform, Laplace of y, Imy(t)e
L L L L
In log h2
-
HANDBOOK
L2 -$‘dt
distance, length, or length’of path length, path length, or distance liquid phase, moles of path length, length, or distance fracture half-length (specify “in the direction or’ when using xf ) spacing (electrical logging) heat of vaporization, latent natural logarithm, base e common logarithm, base 10 logarithm, base a magnetization mobility ratio, general (hdisplacing/hdisplaced) mobility ratio, sharp-front approximation (AD/Ad) molecular weight number of compounding periods (usually per year) slope, interval transit time vs. density (absolute value) volumetric heat capacity molecular weight of produced liquids, mole-weighted average mobility ratio, diffuse-front approximation [(AD+ Ad)swept/(b)unsweptl; D signifies displacing; d signifies displaced; mobilities are evaluated at average saturation conditions behind and ahead of front magnetization, fraction mobility ratio, total, [(A,)swept/(A,)unsweptI; “swept” and “unswept” refer to invaded and uninvaded regions behind and ahead of leading edge of displacement front cementation (porosity) exponent (in an empirical relation between FR and 4) fuel consumption mass ratio of initial reservoir free-gas volume to initial reservoir oil volume slope fuel consumption in experimental tube run fuel consumption in experimental tube run (mass of fuel per mole of produced gas)
L L L L L L2/ t2
da tn tL2/m rn/Lt2T m
various m
various m/L3 m
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Letter Symbol
Reserve SPE Letter Symbol
mR mk
FFR
N N N
n,C
FCMR AMAK NMB NEU NIJMU
n
OIL OILTI
n
NMB
N N N N
meND
NCR
N,,
NN
N,,CN
NR
NF
n
CG
NRe N, Np
nP
%a n
N
nPQ
n n n
n
N
n nN "J % 4
0 0,
P P P PPV P, pk P B F
Computer Letter Symbol
PC*PC P P P
i!R
pR
PD
pD
PO
pa
Pb
Ps,ps,pb
Pbh
P bh
PC
PC
Pcf PCS
P CJ-
Pd
pd
Pt?
pt?
PCS
SND NGR NEUN FUOR REYQ OllE OllP OILPUL NMB NGW RFX NMB NMB SXP NMBN MOLJ MOLPJ NMBM XPO XPOU CFL NMBP PRFT CFLPV PRSCP PRAK PRS PRSAV PRSAV PRSAVR PRSO PRSA PRSB PRSBH PRSC PRSCF PRSCS PRSD PRSE
-
59-9
Quantity
fuel consumption in reservoir amortization (annual write-off of unamortized investment at end of year k) count rate (general) neutron [usually with identifying subscript(s)] number, dimensionless, in general (always with identifying subscripts) oil (always with identifying subscripts) oil in place in reservoir, initial pump strokes, number of, cycles per unit of time slope, neutron porosity vs. density (absolute value) gamma-ray count rate neutron count rate fuel deposition rate Reynolds number (dimensionless number) oil influx (encroachment) cumulative oil produced, cumulative oil recovery, ultimate density (indicating “number per unit volume”) exponent of backpressure curve, gas well index of refraction number (of variables, or components, or steps, or increments, etc.) number (quantity) saturation exponent density (number) of neutrons moles of component j moles of component .i produced, cumulative number of moles, total operating expense operating expense per unit produced cash flow, undiscounted phases, number of profit, total cash flow, discounted capillary pressure profit, annual net, over year k pressure average pressure pressure, average or mean pressure, reservoir average pressure, dimensionless pressure, atmospheric pressure, bubblepoint (saturation) pressure, bottomhole pressure, critical pressure, casing flowing pressure, casing static pressure, dew point pressure, external boundary
Dimensions
dL3 M 1/t various
various L3 L3/m 1/t 1/t rn/L3t
1: L3 l/L3
l/L3
various M/L3 M M $Lt2 ZLt2 m/L? m/L+ n-l/L?
PETROLEUM
59-10
Letter Symbol
PCY, Pf Pi Piwf Piws PPC
Reserve SPE Letter Symbol
Pem Pf pi P IWf piw3
PPC
PPC PPC
b
PFJr
PI PSC
p, psc
PSP
PSP
pb
%
pi/ pts PW
Computer Letter Symbol PRSXT PRSF PRY PRSIWF PRSIWS PRSPC PRSPC PRSPRD PRSRD PRSSC PRSSP PRSTCKI PRSTF PRSTS PRSW PRSWF PRSWS PRSWS CHG HRT
P wf PWS P ws 4 4*@ QftD script 1 ENCLTQII
Qv Qi
zv
CEXV
4i
FLUID
Qp
QP,D script 1 FLUP
Qp
FLUP
Q tll
ENCTOG
QD Qll %vf&vi~Qdh 2D
Qi ED
QF Q*
q c,# Qx q mlQsc
Q, Q WD
PI’
RTE RTEAV RTEO RTEA RTEDH RTEG RTEGO RTEI RTEO RTEOCI RTEPAV RTES RTESC RTESC RTEW RTEWll RES
ENGINEERING
Quantity
pressure, extrapolated pressure, front or interface pressure, initial pressure, bottomhole flowing, injection well pressure, bottomhole static, injection well pressure, pseudocritical pseudocritical pressure pressure, pseudoreduced pressure, reduced pressure, standard conditions pressure, separator pressure function, dimensionless, at dimensionless time tD pressure, tubing flowing pressure, tubing static pressure, bottomhole general pressure, bottomhole flowing pressure, bottomhole static pressure, bottomhole, at any time after shut-in charge heat flow rate influx function, fluid, linear aquifer, dimensionless cation exchange capacity per unit pore volume pore volumes of injected fluid, cumulative, dimensionless fluids, cumulative produced (where Np and W, are not applicable) produced fluids, cumulative (where Np and W, are not applicable) fluid influx function, dimensionless, at dimensionless time tD production rate or flow rate production rate or flow rate, average production rate, dimensionless production rate at economic abandonment volumetric flow rate downhole production rate, gas production rate, gas, dimensionless production rate at beginning of period production rate, oil production rate, oil, dimensionless production rate or flow rate at mean pressure segregation rate (in gravity drainage) surface production rate volumetric flow rate, surface conditions production rate, water production rate, water, dimensionless electrical resistivity (electrical logging)
HANDBOOK
Dimensions
m/L? m/L? m/Lt* m/L? m/L? m/Lt* m/L? m/L+ rn/Lt2 m/L?
q
mL2/ t3
L3
L3/t L3/t L3/t L3/t L3/t L3/t L3/t L3/t L3/t L3/t L3/t L3/t mL3/tq2
59-11
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
R R 4 1Cw N R R Sk )script R
ARR GOR MRF RRR
Ro
RESZR
Rf
GORF
RI R, R/r, R,,,,
RESA RESI RESM
R rrif RP R, 4, R\/, 4, R,,, 4 R,, R .\o
RESMC RESMF GORP GORS GORSB RESSH GORSI GWRS REST RESW RESXO
R, r r b
RESZ RAO RST RADII
f-ll.o
RAOHL RADP RADE RADS RADW RADWA
S S S
HER SAT ST0
Sl.
SATL
S 17)
STOQ
rff rd r,. r, rn
ss S,, SW 4, s,, s,,, SO
SOP so, 4, SW
SATG SATGC SATGR SATH SATHR SATIW SAT0 SATDG SATOR SATW SATWC
Quantity
gas constant, universal (per mole) gas/oil ratio. producing molecular refraction reaction rate real part of complex number z formation resistivity when 100% saturated with water of resistivity R,,. free gas/oil ratio, producing (free-gas volume/oil volume) apparent resistivity invaded zone resistivity mud resistivity mudcake resistivity mud-filtrate resistivity cumulative gas/oil ratio solution gas/oil ratio (gas solubility in oil) solution gas/oil ratio at bubblepoint conditions shale resistivity solution gas/oil ratio, initial gas solubility in water true formation resistivity water resistivity flushed-zone resistivity (that part of the invaded zone closest to the wall of the hole, where flushing has been maximum) apparent resistivity of the conductive fluids in radius resistance radius, dimensionless hydraulic radius drainage radius external boundary radius radius of well damage or stimulation (skin) well radius radius of wellbore, apparent or effective (includes effects of well damage or stimulation) entropy, total saturation storage or storage capacity liquid saturation, combined total dimcnaionless fractional storage capacity gas saturation gas saturation, critical gas saturation, residual saturation, hydrocarbon residual hydrocarbon saturation irreducible (interstitial or connate) water saturation oil saturation gas-cap interstitial-oil saturation residual oil saturation water saturation critical water saturation
Dimensions
mLZ/t2T
i3 m/L’ mL3/tq*
mL3/ tq2 mL3/tq2 mL3/tq2 mL3/tq2 mL3/tq2
mL3/tq2
mL3/ tq2 mL3/ tq2 mL3/tq2
mL3/tq2 L ML2/tq2
mL21t2T various
59-12
Letter Symbol
PETROLEUM ENGINEERING
Reserve SPE Letter Symbol
Sw s WI SW’O Swr s S
SATWG SATWI SATWO SATWR
L
DIS HERS SKN SDVES VARES PER TRM TEM TEMR TEMBH TEMC TEMF TEMPRD TEMRD TEMSC TAC TIM TIMRP TIMH TIMAV TIMD TIMMD NFL TIMD TIMDN TIMP
S s
Computer Letter Symbol
10
S s*
T T T TR Thh T T/ T,, T. TX
t script t t tl fll2 t2 tD tDtn t/v td h!V t P
TIMS TACSH HTCU FIX VELV
ts
t,,, script t u u u
VELV
Q
R, n,, u
V,,R,
GRRT MDLV VLT VDL VLF
-
Quantity
interstitial-water saturation in gas cap initial water saturation interstitial-water saturation in oil band residual water saturation Laplace transform variable displacement entropy, specific skin effect standard deviation of a random variable, estimated variance of a random variable, estimated period transmissivity, transmissibility temperature reservoir temperature bottomhole temperature critical temperature formation temperature pseudoreduced temperature reduced temperature temperature, standard conditions interval transit time time relaxation time, proton thermal half life relaxation time, free-precession decay time, dimensionless time, dimensionless at condition m neutron lifetime time, delay decay time, neutron (neutron mean life) time well was on production prior to shut-in, equivalent (pseudotime) time for stabilization of a well shale interval transit time heat transfer coefficient, over all flux flux or flow rate, per unit area (volumetric velocity) superficial phase velocity (flux rate of a particular fluid phase flowing in pipe; use appropriate phase subscripts) gross revenue (“value”), total moles of vapor phase potential difference (electric) volume volume fraction or ratio (as needed, use same subscripted symbols as for “volumes”; note that bulk volume fraction is unity and pore volume fractions are fJ)
HANDBOOK
Dimensions
L L2/t2T various
t
various
T t/L t
l/t t t t t t/L m/t3T various L/t
L/t M mL2/qt2 L3 various
59-13
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Reserve SPE Letter Symbol
Letter Symbol
v,
Vt?,
vRb
VRI< vb
vb
vbE
vbE
Vb,, v, V8.
Computer Letter Symbol VOLM VOLRB VOLRU VOLE VOLBEX VOLBP VOLG VOLGR VOLIG
v/m
VOLIM
Vmo
V!?l,
VOLMA
Vmo
V,l,
VOLMA
Vpnr, vne
VTIP 5 VPD
VP
v,
vs
VOLNE VOLP VOLPR VOLS
Vsh
vsh
VOLSH
Vshd Vshs
vshd
VOLSHD
VU
RU
v~D
“shs
V
KU
V
VS
V
v, u
vb
vb, ub w
W W
W
w,G
W W
W
W,
WP
wi
Y
wp W
Z
W
m
t ma
I;: z X X
WP
script
t
Atrn, m
VOLSHS GRRU VAC SPV VEL VELB WTR WTRTI WGT WRK WTRE WTRI WTRP ARR MRT TACMA MRT XEL MFRL
zi 3i
MENES
-
Quantity
molal volume (volume per mole) volume of reservoir rock burned volume of reservoir rock unburned bulk volume bulk volume of pack burned in experimental tube run volume at bubble point pressure volume, effective pore volume, grain (volume of all formation solids except shales) volume, intergranular (volume between grains; consists of fluids and all shales) ( Vb- V,, 1 volume, intermatrix (consists of fluids and dispersed shale) (Vb- V,, 1 matrix (framework) volume (volume of all formation solids except dispersed clay or shale) volume, matrix (framework) (volume of all formation solids except dispersed shale) volume, noneffective pore water (always with identifying subscripts) water in place in reservoir, initial weight (gravitational) work water influx (encroachment), cumulative water injected, cumulative water produced, cumulative Arrhenius reaction-rate velocity constant mass flow rate matrix interval transit time rate, mass flow reactance tensor ofx mole fraction of a component in liquid phase vector of x mean value of a random variable, x, estimated
Dimensions
,“i: L3 L3 L3 L3
L3 L3
M/L3 L/t L3/m L/t L/t various L3 mL/t* mL*/ t* ;; L3/m m/t St ML*/tq*
59-14
Letter Symbol
PETROLEUM ENGINEERING
Reserve SPE Letter Symbol
Computer Letter Symbol
Y
HOL
Y Z Z Z
MFRV ANM ZEL ZEL
Z
MPO MPDA ZED
Z, z 2 Z 4
MFRM VAL ZEOPAV
Quantity
holdup (fraction of the pipe volume filled by a given fluid: Y, is oil hold up, y, is water holdup, sum of all holdups at a given level is one> mole fraction of a component in vapor phase atomic number elevation referred to datum height, or fluidhead or elevation referred to a datum impedance impedance, acoustic gas compressibility factor (deviation factor) (z =pV/nR r) mole fraction of a component in mixture valence gas deviation factor (compressibility factor) at mean pressure
HANDBOOK
Dimensions
L L various m/L2t
Greek CY a a! CY a “SPsh ; Y
Y Y Y + Y&T YO YW
A
ANG COEA HTD RED HTD REDSH BRGR HEC GRY SPG HSPR STNS SRT SPGG SPGO SPGW DEL DELGASE DELGASI OELGASP OELOILE DELOILP OELWTRE DELWTRI OELWTRP OELRAD DELTIMWF
AL
OELTIMWS
angle attenuation coefficient heat or thermal diffusivity reduction ratio or reduction term thermal or heat diffusivity reduction ratio, SP, due to shaliness bearing, relative thermal cubic expansion coefficient gamma ray [usually with identifying subscript(s) 1 specific gravity (relative density) specific heat ratio strain, shear shear rate specific gravity, gas specific gravity, oil specific gravity, water difference or difference operator, finite (Ax =x2 -x1 or x1 -x2) gas influx (encroachment) during an interval gas injected during an interval gas produced during an interval oil influx (encroachment) during an interval oil produced during an interval water influx (encroachment) during an interval water injected during an intervai water produced during an interval radial distance (increment along radius) drawdown time (time after well is opened to production) (pressure drawdown) buildup time; shut-in time (time after well is shut in) (pressure buildup, shut-in time)
l/L L*/t L2/t
l/T various
l/t
L t
SPE LETTER AND COMPUTER SYMBOLS STANDARD
59-15
Reeerve
SPE Letter Symbol
Computer Letter Symbol
Quantity -
DCR ANGH OPR ANGH SKD DPROB DPROU
DPRWB
DIE STN DFS ANGO ANGDA ANGC ANG STNV LAM MOB WVL MOBG MOB0 MOBT MOBW PSN RAZ PAMM MEN VIS VISA VISG VEGA VISO VISPAV VISW VSK VSK DEN RHO DENAVL DENFU DENA DENB DENF OENG
decrement deviation, hole (drift angle) displacement ratio drift angle, hole (deviation) skin depth (logging) displacement ratio, oil from burned volume, volume per unit volume of burned reservoir rock displacement ratio, oil from unburned volume, volume per unit volume of unburned reservoir rock displacement ratio, water from burned volume, volume per unit volume of burned reservoir rock dielectric constant strain, normal and genera1 hydraulic diffusivity (~/c#Jc~ or A/4c) angle of dip dip, apparent angle of contact angle angle strain, volume decay constant (l/~,,) mobility (k /CL) wave length (I/CT) mobility, gas mobility, oil mobility, total, of all fluids in a particular region of the reservoir [e.g., (A,,+& +A,,.)] mobility, water Poisson’s ratio azimuth of reference on sonde magnetic permeability mean value of a random variable viscosity, dynamic viscosity, air viscosity, gas viscosity, gas, at 1 atm viscosity, oil viscosity at mean pressure viscosity, water kinematic viscosity viscosity, kinematic density electrical resistivity (other than logging) density of produced liquid, weight-weighted average density, fuel density, apparent density, bulk density, fluid density, gas
Dimensions
various
L
q2t2/mL3 L2/t
l/t L3t/m L L3t/m L3t/m L3t/m L3t/m
mL/q* m/Lt d-t m/Lt m/Lt m/Lt m/Lt m/Lt L*/t L2jt m/L3 mL3jtq2 dL3
$1: m/L3 m/L3 m/L3
59-16
Letter Symbol Pm0 PO fsE
PETROLEUM ENGINEERING
Reserve SPE Letter Symbol
Computer Letter Symbol DENMA DEND DENSEX DENT DENW DENXD XSTMAC SUM SIG XSTMIC XNL SFT XSTMIC sov STS SFT WVN VAR STSS TIMC TIMAV TORHL TDRHL TIMD TIMD TORE DA2 POT POR POREX PORR PORA PORE PDRH PDRIG PORIM PORNE PORT STR DSM
ot < s > 3
AV LT LE GT GE
Quantity
density, matrix (solids, grain) density, oil density of solid particles making up experimental pack density, true density, water density, flushed zone cross section, macroscopic summation (operator) conductivity, electrical (other than logging) cross section, microscopic cross section of a nucleus, microscopic interfacial, surface tension microscopic cross section standard deviation of a random variable stress, normal and general surface tension, interfacial wave number (l/h) variance of a random variable stress, shear time constant lifetime, average (mean life) hydraulic tortuosity tortuosity, hydraulic decay time (mean life) (l/A) mean life (decay time) (l/A) tortuosity, electric dip, azimuth of potential or potential function porosity (vb - vS)/ vb porosity of experimental pack porosity of reservoir or formation porosity, apparent porosity, effective (V,,/Vh) porosity, hydrocarbon-filled, fraction or percent of rock bulk volume occupied by hydrocarbons “porosity” (space), intergranular (V, - V,, )/V, “porosity” (space), intermatrix tvb - v,,,, )/ vb porosity, noneffective (V,,,/V,) porosity, total stream function dispersion modulus (dispersion factor) angular frequency proportional to average or mean (overbar) smaller than equal to or smaller than larger than equal to or larger than
HANDBOOK
Dimensions
-
m/L3 m/L3 m/L’ m/L3 m/L’ m/L3 l/L various l/L L* m/t2 L* m/L+ r-n/t* l/L m/L+ t t
various
various l/t
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Reserve SPE Letter Symbol
Letter Symbol
Computer Letter Symbol ASYM APPR DEL
V V. V2 VX erf erfc lim
b
Y
ERF ERFC LM ICP
E,
Ei(x)
59-17
Quantity
asymptotically equal to approximately equal to or is approximated by (usually with functions) de1 (gradient operator) divergence Laplacian operator curl error function error function, complementary limit intercept Euler’s number exponential integral, modified kii [ s-‘$dt+ -co
- Ei( -x)
r:dt]
c
exponential integral, exp z
f” g(z)
F
EXP FAC FRC
various
, x positive
me-’ s x
ez
Dimensions
-dt, t
x positive
exponential function ratio fraction imaginary part of complex number z Laplace transform of y, imy(t)es’dt
A
SLP NUMQ NMB
SDVES VARES MENES
P,T
f
ANG
MEN POT STR SDV VAR
logarithm. natural, base i logarithm. common, base 10 logarithm, base u slope number. dimensionless number (of variables, or steps. or increments, etc.) real part of complex number ,: Laplace transform variable standard deviation of a random variable. estimated variance of a random variable. estimated mean value of a random variable. .Y. estimated vector of Itensor of .r angle Euler’s constant=0.5772 difference (Ax=x* --x t or x, --x2) difference operator, finite mean value of a random variable potential or potential function stream function standard deviation of a random variable variance of a random variable
various
various various
59-18
PETROLEUM ENGINEERING
HANDBOOK
Quantities in Alphabetical Order
Letter Symbol
Quantity
Arrhenius reaction-rate velocity constant absolute permeability (fluid flow) acceleration of gravity acoustic impedance acoustic velocity activity air/fuel ratio air injection rate air requirement air requirement, unit, in laboratory experimental run, volumes of air per unit mass of pack air requirement, unit, in reservoir, volumes of air per unit bulk volume of reservoir rock air viscosity amortization (annual write-off of unamortized investment at end of year k) amplitude amplitude, compressional wave amplitude, relative amplitude, shear wave angle angle angle of dip angle, contact angular frequency anisotropy coefficient annual operating cash income, over year k annulus geometrical factor (multiplier or fraction) apparent interval transit time apparent conductivity apparent density apparent or effective wellbore radius (includes effects of well damage or stimulation) apparent porosity apparent resistivity apparent resistivity of the conductive fluids in an invaded zone (due to fingering) approximately equal to or is approximated by (usually with functions) area area1 efficiency (used in describingresultsof model studies only); area swept in a model divided by total model reservoir area (see EJ asymptotically equal to Dimensions: Lzlength.
m=maSs. q=de~tl~al
charge.
t=tlIllt?.
Reeerve SPE Letter Symbol
Computer Letter Symbol
aE
ARR PAM GAV MPOA VAC ACT FACAFU INJA AIR AIREX
aR
AIRR
P g ZO V
iF ‘0
a
Pa mk
t, script f
dLt M
AMP AMPC AMPR AMPS ANG ANG ANGII ANGC FQNANG COEANI INCK GMFAN
various various various various
PORA RESA
=E
APPR
A
ARA EFFA
RESZ
-
‘1=temperature, and
ASYM M =money.
various L3/t various L3/m
VISA
40 47 R,
EA
L3/m L’ L/t2 m/L2t L/t
AMAK
TACA ECNA IJENA RADWA
ccl pa rho r,.,
Dimensions
‘It M
t/L tq2/mL3 m/L3 L
mL3/tq2 mL3/tq2
L2
SPE LETTER AND COMPUTER SYMBOLS STANDARD
59-19
Letter Symbol
Quantity -
Reserve SPE Letter Symbol
Computer Letter Symbol
Dimensions
-
atmospheric pressure atomic number atomic weight attenuation coefficient average flow rate or production rate average or mean (overbar) average pressure average reservoir pressure azimuth of dip azimuth of reference on sonde backpressure-curve exponent, gas well backpressure curve (gas well), coefficient of backpressure curve (gas well), exponent of base a, logarithm bearing, relative bed thickness, individual bottomhole flowing pressure bottomhole pressure bottomhole pressure flowing bottomhole flowing pressure, injection well bottomhole static pressure, injection well bottomhole pressure at any time after shut-in bottomhole pressure, general bottomhole pressure, static bottomhole (well) pressure in water phase bottomhole temperature breadth, width, or thickness (primarily in fracturing) boundary pressure, external boundary radius, external bubblepoint formation volume factor, gas bubblepoint formation volume factor, oil bubblepoint (saturation) pressure bubblepoint reciprocal gas formation volume factor at bubblepoint conditions bubblepoint pressure, volume at bubblepoint solution gas/oil ratio buildup time; shut-in time (time after well is shut in) (pressure buildup, shut-in time) bulk density bulk modulus bulk volume bulk volume of pack burned in experimental
PO Z A
A4 -a Q P P Pd M
PRSA ANM AWT COEA ’ RTEAV AV PRSAV PRSAVR DA2 RAZ NGW CGW NGW BRGR THK PRSWF PRSBH PRSWF PRSIWF PRSIWS PRSWS PRSW PRSWS PRSWW TEMBH WTH
m/Lt2 m l/L L’/t m/Lt* nl/Lt2
L m/Lt* m/Lt2 m/Lt* m/Lt2 m/Lt2 m/Lt* m/Lt’ n-l/L? m/Lt* T L
$6 Bob
Fgb F,,
Pb
Psfs,pb
PRSE RAOE FVFGB FVFOB PRSB
f&J;b
RVFGB
b
VOLBP
L3
Arws
GORSB DELTIMWS
t
PC>
PC &
bd V
Fxsb
2 At,,
pb
K vb
VbE
rho
Db & vb VbE
DENB BKM VOLB VOLBEX
m/L+ L
m/Lt*
m/L3 m/Lt2 ;:
tube run
bulk (total) volume, fraction of burned reservoir rock, volume of burning-zone advance rate (velocity of) capacitance
Vh
FRCVB VOLRB VELB
C
ECU
fv VRtl
L3 L/t q2t2/mL2
PETROLEUM ENGINEERING
59-20
Quantity -
-
capacity, cation exchange, per unit pore volume capacity, cation exchange, per unit pore volume, total capacity, storage capacity, dimensionless fractional storage capillary pressure capital investment, initial capital investment, subsequent, in year k capital investments, summation of all cash flow, discounted (present value) cash flow, undiscounted cash income, annual operating, over year k cash income, operating cash income, operating, after taxes cash income, operating, before taxes casing pressure, flowing casing pressure, static cation exchange capacity per unit pore volume cation exchange capacity per unit pore volume, total cementation (porosity) exponent (in an empirical relation between FR and 4) charge (current times time) coefficient, anisotropy coefficient, attenuation coefficient, convective heat transfer coefficient, diffusion coefficient, electrochemical coefficient, formation resistivity factor coefficiem in the equation of the electrochemical component of the SP (spontaneous electromotive force) coefficient of gas-well backpressure curve coefficient heat transfer, overall coefficient, heat transfer, radiation coefficient, thermal cubic expansion coefficient or multiplier combined total liquid saturation common logarithm, base 10 component j, cumulative moles produced component j, moles of component, mole fraction of, in liquid phase component, mole fraction of, in mixture component, mole fraction of, in vapor phase components, number of component of the SP, electrochemical component of the SP, electrokinetic compressibility compressibility factor (gas deviation factor, z=pVlnRT)
HANDBOOK
Letter Symbol
Reserve SPE Letter Symbol
QV Qv,
zv zv,
CEXV CEXUT
s
S,Q
ST0 STOQ
various
PRSCP
m/L? M M M M M M M M M m/Lt2 m/Lt*
SP PC c, Ch C P PI; P
SD
Pc.Pc
INVI INVK INVT CFLPV CFL INCK INC INCA INCB PRSCF RSCS CEXV CEXUT
C,
h I 42 Ib
PC! PC,
Qv Qbi
Computer Letter Symbol
PC, p<, zv 44
m
MXP
Q
Dimensions
K
CHG COEANI COEA HTCC OFN COEC
KR
COER
K
KSP
mL2/t2q
C CT I
~3-21~4n/~2n
IT, 1,
ii
b M
SL
PL JL
CGW HTCU HTCI HEC COE SATL
K cl,,, h* D
uT,
u,
9
l/L m/t3T L2/t mL2/t2q
m/t3T rn/t3T l/T various
log 51 n/ X Z
Y C
nc
4
@c
Eh c
@k
Z
ktK Z
MOLPJ MOLJ MFRL MFRM MFRV NMBC EMFC EMFK CMP ZED
mL2/t2q mL2/t2q Lt2/m
59-21
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Reserve SPE Letter Symbol
Quantity
Computer Letter Symbol
Letter Symbol
Dimensions
-
compressibility factor or deviation factor for gas, at mean pressure compressibility, formation or rock compressibility, gas compressibility, oil compressibility, pseudoreduced compressibility, water compressional wave amplitude concentration concentration, methane (concentration of other paraffin hydrocarbons would be indicated similarly, Ccz, Cc, , etc.)
ZEDPAV CMPF CMPG CMPO CMPPRO CMPW AMPC CNC CNCCl
Ltz/m various various various
CNCOZ
various
cm94
CNCFU
various
gL
NGLTI
L3
NGLP CNTL SIG ECN ECNA CNDFQ
L3 various various tq2/mL3 tq2/mL3
CND HCN
various mL/t3T
concentration, oxygen (concentration of other elements or compounds would be indicated similarly, Ccoz, CNl, etc.) concentration, unit fuel (see
symbol
Lt2/m Lt2/m Lt2/m
m)
condensate liquids in place in reservoir, initial condensate liquids produced, cumulative condensate or natural gas liquids content conductivity, electrical (other than logging) conductivity (electrical logging) conductivity (electrical), apparent conductivity, fracture, dimensionless conductivity, other than electrical (with subscripts) conductivity, thermal (always with additional phase or system subscripts) constant, Arrhenius reaction-rate velocity constant constant, decay (l/~d) constant, dielectric constant, Euler’s = 0.5772 constant in general* constant-income discount factor constant3 hyperb,c$ic decline,
c kh W
z
ARR
L3/m
A
C
LAM DIG
q2t2/mL3
E epsilon Y
l/t
oscc HPC
a,t
4 =a/
I I l+h
constant: universal gas (per mole) constant, waterdrive constant, waterdrive, linear aquifer consumption, fuel consumption of fuel in experimental tube run consumption of fuel in experimental tube run (mass of fuel per mole of produced gas) consumption of fuel in reservoir contact angle content, condensate or natural gas liquids content, wet-gas convective heat-transfer coefficient *Any
sunable nonconfl~crmg
symbol
defined
m the text
R c
RRR
CL m
FF
mE
FFE
ME,
FFE~
FFR r< 9 Yc CL
CL.4
c,
CwRJnwR
h
hh,hT
-
WDC WDCL FCM FCMEX FCMEXG
mL2/ t2T L4t2/m L4t2/m various I-f-l/L3 m
FCMR
m/L3
ANGC CNTL CNTWG HTCC
various various m/t3T
PETROLEUM
59-22
Quantity
conversion factor in Newton’s Second Law of Motion correction term or correction factor (either additive or multiplicative) count rate (general) count rate, neutron count rate, gamma ray critical gas saturation critical pressure critical temperature critical water saturation cross section (area) cross section, macroscopic cross section, microscopic cross section of a nucleus, microscopic cubic expansion coefficient, thermal cumulative condensate liquids produced cumulative free gas produced cumulative gas influx (encroachment) cumulative gas injected cumulative gas/oil ratio cumulative gas produced cumulative moles of component j produced cumulative oil influx (encroachment) cumulative oil produced cumulative produced fluids (where NP and W, are not applicable) cumulative water influx (encroachment) cumulative water injected cumulative water/oil ratio cumulative water produced cumulative wet gas produced curl current, electric damage or stimulation radius of well (skin) damage ratio or condition ratio (conditions relative to formation conditions unaffected by well operations) datum, elevation referred to decay constant (l/~,j) decay time (mean life) (l/x) decay time, neutron (neutron mean life) decline constant, hyperbolic, from the equation
/I q =q,/ l+T I I decline factor, effective decline factor, nominal decrement degrees of freedom
Letter Symbol
Reserve SPE Letter Symbol
ENGINEERING
Computer Letter Symbol
HANDBOOK
Dimensions
GRVC C
s
b gLP gF,, & g, FKP?FKOP 4 NW HP 5
We wi
WP g WI,
; script i,i 4 Fd
Oh
C td
COR NMB NEUN NGR SATGC PRSC TEMC SATWC ARA XSTMAC XSTMIC XNL HEC
l/t 1/t 1/t m/L+ T L2 l/L l/JL2 l/T
NGLP GASFP GASE GASI GORP GASP MOLPJ OILE OILP FLUP WTRE WTRI FACWOP WTRP GASWGP
;i
L3 L3 L3
mL/t2 L3 L3
CUR RADS DMRS
dt
ZED LAM TIM0 TIMON HPC
L l/t t t
DECE DEC OCR DGF
L
various
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
de1 (gradient operator) delay time deliverability (gas well) density density, apparent density, bulk density, fluid density, flushed zone density (indicating “number per unit volume”) density, fuel density, gas density, matrix (solids, grain) density (number) of neutrons density of produced liquid, weight-weighted average density of solidparticles making up experimental pack density, oil density, relative (specific gravity) density, true density, water depletion deposition rate of fuel depreciation depth depth, skin (logging) deviation factor (compressibility factor) for gas (z=pV/nRT) deviation factor (compressibility factor) for gas, at mean pressure deviation, hole (drift angle) dewpoint pressure
59-23
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
Dimensions
nf
-
pr
DL
DEL TIMDY DLV DEN DENA DENB DENF DENXD NMB DENFU DENG DENMA NMBN DENAVL
P\L
D.,E
DENSEX
II-l/l--’
PO Y PI
DEN0
m/L3
s,
V ; p
rho
PN Ph
PI PW n PIPa PlllU
p,,
D DO & Dl DAYI N D, 4 D 1,10
DC, F,
4 DM
DE NR
NF
DP
D s Z
SPG DENT DENW EDE FUDR EDP
Y.H
DPH
>
SKD ZED
t
L3/t m/L3 m/L3 m/L” m/L3 m/L3 l/L3 m/L3 m/L3 Ill/L3 l/L3 m/L3
m/L3 m/L3 m/L3 t L L
ZEDPAV
diameter
6 PC/ d
diameter, hole diameter, invaded zone (electrically equivalent)
4, 4
diameter, mean particle dielectric constant difference or difference operator, finite (AX =x2-x1 orxI-x2) diffusion coefficient diffusivity, hydraulic (k/+cp or h/$x) dimensionless fluid influx function, linear aquifer dimensionless fluid influx function at dimensionless time rD dimensionless fractional storage capacity dimensionless fracture conductivity dimensionless gas production rate dimensionless number, in general (always with identifying subscripts) (Example: Reynolds number, NRe) dimensionless oil-production rate dimensionless pore volume
d,,
ANGH PRSD DIA DIAH DIAI
E epsilon A D r)L,D
Qp,D scripl I
QID s, C ID 4x0 N
4,JD VPD
DIAAVP DIC DEL
L q2t2/mL3
DFN DFS ENCLTDQ
L2/t L2/t
ENCTDD SD Kfl
QKD
QoD %D
m/L+ L L L
STOQ CNDFO RTEGD NUMD
RTEDD voua
59-24
PETROLEUM ENGINEERING
Quantity
dimensionless pressure dimensionless-pressure function at dimensionless time tD dimensionless production rate dimensionless quantity proportional to x dimensionless radius dimensionless time dimensionless time at condition m dimensionless water production rate dip, angle of dip, apparent angle of dip, apparent azimuth of dip, azimuth of discount factor, constant-income discount factor, general discount factor, single-payment [l/(1 +i)k; or ePJk, j = ln(1 +i)l discount factor, single-payment (constant annual rate) [e-‘” (e’- 1j/j1 discount rate discounted cash flow dispersion coefficient dispersion modulus (dispersion factor) displacement displacement efficiency from burned portion of in-situ combustion pattern displacement efficiency from unburned portion of in-situ combustion pattern displacement efficiency: volume of hydrocarbons (oil or gas) displaced from individual pores or small groups of pores divided by the volume of hydrocarbons in the same pores just before displacement displacement ratio displacement ratio, oil from burned volume, volume per unit volume of burned reservoir rock displacement ratio, oil from unburned volume, volume per unit volume of unburned reservoir rock displacement ratio, water from burned volume, volume per unit volume of burned reservoir rock distance between adjacent rows of injection and production wells distance between like wells (injection or production) in a row distance, length, or length of path distance, radial (increment along radius)
Reserve SPE Letter Symbol
Letter Symbol
PD
PID
Computer Letter Symbol
P ID
PD
PRSD fw.Taa
QD
RTEa
RD
RAD[I TlMa TlMMa RTEWQ ANGD ANGDA DAZA DAZ
TD 7DM
Q M,D ffd ffda Pdo Pd
HANDBOOK
Dimensions
oscc DSC DSCSP
D SPC
DSCSPC
d L 7)Db ?eDb
RTED CFLPV DSP DSM DIS EFFDB
L2jt
L
EFFDU EFFD
7)DTeD
1
DPR DPRDB DPRDU
6 wb
Fdwb
DPRWB
LdpL2
DUW
L
DLW
L
LTH DELRAD
L L
LOJ
1
s,p script I
Ar
AR
59-25
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
Letter Symbol
Reserve SPE Letter Symbol
V rci At,
Rd ATwf
Computer Letter Symbol
Dimensions
-
divergence drainage radius drawdown time (time after well is opened to production) (pressure drawdown) drift angle, hole (deviation) earning power or rate of return (internal, true, or discounted cash flow) effect, skin effective decline factor effective or apparent wellbore radius (includes effects of well damage or stimulation) effective permeability to gas effective permeability to oil effective permeability to water effective porosity efficiency efficiency, area1 (used in describing results of model studies only): area swept in a model divided by total model reservoir area (see EP) efficiency, displacement, from burned portion of in-situ combustion pattern efficiency, displacement, from unburned portion of in-situ combustion pattern efficiency, displacement: volume of hydrocarbons (oil or gas) displaced from individual pores or small groups of pores divided by the volume of hydrocarbon in the same pores just before displacement efficiency, invasion (vertical): hydrocarbon pore space invaded (affected, contacted) by the injection fluid or heat front divided by the hydrocarbon pore space enclosed in all layers behind the injected fluid or heat front efficiency, overall reservoir recovery: volume of hydrocarbons recovered divided by volume of hydrocarbons in place at start of project
d
Tm’a
L t
ANGH
6 ‘I s
RADD DELTIMWF
ADRI
S,oR wa
SKN DECE RADWA PRMG PRMD PRMW PORE EFF EFFA
kK ko kw 4, E
EA
EDb
7)DbjeDb
EFFDB
41,
“(1DuxDu
EFFDU
41
?)DPeD
EFFD
E,
r)l,el
EFFI
ER
“rlR zR
EFFR
EP
77tw
EFFP
Ebb
rlVbTeVb
EFFVB
EV
t)vxb,
EFFV
E
Y
ELMY
L t: L’
(ER=EIJE,E,l=Eb.ED)
efficiency, pattern sweep (developed from area1 efficiency by proper weighting for variations in net pay thickness, porosity, and hydrocarbon saturation): hydrocarbon pore space enclosed behind the injected-fluid or heat front divided by total hydrocarbon pore space of the reservoir or project efficiency, volumetric, for burned portion only, in-situ combustion pattern efficiency, volumetric: product of pattern sweep and invasion efficiencies elasticity, modulus of (Young’s modulus)
In/L+
59-26
PETROLEUM ENGINEERING
Letter Symbol
Quantity
electric current electric impedance electrical conductivity (other than logging) electrical resistivity (other than logging) electrical resistivity (electrical logging) electrical tortuosity
I
electrically zone
;,
equivalent
diameter
of the invaded
electrochemical coefficient electrochemical component of the SP electrokinetic component of the SP electromotive force elevation referred to datum encroachment or influx, gas, cumulative encroachment or influx, gas during an interval encroachment or influx, oil, cumulative encroachment or influx, oil, during an interval encroachment or influx rate encroachment or influx rate, gas encroachment or influx rate, oil encroachment or influx rate, water encroachment or influx, water, cumulative encroachment or influx, water, during an interval energy enthalpy (always with phase or system subscripts) enthalpy (net) of steam or enthalpy above reservoir temperature enthalpy, specific entropy, specific entropy, total equal to or larger than equal to or smaller than equilibrium ratio (y/x) equivalent diameter (electrical) of the invaded zone equivalent time well was on production before shut-in (pseudotime) equivalent water resistivity error function error function, complementary Euler number Euler’s constant = 0.5772 expansion coefficient, thermal cubic experimental pack porosity exponent of backpressure curve, gas well exponent, porosity (cementation) (in an empirical relation between FK and $) exponent, saturation exponential function
Reserve SPE Letter Symbol
i script i,i
Z, a
p rho R
Computer Letter Symbol
HANDBOOK
Dimensions
CUR
q/t
MPDE SIG RHO RES TORE
mL2/tq2 various mL3/ tq2 mL3/ tq2
DIAI
L
COEC EMFC EMFK EMF ZEIJ GASE OELGASE OILE
mL2/t2q mL2/t2q mL2/t2q mL2/t2q L
OELOILE ENC ENCG ENCO ENCW WTRE DELWTRE ENG HEN HENS
ki L3 L3 L3/t L3/t L3/t L3/t L3 L3 mL*/ t2 mL2/ t2 mL2/t2
h
HENS
: 2 G K 4
HERS HER GE LE EDR DIAI
II’
TIMP
er.f
R,,,.
RWE ERF ERFC
mL”/tq!
; 41. I1 m
HEC POREX NGW MXP
l/T
erfc E,,
n e’
exp z
SXP EXP
L2/ t2 L2/tLT mL2/t2T
L
59-27
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
exponential integral 02 c-i s
t
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
Dimensions
-Ei (-x )
df,x positive
\
external boundary pressure external boundary radius extrapolated pressure factor, compressibility (gas deviation factor z =a VInR T) factor, discount factor, effective decline factor, nominal decline factor, conversion, in Newton’s Second Law of Motion factor, formation resistivity, equals R o/R,, (a numerical subscript to F indicates the value of R,,) factor, friction factor, geometrical (multiplier) (electrical logging) factor, geometrical (multiplier) annulus (electrical logging) factor, geometrical (multiplier) invaded zone (electrical logging) factor, geometrical (multiplier) pseudo (electrical logging) factor, geometrical (multiplier) flushed zone (electrical logging) factor, geometrical (multiplier) mud (electrical logging) factor, geometrical (multiplier) true (noninvaded zone> (electrical logging) factor in general, including ratios (always with identifying subscripts) factor, turbulence flow rate, mass flow rate, heat flow rate or flux, per unit area (volumetric velocity) flow rate or production rate flow rate or production rate at mean pressure flow rate or production rate, average flowing bottomhole pressure, injection well flowing pressure, bottomhole flowing pressure, casing flowing pressure, tubing
Ei(x)
PRSE RADE PRSXT ZEO
D d a ‘%
DSC OECE DEC GRVC
FK
FACHR
f G
.fG
FACF GMF
Go,,
fcm
GMFAN
G,
fG,
GMFI
m/Lt2 L m/L?
GMFP GMFXO GMFM
G,
.fG,
GMFT
F
A&-
FAC
various
FACB MRT HRT VELV
m/t
RTE RTEPAV
L3/t L3/t
RTEAV PRSIWF PRSWF PRSCF PRSTF
L3/t m/Lt2 m/Lt2 m/Lt2 m/Lt2
FB
m 49@ JI
mL*/ t3 L/t
59-28
PETROLEUM ENGINEERING
Letter Symbol
Quantity
flowing time after well is opened to production (pressure drawdown) fluid (generalized) fluid interval velocity fluid head or height or elevation referred to a datum fluid interval transit time fluid density fluid influx function, dimensionless, at dimensionless time tD fluid influx function, linear aquifer, dimensionless fluids, cumulative produced (where NP and W, are not applicable) flushed-zone density flushed-zone resistivity (that part of the invaded zone closest to the wall of the hole, where flushing has been maximum flushed-zone geometrical factor (fraction or multiplier) flux flux or flow rate, per unit area (volumetric velocity) force, mechanical force, electromotive (voltage) formation or reservoir porosity formation or rock compressibility formation resistivity factor-equals RJR, (a numerical subscript to F indicates the value I?,) formation resistivity factor coefficient (FR@”) formation resistivity, true formation resistivity when 100% saturated with water of resistivity R, formation temperature formation volume factor at bubblepoint conditions, gas formation volume factor at bubblepoint conditions, oil formation volume factor, gas formation volume factor, oil formation volume factor, total (two-phase) formation volume factor, volume at reservoir conditions divided by volume at standard conditions formation volume factor, water fraction (such as the fraction of a flow stream consisting of a particular phase) fraction gas
At,,
Reserve SPE Letter Symbol
Computer Letter Symbol
HANDBOOK
Dimensions
OELTIMWF
t
“I Z
FLU VACF ZEL
L/t
t,/ script t P,Trho Q ID
TACF DENF ENCTtlO
Arw,
F
QL,D
QP
Qf,Dscript I Qp,Dscript I
pxo rho R x0
u u F E
Q V
4R
fR.
ER
Cf
$9
KJ
FR
KR
MR,a,C
Rt Ro
Tf
Of
t/L m/L3
m/L3 mL3/tq2
GMFXO FLX VELV
various L/t
FCE EMF PORR CMPF FACHR
mL/t2 mL2/t2q Lt2jm
CDEA REST RESZR
mL3jtq2 mL3jtq2
TEMF
T
B@’
Fgb
FVFGB
Bob
Fob
FVFOB
Bx BO 4 B
L
ENCLTOO FLUP DENXO RESXO
fGx0
various
FVFG FVFO FVFT FVF
FVFW FRC FRCG
SPE LETTER AND COMPUTER SYMBOLS STANDARD
-
Quantity
fraction liquid fraction of bulk (total) volume fraction of intergranular space (“porosity”) occupied by all shales fraction of intergranular space Cporosity”) occupied by water fraction of intermatrix space (“porosity”) occupied by nonstructural dispersed shale fracture conductivity, dimensionless fracture half-length (specify “in the direction or’ when using 5, ) fracture index free energy (Gibbs function) free fluid index free gas/oil ratio, producing (free-gas volume/oil volume) free gas produced, cumulative free-gas volume, initial reservoir (=mNB,,) free producing gas/oil ratio (free-gas volume/ oil volume) frequency friction factor front or interface pressure fuel concentration, unit (see symbol m) fuel consumption fuel consumption in experimental tube run fuel consumption in experimental tube run (mass of fuel per mole of produced gas) fuel consumption in reservoir fuel density fuel deposition rate fugacity gamma ray count rate gamma ray [usually with identifying subscript(s) 1 gas(any gas, including air) always with identifying subscripts gas-cap interstitial-oil saturation gas-cap interstitial-water saturation gas compressibility gas compressibility factor (deviation factor) (Z=pV/nR r) gas constant, universal (per mole) gas density gas deviation factor (compressibility factor) at mean pressure gas deviation factor (compressibility factor, z =p V/nRT) (deviation factor) gas, effective permeability to gas formation volume factor
59-29
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
FL,~, script1
f$th
FRCL FRCVB FIGSH
f&
FIGW
f &hd
FIMSHO
CJD
CNOFO LTHFH
.fL
fv
LJ
FRX GFE FFX GORF
1,
G
IFI RI-
G G;
L
mL2/ t2
GASFP GASFI GORF
RF
FON FACF PRSF CNCFU FCM FCMEX FCMEXG
: pi G
m mE “4
FCMR
mR
PF
Dimensions
rho
NR
f NGR E
S SZ 52 z
R
OENFU FUOR FUG NGR GRY GAS SATOG SATWG CMPG ZEO
P,~rho zp
RRR DENG ZEOPAV
Z
ZEO
h 4
PRMG FVFG
l/t m/L+ various various m/L3 m m/L3 m/L3 m/L3 t m/L+ l/t various various
Lt*/m
mL*/t*T m/L3
L2
59-30
-
PETROLEUM ENGINEERING
Quantity
gas formation volume factor at bubblepoint conditions gas fraction gas in place in reservoir, total initial gas influx (encroachment), cumulative gas influx (encroachment) during an interval gas influx (encroachment) rate gas injected, cumulative gas injected during an interval gas injection rate gas liquids, natural, or condensate content gas mobility gas, fraction gas mole fraction V/(L + V) gas/oil permeability ratio gas/oil ratio, cumulative gas/oil ratio, free producing (free-gas volume/ oil volume) gas/oil ratio, producing gas/oil ratio, solution at bubblepoint conditions gas/oil ratio, solution (gas solubility in oil) gas/oil ratio, solution, initial gas produced, cumulative gas produced during an interval gas produced from experimental tube run gas production rate gas production rate, dimensionless gas reciprocal formation volume factor gas reciprocal formation volume factor at bubblepoint conditions gas recovery, ultimate gas, relative permeability to gas saturation gas saturation, critical gas saturation, residual gas solubility in oil (solution gas/oil ratio) gas solubility in water gas specific gravity gas viscosity gas viscosity at 1 atm gas-well backpressure curve, coefficient of gas-well backpressure curve, exponent of gas-well deliverability gas, wet, produced, cumulative general and individual bed thickness general dimensionless number (always with identifying subscripts) geometrical factor (multiplier) (electrical logging)
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
HANDBOOK
Dimensions
FVFGB
FRCG GASTI GASE DELGASE ENCG GASI OELGASI INJG CNTL MOBG FRCG MFRTV PRMGO GORP GORF
L3/t various L3t/m
GOR GORSB GORS GORSI GASP OELGASP GASPEX RTEG RTEGO
;;
L3/t
RVFG RVFGB GASPUL PRMRG SATG SATGC SATGR GORS GWRS SPGG VISG VISGA CGW NGW OLV d,e
GASWGP THK NUMB
fG
GMF
&P
L3
m/Lt m/Lt L3-2nt4n/m2n
L3/t L3 L
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
geometrical factor (multiplier), annulus (electrical logging) geometrical factor (multiplier), flushed zone (electrical logging) geometrical factor (multiplier), invaded zoned (electrical logging) geometrical factor (multiplier), mud (electrical logging) geometrical factor, (multiplier), true (noninvaded zone) (electrical logging) geometrical factor (multiplier), pseudo (electrical logging) geometrical factor (multiplier), true (electrical logging) gradient gradient, geothermal gradient operator gradient, temperature grain (matrix, solids) density gravity, acceleration of gravity, specific, relative density gravity, specific, gas gravity, specific, oil gravity, specific, water gross (total) pay thickness gross revenue (“value”) per unit produced gross revenue (“value”), total half-life heat flow rate heat of vaporization, latent heat or thermal diffusivity heat, specific (always with phase or system subscripts) heat transfer coefficient, convective heat transfer coefficient, overall heat transfer coefficient, radiation height, or fluid head, or elevation referred to a datum height (other than elevation) Helmholtz function (work function) holdup (fraction of the pipe volume filled by a given fluid; yO is oil holdup, yw is water holdup, C of all holdups at a given level is one) hole deviation, drift angle hole diameter hydraulic diffusivity (k /C$Cp or A/+) hydraulic radius hydraulic tortuosity
59-31
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
G Clli
fcan
GMFAN
G,,
fGx0
GMFXO
G
fc,
GMFI
Gt?,
fcm
GMFM
G,
fc,
GMFT
GP G,
GMFP
fc, Y
GRD GRDGT
L M/L3 M t mL2/ t3 L2/ t2 L2/t L2/t2T
D.h
HTCC HTCU HTCI ZEL
m/t3T m/t3T m/t3T L
d,e /”
ZHT HWF HOL
L mL*/ t2
4, @ A” ap 77h
Y
various T/L
GRDT OENMA GRV SPG SPGG SPGO SPGW THKT GRRU GRRT TIMH HRT HLTV HTD HSP
D ma
h A
GMFT
4 gh
h u I z
Dimensions
hh,hT UT, II, ITJO
dHd?i, RH
ANGH DIAH DFS RAOHL TORHL
T/L dL3 L/t2
L L21t L
PETROLEUM ENGINEERING
59-32
Quantity
hydrocarbon-filled porosity, fraction or percent of rock bulk volume occupied by hydrocarbons hydrocarbon resistivity index R,/R o hydrocarbon saturation, residual hydrogen index hyperbolic decline&constant (from equation)
,. I I
Letter Symbol
Reserve SPE Letter Symbol
fht
Computer Letter Symbol
ch
HANDBOOK
Dimensions
PORH
RSXH
IR s hr
phrpShr
iR
IH
iH
h
SATHR HYX HPC
q=qt/ 1,:
imaginary part of complex number z impedance impedance, acoustic impedance, electric index (use subscripts as needed) index, fracture index, free fluid index, hydrogen index, injectivity index of refraction index, porosity index, primary porosity index, productivity index, (hydrocarbon) resistivity RtIR, index, secondary porosity index, shaliness gamma ray (Ylog - Ycn)/(YstlYen) index, specific injectivity index, specific productivity individual bed thickness influx (encroachment), cumulative, gas influx (encroachment), cumulative, oil influx (encroachment), cumulative, water influx (encroachment) during an interval, gas influx (encroachment) during and interval, oil influx (encroachment) during an interval, water influx function, fluid, linear aquifer, dimensionless influx function, fluid, dimensionless (at dimensionless time to> influx (encroachment) rate influx (encroachment) rate, gas influx (encroachment) rate, oil influx (encroachment) rate, water initial condensate liquids in place in reservoir initial capital investment initial oil in place in reservoir initial pressure
9 (2)script I Z ZO ze Z If kf IH I
;, h
z,
iFf iH
i P i, Cpl
J
j
IR
jR
92
ilp2
shGR
r)
i b?IFpiF
bhGR
4
4
JS
MPO MPOA MPOE -x FRX FFX HYX IJX RFX PRX PRXPR POX RXSH
IJXS POXS THK GASE
G 4 K AGe AN, Aw,
4 We ke An, A%
OllE
Qpr~script 1
WTRE OELGASE OELOILE DELWTRE ENCLTDD
Q tLJ
QetDscript 1
ENCTQO
i
ENC ENCG ENCO ENCW NGLTI INVI OILTI PRSI
Q LtD
e
e,
‘s ‘0 L
GL
gL
eg e,
ci N Pi
L4t/m
L4t/m
PRXSE SHXGR
JS d.e ge
h
various m/L2t mL2/ tq2
L3t/m L3t/m L L3 L3 L3 ::
L3
L3/t L3/t L3/t L3/t L3 M L3 n-l/L+
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
initial reservoir free-gas volume initial solution gas/oil ratio initial water in place in reservoir initial water saturation injected gas, cumulative injected gas during an interval injected water, cumulative injected water during an interval injection rate injection rate, air injection rate, gas injection rate, water injection well bottomhole pressure, flowing injection well bottomhole pressure, static injectivity index injectivity index, specific in-place condensate liquids in reservoir, initial in-place gas in reservoir, total initial in-place oil in reservoir, initial in-place water in reservoir, initial instantaneous producing water/oil ratio intercept interest rate, effective compound (usually annual) interest rate, effective, per period interest rate, nominal annual interface or front pressure interfacial, surface tension intergranular “porosity” (space) integral, exponential -
59-33
Letter Symbol
Reserve SPE Letter Symbol
GF,
gF,
RX,
Fm
W s G;
gi
AG,
&
wi
wi
A Wi i *a ‘s ‘w
W pwr ) %,
AWi
PM I 4
Pw pi, i s
GL
gL
G N
g
P,wf
W Fwo b iM
.i Pf
n W
Y
Computer Letter Symbol GASFI
L3
GDRSI WTRTI SATWI GASI DELGASI WTRI DELWTRI
L/t2 L3
INJ INJA INJG INJW PRSIWF PRSIWS IJX IJXS NGLTI GASTI OILTI WTRTI FACWD ICP IRCE IRPE IRA PRSF SFT PDRIG
-Ei (-x)
,-I
t dt,x positive x integral, exponential, modified s
r20
EioC)
Il$dt +J$dtl, x positive
intergranular space (porosity), fraction occupied by all shales intergranular space (porosity), fraction occupied by water intermatrix space (porosity), fraction occupied by nonstructural dispersed shale intermatrix “norositv” fsnace)
Dimensions
f@h
FIGSH
few
FIGW
f qbhd
FIMSHD
+im
PORIM
;: L3 L3 L3/t L3/t L3/t L3/t m/L+ m/Lt2 L4t/m L3t/m $ L3 L3 various
m/L+ m/t2
59-34
PETROLEUM ENGINEERING
Quantity
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol INE SATOG
internal energy interstitial-oil saturation in gas cap interstitial-water saturation in gas cap interstitial-water saturation in oil band interval transit time interval transit time, apparent interval transit time/density slope (absolute value) ifscript t interval transit time, fluid t tma script interval transit time, matrix t,hscript t interval transit time, shale invaded-zone diameter, electrically equivalent 4 invaded-zone geometrical factor (multiplier) Gi (electrical logging) invaded-zone resistivity Ri invasion (vertical) efficiency: hydrocarbon pore 4 space invaded (affected, contacted) by the injected-fluid or heat front divided by the hydrocarbon pore space enclosed in all layers behind the injected-fluid or heat front irreducible (or interstitial or connate) S/W water saturation kinematic viscosity v nu kinetic energy Ek Laplace transform of y, JJJ (t)P’df
Z?,(v) script L
Laplace transform variabli Laplacian operator larger than latent heat of vaporization length, path length, or distance lifetime, average (mean life) limit linear aquifer waterdrive constant liquid fraction liquid mole fraction L/(L + V) liquid phase, mole fraction of component in liquid phase, moles of liquid saturation, combined total liquids, condensate, in place in reservoir, initial liquids, condensate, produced cumulative logarithm, base a logarithm, common, base 10 logarithm, natural, base e macroscopic cross section
s V2
SATWG SATWO TAC TACA
t/L t/L
TACF TACMA TACSH OIAI GMFI
t/L t/L t/L L
RESI EFFI
mL3/tq2
SATIW VSK ENGK
GL
SL SLP
loL; 1% In z
S
XSTMAC
fL X
mL2/ t2
tL*/m
G
CL .fL
Dimensions
SAD
GT HLTV LTH TIMAV LM WOCL FRCL MFRTL MFRL MOLL SATL NGLTI NGLP
2 LV i lim
HANDBOOK
h” s,P script 1 t F,,ffscript I FL,fu script I
L
nL
SL
PL ,SL
L*/t mL2/t2
L2/ t* L t L4t2/m
L3
l/L
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
macroscopic cross section of a nucleus magnetic permeability magnetic susceptibility magnetization magnetization, fraction mass mass flow rate matrix interval transit time matrix (solids, grain) density matrix (framework) volume (volume of all formation solids except dispersed clay or shale) mean life (average lifetime) mean life (decay time) (l/r) mean or average pressure mean or average (overbar) mean value of a random variable mean particle diameter mean value of a random variable, x, estimated mechanical force methane concentration (concentration of other paraffin hydrocarbons would be indicated similarly, Cc, , Cc, , etc.) microscopic cross section mixture, mole fraction of component mobility (k/k) mobility, gas mobility, oil mobility ratio, general (Adisplacing/hdisplaced) mobility ratio, diffuse-front approximation
59-35
Letter Symbol
s m
o: M
W
ma script t
pm0
Vma
7 Td P 2 x F %
rho
Computer Letter Symbol
Dimensions
XNL PRMM SUSM MAG MAGF MAS MRT TACMA DENMA VOLMA
L2 n-L/q* mL/q* dst
TIMAV TIMD
t t m/Lt2
Q
PRSAV AV MEN DIAAVP MENES FCE
+I
CNCCl
;
Mf m t
Reserve SPE Letter Symbol
m A&m D ma Vma i td P
4
F A Mm,
4,
L mL/t* various
XSTMIC MFRM
L2
MOB MOBG MOB0 MBR MBRSAV
L’t/m L3t/m L’t/m
[(AD +hd)swept/(hd)unswept];
D signifies displacing; d signifies displaced; mobilities are evaluated at average saturation conditions behind and ahead of front mobility ratio, sharp-front approximation
F,
MBR
FM
MBRT
A
MOBT
L3t/m
MOBW BKM DSM ELMS ELMY VOLM
L3t/m m/L+
(b/Ad)
mobility ratio, total, [(A,)swept/(AI)unsweptl; “swept” and “unswept” refer to invaded and uninvaded regions behind and ahead of leading edge of displacement front mobility, total, of all fluids in a particular region of the reservoir; e.g., (A, + A, + A,) mobility, water modulus, bulk modulus, dispersion (dispersion factor) modulus, shear modulus of elasticity (Young’s modulus) molal volume (volume per mole)
ES Y
VIII
m/L+ m/L+ L3
59-36
PETROLEUM ENGINEERING
Letter Symbol
Quantity -
Reserve SPE Letter Symbol
Computer Letter Symbol
HANDBOOK
Dimensions
-
mole fraction gas, V/(L+ v) mole fraction liquid, LI(Z,+ v) mole fraction of a component in liquid phase mole fraction of a component in mixture mole fraction of a component in vapor phase molecular refraction molecular weight molecular weight of produced liquids, mole-weighted average moles, number of moles of component j moles of component j produced, cumulative moles of liquid phase moles of vapor phase moles, number of, total mole-weighted average molecular weight of produced liquids mudcake resistivity mudcake thickness mud-filtrate resistivity mud geometrical factor (multiplier) (electrical logging) mud resistivity multiplier (factor), geometrical (electrical logging) multiplier (factor), geometrical, annulus (electrical logging) multiplier (factor), geometrical, flushed zone (electrical logging) multiplier (factor), geometrical, invaded zone (electrical logging) multiplier (factor), geometrical, mud (electrical logging) multiplier (factor), geometrical, pseudo (electrical logging) multiplier (factor), geometrical, true (electrical logging) multiplier or coefficient natural gas liquids or condensate content natural logarithm, base e net pay thickness neutron count rate neutrons, density (number) of neutron lifetime neutron porosity/density slope (absolute value) neutron [usually with identifying subscript(s)] Newton’s Second Law of Motion, conversion factor in nominal decline factor
4
FL, fp script I X z
Y
R M
N
ML n
nJ % L
V nt
N Ni NpJ nL zt
ML,
R mc hmc R mf
pmc Trmc dmc ‘ernc
MFRTV MFRTL MFRL MFRM MFRV MRF MWT MWTAVL
L3 m m
NMBM MOLJ MOLPJ MOLL MOLV NMBMT MWTAVL
m
RESMC THKMC RESMF GMFM
mL3/ tq2 L mL3/tq2
mL3/ tq*
Gttl
PmfJmf fGm
R, G
fG
RESM GMF
G0”
fGLVI
GMFAN
Gx0
fGm
GMFXO
Gi
fGi
GMFI
fGm
GMFM
GP
fGp
GMFP
Gt
fGt
GMFT
pmjrm
K
M
CL
cL,nL
In hn
4&
NN nN tN
N N gc a
TN>h mdND
COE CNTL
various various
THKN NEUN NMBN
L
NFL SND NEU GRVC DEC
l/t
l/t L3/m various
59-37
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
nucleus cross section, microscopic number, atomic number, dimensionless, in general (always with identifying subscripts) number of pump strokes, cycles per unit of time number (of variables, or components, or steps, or increments, etc.) number (quantity) number of compounding periods (usually per year) number of components number of moles, total number, Reynolds (dimensionless number) oil (always with identifying subscripts) oil band interstitial-water saturation oil compressibility oil density oil displaced from burned volume, volume per unit volume of burned reservoir rock oil displaced from unburned volume, volume per unit volume of unburned reservoir rock oil, effective permeability to oil formation volume factor oil formation volume factor at bubblepoint conditions oil, gas solubility in (solution gas/oil ratio) oil in place in reservoir, initial oil influx (encroachment) cumulative oil influx (encroachment) during an interval oil influx (encroachment) rate oil mobility oil produced, cumulative oil produced during an interval oil production rate oil production rate, dimensionless oil reciprocal formation volume factor (shrinkage factor) oil recovery, ultimate oil, relative permeability to oil saturation oil saturation in gas cap, interstitial oil saturation, residual oil specific gravity oil viscosity operating cash income operating cash income, after taxes operating cash income, before taxes operating expense operating expense per unit produced operator, Laplacian
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter
Symbol
z”
N
XNL ANM NUMO
N
NMBPS
n
NMB
L C
ke N sWV ccl p. rho 6ob
NMB NMBCP NMBC NMBM REYO OIL SATWO CMPD DEN0 DPROB
Dimensions
L*
various Lt*/ m m/L3
OPROU PRMD FVFO FVFOB
L*
GORS OILTI OILE DELOILE ENCO MOBD OILP DELOILP RTEO
L3/t L3t/m $ L3/t
RTEOQ RVFO NPQ
k s: Sw
SO, Yo ko I 4 I 0 0”
V2
DILPUL
L3
PRMRO SAT0 SATOG SATOR SPGO VISD INC INCA INCB XPO XPOU
mm
M M M various M/L3
59-38
-
PETROLEUM ENGINEERING
Quantity
overall heat transfer coefficient overall reservoir recovery efficiency: volume of hydrocarbons recovered divided by volume of hydrocarbons in place at start of project
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
uT~ u, ?RleR
HANDBOOK
Dimensions
HTCU EFFR
m/t3T
CNCOZ
various
(ER = EpEsEo = E,E,)
oxygen concentration (concentration of other elements or compounds would be indicated as CCO, , cN2, etc.) oxygen utilization particle diameter, mean path length, length, or distance pattern sweep efficiency (developed from area1 efficiency by proper weighting for varations in net pay thickness, porosity, and hydrocarbon saturation: hydrocarbon pore space enclosed behind the injected-fluid or heat front divided by total hydrocarbon pore space of the reservoir or project pay thickness, gross (total) pay thickness, net period permeability, absolute (fluid flow) permeability, effective, to gas permeability, effective, to oil permeability, effective, to water permeability, magnetic permeability ratio, gas/oil permeability ratio, water/oil permeability, relative, to gas permeability, relative, to oil permeability, relative, to water phases, number of Poisson’s ratio pore volume Vb- V, pore volume, dimensionless pore volumes of injected fluid, cumulative porosity ( Vb- V, )/ Vb porosity, apparent porosity, effective
%
E
UTLOL
02
4 s,!
script
rlP JP
1
OIAAVP LTH EFFP
L
THKT THKN PER PAM PRMG PRMO PRMW PRMM
L L
VP
PRMGO PRMWO PRMRG PRMRO PRMRW NMBP PSN VOLP
‘PD
VOLPtl
vt cl-
FLUID
4i
f> E
POR PORA PORE MXP
fht
PORH
Eh
PRX PRXPR PRXSE PORNE
L
t ;: 1: ml-/q2
L3
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
59-39
Letter Symbol
-
“porosity” (space), intergranular (Vb - VgrI/ Vb1 “porosity” (space), intermatrix (Vb - V,, / Vb) porosity of experimental pack porosity of reservoir or formation porosity, total potential or potential function potential difference (electric) potential energy pressure, bottomhole pressure pressure, atmospheric pressure, average or mean pressure, average, reservoir pressure, bottomhole, at any time after shut-in pressure, bottomhole flowing pressure, bottomhole flowing, injection well pressure, bottomhole general pressure, bottomhole static pressure, bottomhole (well), in water phase pressure, bottomhole static, injection well pressure, bubblepoint (saturation) pressure, capillary pressure, casing flowing pressure, casing static pressure, critical pressure, dewpoint pressure, dimensionless pressure, external boundary pressure, extrapolated pressure, flowing bottomhole pressure, flowing casing pressure, flowing tubing pressure, front or interface pressure function, dimensionless, at dimensionless time tD pressure, initial pressure, pseudocritical pressure, pseudoreduced pressure, reduced pressure, reservoir average pressure, separator pressure, standard conditions pressure, static bottomhole pressure, static casing pressure, static tubing pressure, tubing flowing pressure, tubing static primary porosity index produced condensate liquids, cumulative
Reserve SPE Letter Symbol
PORIG PORIM POREX PORR PORT POT VLT ENGP
4E 4R 4r a
V Ep Pbh
Pbh
P Pa F
P P_a P-
FR
pR
PW PWf PiwJ PW PWS PWW PiWS
P ws P wf Prwf p&V P ws P
pb
&,ps,pb
p””
P‘S PC
PCJPC PCJ PCS PC
Pd
pd
PD
pD
P, J+,t
PP PtW PYf
PC/ P!f PJ P/D
Pi Ppc PPl
p,
PfX, P, P;
PtD p,
PRSI
5
PPC PPr
P-’
F-R
pR
PSP
PSP
PlS P!f
PIT I $1 GLP
PRSBH PRS PRSA PRSAV PRSAVR PRSWS PRSWF PRSIWF PRSW PRSWS PRSWW PRSIWS PRSB PRSCP PRSCF PRSCS PRSC PRSD PRSD PRSE PRSXT PRSWF PRSCF PRSTF PRSF PRSTQD
prJ
P,
PS‘ PWS PCS
Computer Letter Symbol
PSC
P w.s PCS p, Pff p,s i,l gLP
PRSPC PRSPRD PRSRD PRSAVR PRSSP PRSSC PRSWS PRSCS PRSTS PRSTF PRSTS PRXPR NGLP
Dimensions
various mL*/qt* mL*/t* m/L+ m/L+ n-l/L+ m/L+ m/L+ m/Lt2 m/Lt2 m/L9 n-l/L+ m/Lt2 m/L+ m/L+ m/L+ m/L? m/L+ m/Lt2 m/L+ m/Lt2 n-l/L+ m/L+ m/L? m/Lt2 m/Lt* m/Lt2
m/Lt2 m/L? m/Lt2 n-t/L+ m/L+ m/L+ m/L? m/L+ m/L? m/L+ m/Lt2 L3
59-40
PETROLEUM ENGINEERING
Quantity
produced fluids, cumulative (where NP and Wp are not applicable) produced free gas, cumulative produced gas, cumulative produced gas during an interval produced gas from experimental tube run produced gas, wet, cumulative produced-liquid density, weight-weighted average produced moles of component j, cumulative produced oil, cumulative produced oil during an interval produced water, cumulative produced water during an interval produced wet gas, cumulative producing gas/oil ratio producing gas/oil ratio, free (free-gas volume/oil volume) producing water/oil ratio, instantaneous production rate at beginning of period production rate at economic abandonment production rate, dimensionless production rate, gas production rate, gas, dimensionless production rate, oil production rate, oil, dimensionless production rate or flow rate production rate or flow rate at mean pressure production rate or flow rate, average production rate, water production rate, water, dimensionless production time after well is opened to production (pressure drawdown) production time of well, equivalent, before shut-in (pseudotime) productivity index profit, annual net, over year k profit, annual, over year k, fraction of unamortized investment profit, total proportional to productivity index, specific pseudocritical temperature pseudocritical pressure pseudogeometrical factor (multiplier) (electrical logging) pseudoreduced compressibility pseudoreduced pressure pseudo-SP
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
QP
FLIJP
GFP GP AGP GPE G %P
GASFP GASP OELGASP GASPEX GASWGP
FL rho
DENAVL
HANDBOOK
Dimensions
MOLPJ OILP DELOILP WTRP OELWTRP GASWGP GOR GORF FACWO RTEI RTEA RTED RTEG RTEGG RTEO RTEOQ RTE RTEPAV RTEAV RTEW RTEWG DELTIMWF
L3/t L3/t L3/t L3ft L3/t L3/t L3/t L3/t t
TIMP
t
POX PRAK PRAPK
L4t/m M
PRFT
M
POXS TEMPC PRSPC GMFP
L3t/m T m/Lt2
CMPPRD PRSPRD EMFP
mL*/qt*
59-41
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
Dimensions
-
pseudoreduced temperature pseudotime (equivalent time well was on production before shut-in) pump strokes, number of cycles per unit of time quality (usually of steam) radial distance (increment along radius) radiation heat transfer coefficient radius radius, apparent or effective, of wellbore (includes effects of well damage or stimulation) radius, dimensionless radius, external boundary radius, hydraulic radius of drainage radius of wellbore, apparent or effective (includes effects of well damage or stimulation) radius of well damage or stimulation (skin) radius, well rate, air injection rate: discount, effective profit, of return, reinvestment, etc; use symbol iwith suitable subscripts rate, flow or production rate, gamma ray count rate, gas influx (encroachment) rate, gas injection rate, gas production rate, gas production, dimensionless rate, influx (encroachment) random variable, mean value of x, estimated rate, injection rate, interest, effective compound (usually annual) rate, interest, effective, per period rate, interest, nominal annual rate, mass flow rate of flow or flux, per unit area (volumetric velocity) rate of heat flow rate of return (internal, true, or discounted cash flow) or earning power rate, oil influx (encroachment) rate, oil production rate per unit area, flow (volumetric velocity) rate, oil production, dimensionless rate, production or flow rate, production, at mean pressure rate, production, average rate, production, dimensionless rate, segregation (in gravity drainage)
TEMPRD TlMP
TPr tp
N
n
fs
QJ AR
Ar I r ‘-WI
R R wll
rD
RD
re
R,
rH
RH
rd
Rd
rwa
zT,z~
R wa
rw
RS RW
‘a i
4
rs
Q N&G
‘8
8D
i
iM j W u
Q 1,
r m dJ
T t
NMBPS OLTS OELRAD HCTI RAD RADWA
klh3T L L
RADa RAOE RAOHL RAOD RADWA
L L L L
RAOS RADW 1NJA RTE
L L L3/t
RTE NGR ENCG INJG RTEG RTEGa ENC MENES
L3/t l/t L3/t L3/t L3/t
INJ IRCE
L3/t
IRPE IRA MRT VELV
L3/t
m/t Lit
HRT RORl
mL2/i3
ENCO RTEO VELV RTEOa RTE RTEPAV
L3/t L3/t
RTEAV RTEa RTES
Lit
L3/t L3/t L3/t L3/t
PETROLEUM ENGINEERING
59-42
Quantity
Letter Symbol
-
rate, shear rate (velocity) of burning-zone advance rate, water influx (encroachment) rate, water injection rate, water production rate, water production, dimensionless ratio, air/fuel ratio, damage (“skin” conditions relative to formation conditions unaffected by well operations) ratio, displacement ratio, displacement, oil from burned volume, volume per unit volume of burned reservoir rock ratio, displacement, oil from unburned volume, volume per unit volume of unburned reservoir rock ratio, displacement, water from burned volume, volume per unit volume of burned reservoir rock ratio, equilibrium (v/x) ratio, free producing gas/oil (free-gas volume/oil volume) ratio, gas/oil, cumulative ratio, gas/oil, initial solution ratio, gas/oil permeability ratio, gas/oil producing ratio, gas/oil, solution, at bubblepoint conditions ratio, gas/oil, solution (gas solubility in oil) ratio, mobility, general (Adisplaclng/Adisplaced) ratio, mobility,diffuse-front approximation [(AD
Reserve SPE Letter Symbol
Computer Letter Symbol
HANDBOOK
Dimensions
SRT
1/t
VELB ENCW INJW RTEW RTEWII FACAFU DMRS
L/t
L3/t L3/t L3/t various
DPR DPROB
DPROU
OPRWB EllR GORF
K RF
MS
GORP GORSI PRMGO GOR GORSB GORS MBR MBRSAV
M
MBR
RI, Rsi kg /ko
R R.sb RS M
+ hd)swepJ(Ad)unsweptl;
D signifies displacing; d signifies displaced;
mobilities are evaluated at average saturation conditions behind and ahead of front ratio, mobility, sharp-front approximation (AD/&~)
ratio, mobility, total [(A,jSWePt/ (A,)unsweptl; “swept” and “unswept” refer to invaded and uninvaded regions behind and ahead of leading edge of a displacement front ratio of initial reservoir free-gas volume to initial reservoir oil volume ratio or factor in general (always with identifying subscripts) ratio, permeability, gas/oil ratio, producing gas/oil ratio, permeability, water/oil ratio, solution gas/oil, at bubblepoint conditions ratio, solution gas/oil (gas solubility in oil)
MBRT
m
F~orF.o
MGO
F
A,R,r
FAC PRMGO GOR PRMWO GORSB GORS
various
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity -
ratio, solution gas/oil, initial ratio, water/fuel ratio, water/oil, cumulative ratio, water/oil permeability ratio, water/oil, producing, instantaneous reactance reaction rate reaction rate constant real part of complex number z reciprocal formation volume factor, volume at standard conditions divided by volume at reservoir conditions (shrinkage factor) reciprocal gas formation volume factor reciprocal gas formation volume factor at bubblepoint conditions reciprocal permeability reciprocal oil formation volume factor (shrinkage factor) recovery efficiency, reservoir overall; volume of hydrocarbons recovered divided by volume of hydrocarbons in place at start of project. (ER =EpE/ED
59-43
Letter Symbol
F U’F F WQP
FACWFU FACWOP PRMWO FACWO XEL
ML2/tq2
RRR
m/L2
r,j
RRC
L/t
.fJ
RVF
Kw 14,
kc lk,
F x”” R k b
Dimensions
Fgsi
RN
X(z)
Computer Letter Symbol
script
R
4 bc@
RVFG RVFGB
j bo
RVFO
l/L2
ER
7)R peR
GPa
gPa
EFFR
= E,ED)
recovery, ultimate gas reduced pressure reduced temperature reduction ratio or reduction term reduction, SP (general) due to shaliness refraction, molecular refraction index reduction ratio, SP, due to shaliness relative amplitude relative atomic mass (atomic weight) relative bearing relative density (specific gravity) relative molecular mass (molecular weight) relative permeability to gas relative permeability to oil relative permeability to water relaxation time, free-precession decay relaxation time, proton thermal requirement, air requirement, unit air, in laboratory experimental run, volumes or air per unit mass of pack requirement, unit air, in reservoir, volumes of air per unit bulk volume of reservoir rock reservoir initial free-gas volume
P, 7,
or formation porosity pressure, average recovery efficiency, overall; of hydrocarbons recovered divided
p, Qr
a!
N CL
Y
SF,
GASPUL PRSRO TEMRO RED REDSP MRF RFX REOSH AMPR AWT BRGR SPG MWT PRMRG PRMRO PRMRW TIMAV TIMRP AIR AIREX
t t
L3/m
AIRR
aR
GASFI
GF,
gFi
4JR
~RJ -
FR
pR
ER
77RpeR
(=mNBoi )
reservoir reservoir reservoir volume
Reserve SPE Letter Symbol
ER
L3
PORR PRSAVR EFFR
m/L9
59-44
PETROLEUM ENGINEERING
Quantity -
by volume of hydrocarbons in place at start of project (& = Ep E, ED = E, ED ) reservoir rock burned, volume of reservoir rock unburned, volume of reservoir temperature residual gas saturation residual hydrocarbon saturation residual oil saturation residual water saturation resistance resistivity, electrical (logging) resistivity, electrical (other than logging) resistivity, annulus resistivity, apparent resistivity, apparent, of the conductive fluids in an invaded zone (due to fingering) resistivity factor coefficient, formation (FR4”) resistivity factor, formation, equals I? o/R,+ a numerical subscript to F indicates the R, resistivity flushed zone (that part of the invaded zone closest to the wall of the borehole, where flushing has been the maximum) resistivity, formation 100% saturated with water of resistivity R, resistivity, formation, true resistivity index (hydrocarbon) equals R,/R, resistivity, invaded zone resistivity, mud resistivity, mudcake resistivity, mud-filtrate resistivity, shale resistivity, surrounding formation resistivity, water revenue, gross (“value”), per unit produced revenue, gross (“value”), total Reynolds number (dimensionless number) rock or formation compressibility salinity saturation saturation exponent saturation, gas saturation, gas, critical saturation, gas, residual saturation, interstitial-oil, in gas cap saturation, interstitial-water, in gas cap saturation, hydrocarbon
Letter Symbol
VRb vRu TR su s hr
S0, S UT
Reserve SPE Letter Symbol
Computer Letter Symbol
VOLRB VOLRU TEMR SATGR SATHR SATOR SATWR RST RES RHO
HANDBOOK
Dimensions
$ T
RO RZ
RESAN RESA RESZ
ML2/tq2 mL3/ tq* mL3/tq2 mL3/tq2 mL3/ tq* mL3/tq2
KR
COER
mL3/tq2
FR
FACHR
R x0
RESXO
mL3/ tq2
Ro
RESZR
mL3/tq2
R,
REST RSXH RESI RESM RESMC RESMF RESSH RESS RESW GRRU GRRT REYO CMPF
mL3/tq2
i? P
R an
1, R, R,
R mc R ml R,h 4 RW vu V NRe c/ c S
CNC SAT SXP SATG SATGC SATGR SATOG SATWG SATH
mL3/tq2 mL3/tq2 mL3/tq2 mL3/ tq* mL3/ tq2 mL3/ tq2 mL3/tq2 M/L3 M Lt2/m various
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
59-45
Letter Symbol
Reserve SPE Letter Symbol
Computer Letter Symbol
Dimensions
-
saturation, residual hydrocarbon saturation, oil saturation, oil, residual saturation or bubblepoint pressure saturation, total (combined) liquid saturation, water saturation, water, critical saturation, water, initial saturation, water (irreducible, interstitial, or connate) saturation, water, residual secondary porosity index segregation rate (in gravity drainage) separator pressure shale interval transit time shale resistivity shaliness gamma ray index hog - ro)l (Ysh- ro) shear modulus shear rate shear wave amplitude shrinkage factor (reciprocal oil formation volume
Shr
SATHR SAT0 SATOR PRSB SATL SATW SATWC SATWI SATIW
SO
S Pi
SL SM.
S, $7 s,,
S wr I 62 4s
P iz script t Rsh IshGR
SATWR PRXSE RTES PRSSP TACSH RESSH SHXGR
m/L+
L3/t m/Lt2 t/L mL3/tq2
m/Lt2 l/t various
bo
ELMS SRT AMPS RVFO
PW At,,
PRSWS OELTIMWS
m/L+ t
DSP
OSCSP OSCSPC
G 3;s
factor)
shut-in bottomhole pressure, at any time shut-in time (time after well is shut in) (pressure buildup) single-payment discount factor single-payment discount factor (constant annual rate) skin depth (logging) skin effect skin radius (radius of well damage or stimulation) slope slope, interval transit time vs. density (absolute value) slope, neutron porosity vs. density (absolute value) smaller than solid particles density of experimental rock solid(s) volume (volume of all formation solids) solids (matrix, grain) density solubility, gas in oil (solution gas/oil ratio) solubility, gas in water solution gas/oil ratio at bubblepoint conditions solution gas/oil ratio (gas solubility in oil) solution gas/oil ratio, initial SP, electrochemical component of SP, electrokinetic component of SP (measured SP) (Self Potential) SP, pseudo
DSPC
N < POE
rho
K pm0
r h0
&
R SW Rsb R* 4, EC 6 ESP
EPSP
SK0 SKN RAOS SLP SAD
L various L various tL2/m
SND
L3/m
LT OENSEX VOLS OENMA GORS GWRS GORSE GORS GORSI EMFC EMFK EMFSP EMFPSP
m/L3 L3 m/L3
mL2/t2q mL2/t2q mL2/t2q mL2/t2q
59-46
PETROLEUM ENGINEERING
HANDBOOK
Reserve
SPE Quantity SP,
Letter Symbol
static (SSP) ESSP spacing (electrical logging) LS 3 specific entropy specific gravity (relative density) Y specific gravity, gas Y8 specific gravity, oil Yo specific gravity, water Yw specific heat capacity (always with phase or c system subscripts) specific heat capacity ratio specific injectivity index I specific productivity index J, V specific volume specific weight F WV SSP (static SP) ESSP stabilization time of a well ts standard deviation of a random variable CT standard deviation of a random variable, estimated s static bottomhole pressure, injection well Piw static pressure, bottomhole, PWS at any time after shut-in static pressure, casing PCS static pressure, tubing PfS stimulation or damage radius of well (skin) rs storage or storage capacity s strain, normal and general E epsilon strain, shear Y strain, volume 8 stream function * stress, normal and general ostress, shear 7 summation (operator) z superficial phase velocity (flux rate of a IA particular fluid phase flowing in pipe; use appropriate phase subscripts) surface production rate 9sc surface tension, interfacial surrounding formation resistivity E k susceptibility, magnetic temperature T temperature, bottomhole Tbh temperature, critical T, temperature, formation Tf temperature gradient gT temperature, pseudocritical TPC temperature, pseudoreduced TPr temperature, reduced T, temperature, reservoir TR temperature, standard conditions CC tension, surface (interfacial) u
Letter Symbol
Computer Letter Symbol EMFSSP LENS HERS SPG SPGG SPGO SPGW HSP HSPR IJXS PDXS SPV WGTS EMFSSP TIMS SDV suvEs
Dimensions
mL2/ t*q L L2/t2T
L2/t2T
L3t/m L3t/m L3/m mL2/t2 mL2/t2q t
PRSIWS PRSWS
m/L? m/L?
PRSCS PRSTS RADS ST0 STN STNS STNU STR STS STSS SUM VELV
m/L+ rn/Lt2 L various
RTESC SFT RESS SUSM TEM TEMBH TEMC TEMF GRDT TEMPC TEMPRD TEMRO TEMR TEMSC SFT
various m/L+ m/L+ L/t
L3/t m/t2 mL3/tq2 mL/q2 T T T T T/L T T T T T m/t2
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
59-47
Letter Symbol
-
tensor of x thermal conductivity (always with additional phase or system subscripts) thermal cubic expansion coefficient thermal or heat diffusivity thickness (general and individual bed) thickness, gross pay (total) thickness, mudcake thickness, pay, gross (total) thickness, net pay time time after well is opened to production (pressure drawdown) time after well is shut in (pressure buildup) time constant time, decay (mean life) (l/ A) time, delay time difference (time period or interval, fixed length) time, dimensionless time, dimensionless at condition m time for stabilization of a well time, interval transit time, interval transit, apparent time, interval transit, fluid time, interval transit, matrix time, interval transit, shale time, neutron decay (neutron mean life) time, payout (payoff, payback) time period or interval, fixed length time well was on production before shut-in, equivalent (pseudotime) tortuosity tortuosity, electric tortuosity, hydraulic total (combined) liquid saturation total entropy total mobility of all fluids in a particular region of the reservoir; e.g., (A, + A*+ A, ) total mobility ratio [(Ar)swepJ(Ar)unsweptl; “swept” and “unswept” refer to invaded and uninvaded regions behind and ahead of leading edge of a displacement front total (gross) pay thickness total gross revenue (‘value”) total initial gas in place in reservoir total moles total porosity total (two-phase) formation volume factor
Reserve SPE Letter Symbol
Computer Letter Symbol
Dimensions
z X kt,
HEN
mL/t3T
hmc
HEC HTD THK THKT THKMC THKT THKN TIM DELTIMWF
l/T L2/t L L L L L
h hn t At, At, 7 Td b
At tD tDm ts
tscript t t, script t -If script t i m. script t k,, script t tdN iP
At b 7 Te 7H SL s At
t
t
DELTIMWS TIMC TIMD TIMD DELTIM
t t t t t
TIMQ TIMMQ TIMS TAC TACA TACF TACMA TACSH TIMDN TIMPO DELTIM TIMP
t t/L t/Jt/L t/L t/L t t t t
TOR TORE TDRHL SATL HER MDBT
L2/tZT L3t/m
MBRT
ht
V G 3, 4
THKT GRRT GASTI NMBM PORT FVFT
L M
L3
59-48
PETROLEUM ENGINEERING
Quantity
Letter Symbol
-
transfer coefficient, convective heat transfer coefficient, heat, overall transfer coefficient, heat, radiation transit time, interval transit time, apparent, interval transit time, fluid interval transit time, matrix interval transit time, shale interval
h u I k script t in script t if script r i ma script t ksh scripr t
transform, Laplace 0fyT.Y (t )P’dt
$0)
transform, Laplace, var:able transmissivity, transmissibility true density true formation resistivity true geometrical factor (multiplier) (noninvaded zone) (electrical logging) tubing pressure, flowing tubing pressure, static turbulence factor two-phase or total formation volume factor ultimate gas recovery unamortized investment over year k undiscounted cash flow unburned reservoir rock, volume of unit air requirement in laboratory experimental run, volumes of air per unit mass of pack unit air requirement in reservoir, volumes of air per unit bulk volume of reservoir rock unit fuel concentration (see symbol m) universal gas constant (per mole) utilization, oxygen valence vapor phase, mole fraction of component vapor phase, moles of vaporization, latent heat of variance of a random variable variance of a random variable, estimated vector of x velocity velocity, acoustic velocity, acoustic apparent (measured) velocity, acoustic fluid velocity, matrix acoustic velocity, shale acoustic velocity (rate) of burning-zone advance vertical (invasion) efficiency: hydrocarbon pore space invaded (affected, contacted) by the injected-fluid or heat front divided by the
s T
Reserve SPE Letter Symbol
Computer Letter Symbol
T 4 wf .fGf
PV PIS
p,r PI,
FB 4
4
60
gPa
Gk
HTCC HTCU HTCI TAC TACA TACF TACMA TACSH
m/t3T rn/t’T m/t3T t/Jot/L t/L t/L
TRM DENT REST GMFT
various m/L3 mL3/tq2
PRSTF PASTS FACB FVFT
m/L+ m/Lt=
GASPUL INVUK
L3
P VRU
VRll
aE
F OE
VOLRU AIREX
aR
F UR
AIRR CNCFU RRR UTLOZ
G R eo2 Z Y
V
S2
Dimensions
script L
Pr 4 G,
L” c=
HANDBOOK
A”
VAL MFRV MOLV HLTV VAR VARES
M L3 L3/m
various mL2/t2T
L2/ t=
2 V V VC2 Vf %I, vsh vb El
VEL VAC VACA VACF VACMA VACSH VELB EFFI
L/t L/t L/t L/t L/t L/t L/t
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
-
hydrocarbon pore space enclosed in all layers behind the injected-fluid or heat front viscosity, air viscosity at mean pressure viscosity, dynamic viscosity, gas viscosity, gas, at 1 atm viscosity, kinematic viscosity, oil viscosity, water volume volume at bubblepoint pressure volume, bulk volume, bulk, of pack burned in experimental run volume, effective pore volume fraction or ratio (as needed, use same subscripted symbols as for “volumes”; note that bulk volume fraction is unity and pore volume fractions are +I volume, free-gas, initial reservoir (=mNb,; )
volume, grain (volume of all formation solids except shales) volume, intergranular (volume between grains; consists of fluids and all shales)
59-49
Reserve SPE Letter Symbol
Letter Symbol
Computer Letter Symbol
VISA VISPAV
Dimensiona
m/Lt mm m/Lt mm m/Lt
VIS VISG VISGA VSK visa VISW VOL VOLBP VOLB VOLBEX
L3
V
VOLG VLF
L3 various
GFi
GASFI
L3
Vgr
VOLGR
L3
VOLIG
L3
vim
VOLIM
L3
Vma
VOLMA
K
L2/t m/Lt gLt $
volume, intermatrix (consists of fluids and dispersed shale) (vb - V,,,,> volume, matrix (framework) (volume of all formation solids except dispersed shale) volume, noneffective pore (VP-V, ) volume of reservoir rock burned volume of reservoir rock unburned volume per mole (molal volume) volume, pore (Vb-V,) volume, pore, dimensionless volume, shale, dispersed volume, shale, laminated volume, shale, structural volume, shale(s) (volume of all shales: structural and dispersed) volume, solid(s) (volume of all formation solids) volume, specific volumetric efficiency for burned portion only, in-situ combustion pattern volumetric efficiency: product of pattern sweep and invasion efficiencies
Vne
VOLNE VOLRB VOLRU VOLM VOLP
vRb vRu VM VP
VPD Vshd Vshs Vsh
VOLPQ VOLSHO VSHLAM VOLSHS VOLSH
VS
VOLS
V
SPV
EVb
EFFVB
Ev
EFFV
vxhf
script
i
L3/m
59-50
PETROLEUM ENGINEERING
HANDBOOK
Reserve
-
Letter Symbol
Quantity
-
volumetric flow rate volumetric flow rate downhole volumetric flow rate, surface conditions volumetric heat capacity volumetric velocity (flow rate or flux, per unit area) water (always with identifying subscripts) water compressibility water density water displaced from burned volume, volume per unit volume of burned reservoir rock waterdrive constant waterdrive constant, linear aquifer water, effective permeability to water formation volume factor water/fuel ratio water, gas solubility in water in place in reservoir, initial water influx (encroachment), cumulative water influx (encroachment) during an interval water influx (encroachment) rate water injected, cumulative water injected during an interval water injection rate water mobility water/oil permeability ratio water/oil ratio, cumulative water/oil ratio, producing, instantaneous water produced, cumulative water produced during an interval water production rate water production rate, dimensionless water, relative permeability to water resistivity water saturation water saturation, critical water saturation, initial water saturation (interstitial) in oil band water saturation in gas cap, interstitial water saturation, interstitial, connate, or irreducible water saturation, residual water specific gravity water viscosity wave length (l/cr) wave number (l/h) weight (gravitational) weight-weighted average density of produced liquid weight, atomic
SPE Letter Symbol
Computer Letter Symbol RTE
4
RTEOH RTESC HSPV VELV
qdh 4sc
M U
WTR CMPW DENW DPRWB WDC WDCL PRMW FVFW FACWFU GWRS WTRTI WTRE DELWTRE ENCW WTRI DELWTRI INJW MOBW PRMWO FACWOP FACWO
Dimensions
L3/t L3/t L3/t m/Lt2T L/t various Lt2/m m/L3
L4t2/m L4t2/m L2 various LI L3 $lt L3 L3/t L3t/m
WTRP DELWTRP RTEW RTEWQ PRMRW RESW SATW
mL3/tq2
SATWC SATWI SATWO SATWG SATIW
S NV Yw PN’ A oW PL
A
rho
SATWR SPGW visw WVL WVN WGT DENAVL
L l/L m/Lt2 dL3
AWT
m
m/I-t
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Quantity
weight, molecular well radius well radius of damage or stimulation (skin) well stabilization time wellbore radius, effective or apparent (includes effects of well damage or stimulation wet-gas content wet gas produced, cumulative width, breadth, or thickness (primarily in fracturing) work Young’s modulus (modulus of elasticity) zone diameter, invaded, electrically equivalent zone resistivity, invaded
59-51
Letter Symbol
Reserve SPE Letter Symbol
RV Rs Ts
R wo Cw G+%P b W E 4 Ri
C dhg g
WkTP
W
Computer Letter Symbol
Dimensions
MWT RADW RADS TIMS RADWA
m L L
CNTWG GASWGP WTH
various L3
WRK ELMY DIAI RESI
mL2/ t2 m/L+ L mL3/ tq2
:.
L
PETROLEUM ENGINEERING
59-52
HANDBOOK
Subscript Definitions in Alphabetical Order
Subscript
Definition
abandonment acoustic activation log, neutron active, activity, or acting after taxes air air/fuel altered amplitude log angle, angular, or angular coordinate anhydrite anisotropic annulus apparent (from log readings; use tool description subscripts) apparent (general) apparent wellbore (usually with wellbore radius r,) area1 atmosphere, atmospheric average or mean pressure average or mean saturation band or oil band bank or bank region base before taxes bond log, cement borehole televiewer log bottomhole bottomhole, flowing (usually with pressure or time) bottomhole, static (usually with pressure or time) boundary conditions, external breakthrough bubble bubblepoint conditions, oil at (usually with formation volume factor, Bob) bubblepoint conditions, solution at (usually with gas/oil ratio, Rsb) bubblepoint (saturation) bubblepoint or saturation (usually with volume, I/bJ bulk (usually with volume, VL,) burned in experimental tube run (usually with volume, V& burned or burning burned portion of in-situ combustion pattern, displacement from (usually with efficiency, Em) burned portion of in-situ combustion pattern, volumetric of (usually with efficiency, Em)
Letter Subscript
a iA
Reserve SPE Subscript
Computer Letter Subscript
A A tcY na
A A NA A A A AFU A A THE AH ANI AN
a a
a
A
aF ; 0 anh ani an
a
a wa A a
w
P s b b b b CB TV bh Wf ws ilT b ob
AN
A --
$1P
B
r* P B cb tv w,BH
xt
sb
A WA A A PAV SAV B B B B CB TV BH WF ws E BT B OB SB
b bp
s, bp
BP BP
b bE
B,t
B BEX
b Db
B
B DB
Vb
VB
59-53
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Subscript
Definition
burned reservoir rock burned volume, oil from (usually with displacement ratio, Sob) burned volume, water from (usually with displacement ratio, &+b) calculated caliper log capillary (usually with capillary pressure, PC) capture carbon dioxide carbon monoxide casing or casinghead casing, flowing (usually with pressure) casing, static (usually with pressure) cement bond log chemical chlorine log clay clean coil compaction compensated density log compensated neutron log component(s) component j component j produced (usually with moles, nP,) compressional wave conditions for infinite dimensions conductive liquids in invaded zone connate (interstitial, irreducible) constant contact (usually with contact angle, Bc) contact log, microlog, minilog convective conversion (usually with conversion factor in Newton’s law of motion, g,) core corrected critical cumulative influx (encroachment) cumulative injected cumulative produced cumulative produced free value (usually with gas, GF~) cumulative produced liquid (usually with condensate, CL,) damage or damaged (includes “skin” conditions) decay
-
Letter Subscript
Reserve SPE Subscript
Computer Letter Subscript
Rb ob
RB OB
wb
WB
C C C
talc C
C
cap (32 co c
cf
cg
CS
CB
cb
C
CL
Cl
Cl
da
cn C
cln
cP CD CN C
C
cd cn
j Pj
CA C CP c co2 co CS CF cs CB C CL CL CN C CP CD CN C J PJ
C INF
C INF Z
ir, 1 iota, i Script i
IR
C
C C
C C
ML
ml script 1
ML C C
C
FP
C cot7 CR E I P FP
LP
LP
zi
S 0
C
c-2 Z
i C
C
C
COT C
e i P
cr i
PETROLEUM ENGINEERING
59-54
Subscript
Definition
deep induction log deep laterolog delay density density log, compensated density log depleted region, depletion dewpoint differential separation differential temperature log diffusivity dimensionless pore value (usually with volume, I/pD) dimensionless quantity dimensionless quantity at condition m dimensionless time dimensionless water dip (usually with angle, LYE) diplog, dipmeter directional survey dirty (clayey, shaly) discounted value, present worth, or present value dispersed dispersion displaced displacement from burned portion of in-situ combustion pattern (usually with efficiency, Em) displacement from unburned portion of in-situ combustion pattern (usually with efficiency, ED,)
displacing or displacement (efficiency) dolomite downhole drainage (usually with drainage radius, rd) dual induction log dual laterolog earth effective (or equivalent) electric, electrical electrochemical electrode electrokinetic electrolog, electrical log, electrical survey electromagnetic pipe inspection log electron empirical encroachment (influx). cumulative
Letter Subscript
Reserve SPE Subscript
ID LLD d
id PPdscript I1 6
CD D d d d DT
cd d s
dt
rl PD D Dm tD WD d DM DR 4 PV d K d Db
dm dr dty PV D d s,D
HANDBOOK
Computer Letter Subscript IO LLO II RHO CD II D D 0 OT ETA Pa a QM TO wa 0 DM OR OY PV D K DO OB
Du
DU
D dol dh d DI DLL e e e
DN DL DH D 01 DLL E E E C E K EL
; k EL EP el E e
DH di dPPscript 11 E E ec e ek el, ES ep
4P script el EM
EP E EM E
59-55
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Subscript
Definition
entry epithermal neutron log equivalent estimated ethane experimental experimental value per mole of produced gas (usually with fuel consumption, m,) external, outer boundary conditions extrapolated fast neutron log fill-up finger or fingering flash separation flowing bottomhole (usually with pressure or time) flowing casing (usually with pressure) flowing conditions, injection well (usually with pressure, P iwf> flowing conditions, well (usually with time) flowing tubing (usually with pressure) fluid fluids in an invaded zone, conductive flushed zone formation 100% saturated with water (used in R. only) formation (rock) formation, surrounding fraction or fractional fracture, fractured, or fracturing free (usually with gas or gas/oil ratio quantities) free fluid free value, cumulative produced, (usually with gas, GF/,) free value, initial (usually with gas, GF,) front, front region, or interface fuel, mass of (usually with fuel concentration, C,, ) fuel (usually with fuel properties, such as pi) gamma-gamma ray log gamma ray log gas gas at atmospheric conditions gas at bubblepoint conditions gas cap, oil in (usually with saturation, S,) gas cap, water in (usually with saturation, S,,) gas, dimensionless gas/oil, solution (usually with gas/oil ratios) gas/water, solution (usually with gas solubility in water, I?,,) geometrical
Letter Subscript
Reserve SPE Subscript E
f;,E e4 E c2
PV est
E &
EX
e
0
ext NF f f
nf f F F
wf Cf iwf
wf
f
tf f
fl
Z
x0 0 zero
zr
f
fm
; f
F Ff FP
Fi f
F
F”
GG CR g w gb a w gD
gg gr G
Computer Letter Subscript E NE EV ES C2 EX EXG E XT NF F F F WF CF IWF WF TF F Z x0 ZR F S F FR F FF FP FI F FU FU GG GR G GA GB
SW
OG WG Ga S SW
G
G
S
PETROLEUM
59-56
Letter Subscript
Definition
geothermal grain grain (matrix, solids) gravity meter log gross (total) guard log gypsum half heat or thermal heavy phase hole horizontal hydraulic hydrocarbon hydrogen nuclei or atoms hydrocarbon, residual hydrogen sulfide imbibition induction log, deep investigation induction log induction log, dual induction log, medium investigation infinite dimensions, conditions for influx (encroachment), cumulative initial conditions or value initial free value (usually with gas, G,+-,) initial solution (usually with gas/oil ratio, R,V,) injected, cumulative injection, injected, or injecting injection well, flowing conditions (usually with pressut=, phf) injection well, static conditions (usually with p-sure, pi,> inner, interior, or internal interface, front region, or front interference intergranular intermatrix internal interstitial intrinsic invaded invaded zone invaded zone, conductive liquids in an invasion (usually with invasion efficiency, 4 1 irreducible, interstitial, or connate jth component jth component, produced (usually with moles, np;) junction
-
Subscript G gr ma GM G gYP l/2 h HP h H H h H hr HIS I ID 1 Dl IM 00
ENGINEERING
Reserve SPE Subscript
HANDBOOK
Computer Letter Subscript
T
gm T g
T, 8 hp H h H
i script i id i di im i
Fi si
GT GR MA GM T G GY H HT HP H H HL H HY HR H2S I IO I Ill IM INF E I FI SI
iwf
I I IWF
iWS
IWS
I inj
f I
L,i script i F i, i script i
jg im i,i script i script i
1,i
int I I I j P.i
i ir, L,i script i
I F I IG IM I I I I I 2 I IR J PJ J
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Subscript
Definition
laminar laminated, lamination lateral (resistivity) log laterolog (add further tool configuration subscripts as needed) laterolog, dual lifetime log, neutron, TDT light phase limestone limiting value linear, lineal liquid or liquid phase liquids, conductive, invaded zone liquid produced, cumulative (usually with condensate, GLp) location subscripts, usage is secondary to that for representing times or time periods loI? lower magnetism log, nuclear mass of fuel (usually with fuel concentration, cm ) matrix (solids, grain) matrix [solids except (nonstructural) clay or shale] maximum mean or average pressure mean or average saturation medium investigation induction log methane microlaterolog microlog, minilog, contact log microseismogram log, signature log, variable density log minimum mixture mobility molal (usually with volume, V$,,) Mth period or interval mud mudcake mud filtrate net neutron neutron activation log neutron lifetime log, TDT neutron log, compensated neutron log neutron log, epithermal
59-57
Letter Subscript
Reserve SPE Subscript
Computer Letter Subscript
Pscript 1 Pscript 1 L LL
L L P script I PP script I1
LAM LAM L LL
DLL NL LP is
d@ script II nk?script 1 Fp script I 1st
DLL NL LP LS LM L L 2 LP
lim L L
P script 1 I script I
LP
1, 2, 3, etc.
log
P script I NM m
1% L nm
L L NM FU
ma ma
MA MA
max im
MX PAV SAV IM
m@ script II mP script 1 vd
Cl MLL ML VD
F s
IM Cl MLL ML VD
St P
min M A M M m mc
z,m M m
mJ lb NA NL CN N NE
n na nP script I Ctl
n ne
MN M LAM M M M MC MF N N NA NL CN N NE
59-58
PETROLEUM ENGINEERING
Subscript
Definition
neutron log, fast neutron log, sidewall neutron log, thermal nitrogen noneffective nonwetting normal normal (resistivity) log (add numerical spacing to subscript to N; e.g., N16) normalized (fractional or relative) nth year, period, income, payment, or unit nuclear magnetism log numerical subscripts (intended primarily to represent times or time periods; available secondarily as location subscripts or for other purposes) observed
oil at bubblepoint conditions (usually with formation volume factor, Bob) oil, dimensionless oil (except when used with resistivity) oil from burned volume (usually with displacement ratio, 6,,/,1 oil from unburned volume (usually with displacement ratio, 6,,,,1 oil in gas cap (usually with saturation, S,,,) outer (external) boundary conditions oxygen particle (usually with diameter, dp) particular period, element, or interval pattern (usually with pattern efficiency, EP) payout, payoff, or payback permeability phase or phases pipe inspection log, electromagnetic pore (usually with volume, I$) pore value, dimensionless (usuallywith volume, I',?,, 1 porosity porosity data pressure, mean or average primary produced produced componentj (usually with moles, n,,i) produced, cumulative produced free value, cumulative (usually with gas, G,,, ) produced in experiment produced liquid, cumulative (usually with condensate, Cl.,,)
Letter Subscript NF SN NT
Reserve SPE Subscript
nf
sn nt
HANDBOOK
Computer Letter Subscript NF SN NT
N2
N2
ne nw
NW
k
n
n
r,R N
hl
nm
NE NW N N N N NM
1,2,3, etc.
OB ob
OB OB
OD 0
N
00 0
ob
08
011
ou
og e
OG 0
E
02
02
41
P K P PO K P EP P PQ PHI P PAV PR P PJ P FP
PE LP
PEX LP
P k P P k P EP P PD 4 4 P
1 one P pj P
K PO
ep
P
pm
P
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Subscript
Definition
produced water/oil (cumulative) (usually with cumulative water/oil ratio, F,,) production period (usually with time, tp) profit - unamortized investment proximity log pseudo pseudocritical pseudodimensionless pseudoreduced pseudo-SP radius, radial, or radial distance rate rate of return ratio recovery (usually with recovery efficiency, ER) reduced reference relative reservoir reservoir rock, burned reservoir rock, unburned residual residual hydrocarbon resistivity resistivity log Reynolds (used with Reynolds number only, NKJ rock (formation) sand sandstone saturation, mean or average saturation or bubblepoint saturation or bubblepoint (usually with volume, Vbp) scattered, scattering secondary segregation (usually with segregation rate, 4%) separator conditions shale shallow laterolog shear shear wave sidewall sidewall neutron log signature log, microseismogram log, variable density log silt single payment
59-59
Letter Subscript
Reserve SPE Subscript
Computer Letter Subscript WOP
WOP P
P Pk P
P
P PC PD pr PSP r
H
P PK P P PC PO PRO PSP R
R
R
R z R r r k Rb Ru r hr R R
bPP R r
R
R RO R R R RB RU R HR R R
Re f
sd ss s b
fm sa sst SJP s, bp
bp SC
2 s
SP sh LLS
s,set S ru
S
sha QPsscript I1 i-
i SN VD
iW sn vd
sl SP
sit
F SO ss SAV BP BP SC SE S SP SH LLS S S SW SN VD SL SP
PETROLEUM ENGINEERING
59-60
Subscript
Definition
skin (stimulation or damage) slip or slippage slurry (“mixture”) solid(s) (all formation solids) solids in experiment solids (matrix, grain) solution at bubblepoint conditions (usually with gas/oil ratio, Rsb) solution in water (usually with gas solubility in water, I?,,) solution, initial (usually with gas/oil ratio, R,i) solution (usually with gas/oil ratios) sonde, tool sonic velocity log SP spacing specific (usually with J and I) SSP stabilization (usually with time) standard conditions static bottomhole (usually with pressure or time) static casing (usually with pressure) static conditions, injection well (usually with pressure) static or shut-in conditions (usually with time) static tubing (usually with pressure) static well conditions (usually with time) steam or steam zone stimulation (includes “skin” conditions) stock-tank conditions storage or storage capacity strain structural surface surrounding formation swept or swept region system TDT log, neutron lifetime log televiewer log, borehole temperature temperature log temperature log, differential thermal (heat) thermal decay time (TDT) log thermal neutron log time, dimensionless times or time periods tool-description subscripts: see individual entries such as “amplitude log,” “neutron log,” etc.
Letter Subscript s z S
Reserve SPE Subscript S u 2, m CT
SE ma
HANDf3OOK
Computer Letter Subscript s S M S
sb
SEX MA SB
SW
SW
si
SI S
T SV SP
SV
sv
SP
SP
S SSP s SC
S o-
WS cs iWS WS
S
ts WS
S
S
S S
st
E
4 oe
st
S
S
o-
s
S S
S ru
s
u
NL TV T T DT h NL NT tD
nl script 1 tv
1,2,3, etc.
h,e t,h dt T, e
ne script I nt
SSP S SC ws cs IWS ws TS ws S S ST S EPS ST S S S S NL TV T T OT HT NL NT TO
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Subscript
Definition
tool, sonde total initial in place in reservoir total (gross) total, total system transmissibility treatment or treating true (opposed to apparent) (electrical logging) tubing flowing (usually with pressure) tubing or tubinghead tubing, static (usually with pressure) turbulence (used with F only, FB 1 ultimate unamortized unburned unburned portion of in-situ combustion pattern displacement from (usually with efficiency, EDU) unburned reservoir rock unburned volume, oil from (usually with displacement ratio, 6,, ) unit unswept or unswept region upper vaporization, vapor, or vapor phase variable density log, microseismogram log, signature log velocity velocity, sonic or acoustic log vertical volumetric of burned portion of in-situ combustion pattern (usually with efficiency, EVb) volume or volumetric water water, dimensionless water from burned volume (usually with displacement ratio, aWb) water/fuel water in gas cap (usually with saturation, S,,) water/oil (usually with instantaneous producing water/oil ratio, F,,) water/oil, produced (cumulative) (usually with cumulative water/oil ratio, F,,,) water, solution in (usually with gas solubility in water, R,,.) water-saturated formation, 100 % weight well conditions well, flowing conditions (usually with time) well, injection, flowing conditions (usually with pressure, piwzf)
59-61
Letter Subscript
Reserve SPE Subscript
T ti t t T t t
tf a!
ts B ul
a u
Computer Letter Subscript T TI T T T T T TF T TS B
LU
UL U U ou
RU ou
RU ou
U
u u u VD
V vd
iv
SV
V V Vb
v
V
V
W
W
U U U V vo V sv V VB V W
WD wb
WCI WB
wF
WFU WG wo
w wo
WOP
SW
SW
0 zero W
zr
ZR
W
W W WF IWF
W
wf iwf
f
59-62
PETROLEUM ENGINEERING
Subscript
Definition
well, injection, static conditions (usually with pressure, piws) well, static conditions (usually with time) wellbore, apparent (usually with wellbore radius, rwO1 wellhead wet gas (usually with composition or content, Gg ) wet gas produced wetting Young’s modulus, refers to zero hydrocarbon saturation zone, conductive fluids in an invaded zone, flushed zone, invaded
Letter Subscript
Reserve SPE Subscript
iws WS
wgp W
Y 0 zero z x0 i
Computer Letter Subscript IWS
s
wa wh wg
HANDBOOK
th
ws WA WH
WG W zr
I
WGP W Y ZR Z X0 I
59-63
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Subscript Symbols in Alphabetical Order
Letter Subscript Greek
Reserve SPE Subscript
Computer Letter Subscript
Definition
and Numerical e
0 zero 1 1,2,3,etc.
EPS ETA THE LAM RHO PHI P
u
ZR
p,pri
PR
s,set
H SE INF
1,2,3,etc.
1,2,3,etc. l/2 2 m
Subscript
strain diffusivity angle, angular, or angular coordinate mobility density porosity porosity data, derived from tool-description subscripts: see individual entries such as “amplitude log,” “neutron log,” etc. formation 100% saturated with water (used in R. only) primary location subscripts, usage is secondary to that for representing times or time periods numerical subscripts (intended primarily to represent times or time periods; available secondarily as location subscripts or for other purposes) times or time periods half secondary conditions for infinite dimensions
English A A a a a a a
ap A
A A A A A A A A A A
AN
AFU AN
a A A, a
A
a a a at; an anh ani B BT b b b
bt B 6P
AH ANI B BT B B B
amplitude log area1 abandonment acoustic
active, activity, or acting after taxes air altered apparent (general) atmosphere, atmospheric air/fuel annulus apparent (from log readings: use tool description subscripts) anhydrite anisropic turbulence (used with F only, FB) breakthrough band or oil band bank or bank region base
PETROLEUM ENGINEERING
59-64
Letter Subscript b b b b b bE bh bp c c c C C
Reserve SPE Subscript B
B
s, bp B,t B
B B B B BEX
w,BH
BH BP
talc
CA C C C C Cl c2 CB CO CL CN CO co2 CP cs C C C C C
C C
Cl c2
CB CD CL CN co co2 C c
cb cd cl cn
C cg
c c c C
C C C
C
c
C cr ec
CUP cb
CB
c C
Cf Cl Cfl
d
Ll C e CB CF CL CN COR CP cs 0
s, u di dfi’script 11 dm dr
a DN 01 DLL DM OR
cla cln
car CP CS
D D D DI DLL DM DR
Computer Letter Subscript
Subscript
Definition
before taxes bubble bubblepoint (saturation) bulk (usually with volume, V,) burned or burning burned in experimental tube run (usually with volume, V,,) bottomhole bubblepoint or saturation (usually with volume, VbP) calculated caliper log coil component(s) convective methane ethane bond log, cement compensated density log chlorine log compensated neutron log carbon monoxide carbon dioxide capillary (usually with capillary presssure, P,) casing or casinghead chemical compressional wave constant contact (usually with contact angle, 0,) conversion (usually with conversion factor in Newton’s law of Motion, gC) core critical electrochemical capture cement bond log casing, flowing (usually with pressure) clay clean corrected compaction casing, static (usually with pressure) density log dimensionless quantity displacing or displacement (efficiency) dual induction log dual laterolog diplog, dipmeter directional survey
HANDBOOK
59-65
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Letter Subscript DT Db
Reserve SPE Subscript dt
Computer Letter Subscript DT DB
Dm DU
QM DIJ
d d d d d d d d d dh dol 4 E E E E
D cl 0 D 0 0 D 0 0 DH DL DY E EM ES EX EXG
D 0 DH dtv iM est EX
Es EL EP C
e e e e e e e el eq ext F F F
el, ES ep ec 0
!E E E 0
&script el EV
FP Ff
Fi F ;
f ; f
;
fm F
EL EP C E E E E E E E E EV XT F F FU FP FF FI F F F F F FR
Subscript
Definition
differential temperature log displacement from burned portion of in-situ combustion pattern (usually with efficiency, EDb) dimensionless quantity at condition m displacement from unburned portion of in-situ combustion pattern (usually with efficiency, ED,) decay delay depleted region, depletion dewpoint differential separation dip (usually with angle, ad) dispersed displaced drainage (usually with drainage radius, Ye) downhole dolomite dirty (clayey, shaly) electrode empirical estimated experimental experimental value per mole of produced gas (usually with fuel consumption, m& ) electrolog, electrical log, electrical survey electromagnetic pipe inspection log electrochemical boundary conditions, external cumulative influx (encroachment) earth effective (or equivalent) electric, electrical entry external or outer boundary conditions electron equivalent extrapolated fill-up free (usually with gas or gas/oil ratio quantities) fuel (usually with fuel properties, such as nF) cumulative produced free value (usually with gas, GFP) free fluid free value, initial (usually with gas, GFi) finger or fingering flash separation fluid formation (rock) fraction or fractional fracture, fractured, or fracturing
PETROLEUM ENGINEERING
59-66
Letter Subscript
Reserve SPE Subscript
f f G G G GG GM GR g @ m gb gr UP
H H H
H2S
HP h h h h hr I I I I ID IM i i i i i i i ig im
Computer Letter Subscript F F
T g gg gm gr G
h
G GT G GG GM GA G GQ GA GB GR GY
H HL
HY H2S
b T,8 H H T, Q
i script i i, i script i
HP HT H
H HT HR I I I
i id im
1 ID IM I I
inj b,i script i I I ir, b,,i script i
iwf
I I I I IR IG IM I IWF
iws
IWS
int
ws
s
j j K k k
d ek K
ws J J K K K
Subscript
Definition
front, front region, or interface rock (formation) geometrical geothermal guard log gamma-gamma ray log gravity meter log gamma ray log gas gas, dimensionless gas at atmospheric conditions gas at bubblepoint conditions grain gypsum horizontal hydraulic hydrogen nuclei or atoms hydrogen sulfide heavy phase heat or thermal hole hydrocarbon thermal (heat) hydrocarbon, residual imbibition induction log interference invasion (usually with invasion efficiency, E,) induction log, deep investigation induction log, medium investigation cumulative injected initial conditions or value injection, injected, or injecting inner, interior, or internal invaded invaded zone irreducible, interstitial, or connate intergranular intermatrix intrinsic injection well, flowing conditions (usually with pressure, pjWf1 injection well, static conditions (usually with pressure, P& ) well, static conditions (usually with time) jth component junction dispersion electrokinetic particular period, element, or interval
HANDBOOK
59-67
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Letter Subscript
Reserve SPE Subscript
k
P script 1 P script 1 L L L p script I
L
L ! script I
0 script 1 0 script 1 L
LP
Computer Letter Subscript K LAM LAM L L L L LP
LL
@script N
LL
LLD LLS
ppd script N 1ps script I1
LOG
log Pp script 1
LLO LLS L LP LP
LP LP
lim IS M M M E ML MLL m m ma ma
1st
m z, m
z,m m P script 1 mPPscript N
max me
mf min N N N
n
n n
N2
NA NE NF NL NM NT n n n n ne nw 4
na ne nf
n! script 1 nm nt
r,R N NW
LM LS M M M M M ML MLL FU M MA MA MX MC MF MN N N N N2 NA NE NF NL NM NT N N N N NE NW 02
-
Subscript
Definition
permeability laminar laminated, lamination lateral (resistivity log) linear, lineal liquid or liquid phase lower cumulative produced liquid (usually with condensate, GLP) laterolog (add further tool configuration subscripts as needed) deep laterolog shallow laterolog log light phase liquid produced, cumulative (usually with condensate, GLp) limiting value limestone Mth period or interval mixture molal (usually with volume, V,> mud slurry (“mixture”) contact log, microlog, minilog microlaterolog mass of fuel (usually with fuel concentration, C,,,) mud grain (matrix, solids) matrix [solids except (nonstructural) clay or shale] maximum mudcake mud filtrate minimum neutron neutron log normal (resistivity) log (add numerical spacing to subscript N; e.g., N16) nitrogen neutron activation log neutron log, epithermal neutron log, fast neutron lifetime log, TDT nuclear magnetism log neutron log, thermal net normal normalized (fractional or relative) nth year, period, income, payment, or unit noneffective nonwetting oxygen
PETROLEUM ENGINEERING
59-68
Letter Subscript
Reserve SPE Subscript
OB 0
N
Computer Letter Subscript
LIB 0
ob
OB
ob
OB
OD W
OD OG ou
011
P P NL PV Pk ; P P P P P P P PD PD PE PSP PC Pj pr R R R R R R Rb RM
P
nP script 1 PV
PO P P P
r rl P
P P NL PV PK P P PO P PAV P P P P PQ PQ PEX PSP PC PJ PRD
R R R R RB RU
Re R R b, P R
R R RD R R
Subscript
HANDBOOK
Definition
observed oil (except when used with resistivity) oil at bubblepoint conditions (usually with formation volume factor, Bob) oil from burned volume (usually with displacement ratio, & ) oil, dimensionless oil in gas cap (usually with saturation, S,,) oil from unburned volume (usually with displacement ratio, 6,, 1 phase or phases proximity log neutron lifetime log, TDT discounted value, present worth, or present value profit-unamortized investment particle (usually with diameter, dp) pattern (usually with pattern efficiency, EP) payout, payoff, or payback pore (usually with volume, VP) pressure, mean or average produced produced, cumulative production period (usually with time, tp) pseudo pore value, dimensionless (usually with volume, VPD) pseudodimensionless produced in experiment pseudo-SP pseudocritical produced componentj (usually with moles, npj) pseudoreduced rate ratio recovery (usually with recovery efficiency, ER 1 reservoir resistivity resistivity log reservoir rock, burned reservoir rock, unburned Reynolds (used with Reynolds number only, NRe) radius, radial, or radial distance rate of return reduced reference relative
SPE LETTER AND COMPUTER SYMBOLS STANDARD
Letter Subscript r s S S s SN SP SSP sv SWN s s s s
Reserve SPE Subscript
Computer Letter Subscript R SAY SW S SAV
SN
sv swn d
S S S S S S
SP SSP sv SWN S S S S s S S S S S
S S S S
s S
S S S u
S
s s SE sb SC SC sd
sh
s, 0 u
sa sha
si Sl
SP SP ss st St SW &VP T T T T TV
S S S S S S s S SEX SB
o-
sit
sst
S
SC SC SD SH SI SL SP SP ss ST ST SW
GY h, 0 t,h t t tv
59-69
T T T TV
Subscript
Definition
residual saturation, mean or average sidewall storage or storage capacity average or mean saturation neutron log, sidewall SP SSP sonic, velocity or acoustic log sidewall neutron log damage or damaged (includes “skin” conditions) formation, surrounding gas/oil ratio, solution segregation (usually with segregation rate, qs) shear shear wave skin (stimulation or damage) slip or slippage solid (usually with volume or density) solution (usually with gas/oil ratios) spacing specific (usually with J and Z) stabilization (usually with time) steam or steam zone stimulation (includes “skin” conditions) surface surrounding formation swept or swept region system solids in experiment solution at bubblepoint conditions (usually with gas/oil ratio, Rsb) scattered, scattering standard conditions sand shale solution, initial (usually with gas/oil ratio, R,;) silt separator conditions single payment sandstone stock-tank conditions structural solution in water (usually with gas solubility in water, R,,) gypsum
temperature temperature log tool, sonde transmissibility televiewer log, borehole
PETROLEUM ENGINEERING
59-70
Letter Subscript
t t t t f
tD
Reserve SPE Subscript
T
T
T 7 tr t&T
T T T T TO TF TI TS
u
u U U U U UL V V VD
tf ti ts U U U u U ul
V V VD
u Ii u a V V
vd
VB
Vb
V
V V W
W
W
V V
W W
W
WD WF wa wb wf Wf w&T wg WP
-
Computer Letter Subscript
f
V V W W W W WQ WFU WA WB WF WF
WG
wo
WG WGP WH wo
WOP
WOP
ws ws
ws ws X0 Y 2
Wh
X0
Y Z Z
th
Subscript
HANDBOOK
Definition
gross (total) total, total system treatment or treating true (electrical logging) (opposed to apparent) tubing or tubinghead time, dimensionless tubing flowing (usually with pressure) totalinitial in place in reservoir tubing, static (usually with pressure) unamortized unburned unit unswept or unswept region upper ultimate vertical volume or volumetric microseismogram log, signature log, variabledensity log volumetric or burned portion of in-situ combustion pattern (usually with efficiency, EVb) vaporization, vapor, or vapor phase velocity water weight well conditions wetting water, dimensionless water/fuel wellbore, apparent (usually with wellbore radius, rwa) water from burned volume (usually with displacement ratio, ENah ) bottomhole, flowing (usually with pressure or time) well, flowing conditions (usually with time) water in gas cap (usually with saturation, S,,,) wet gas (usuallywith composition or content, C,, ) wet gas produced wellhead water/oil (usually with instantaneous producing water/oil ratio, F,,) water/oil, produced (cumulative) (usually with cumulative water/oil ratio, F,$,,) static bottomhole (usually with pressure or time) well, static, or shut-in conditions (usually with time) flushed zone Young’s modulus, refers to conductive liquids in invaded zone zone, conductive invaded
Author Index A Abbott, W.A.. v, 4-11 Abernathy, B.F., 4431, 44-51 Abou El-Now, F., 25-24 Abou-Kassem, J.H., 48-11, 48-19 Abou-Sayed, A..%, 55-10, 55-11 Abram, A., 54-12 Ache, P.S., 44-29, 44-50 ACS Industries Inc., vi, 12-43 Addington, D.V., 48-20 Adenev. W.E.. 25-22 Aepelbaum. V.A., 25-22 Afanas’eva, N.L., 25-25 Afoeju, B.1. ~ 46-45 Agarwal. R.G., Y-10 Aguilera, A., 51-45, 51-52 Aguilera, R.. 29-9 Ahmed, U., 55-10 Aho. G.E., 47-26 Ahrens. G.. xii. 51-51 Ainley, B.R., 55-10 Air Products and Chemical Inc., 39-28 Ajitsaria, N.K., 20-9, 20-18 Akbar, A.M., 48-20 Akstinat, M.H., xi, 47-25 Alaska Oil & Gas Conservation Commission, viii Alberta Energy Resources Conservation Board. 48-18 Alcauska, J.B., 25-21 Alder. S.B.. viii. 25-23 Alexander. J.D.,‘46-13, 46-43 Aluer. R.P.. 49-41, 49-42, 51-50, 51-51 AlyHussainy. R., 35-10, 35-21 Aliev, S.N., 12-43 Allen. D-R., 46-45 Allen. F.H.. 23-13, 39-13, 39-28 Allen, L.S.. 50-38 Almond, S.W., 55-10 Al-Saadoon, F.T. 37-21, 37-27 Althouse, W.H., 4-1 I American Assn. of Petroleum Geologists (AAPG), 24-22, 29-9, 40-2, 40-37 American Bureau of Shipping. 18-21, 18-52 American Gas Assn. (AGA), vi, 13-8. 13-59. 33-13. 33-23, 40-38 American Gear Manufacturer’s Assn. (AGMA), IO-12 American Hot Dip Galvanizers Assn.. vi. II-14 American Inst. of Mining, Metallurgical and Petroleum Engineers (AlME), 12-43 American Meter Co., vi, 13-41. 13-59 American Nail. Metric Council (ANMC). 58-2, 58-8 American Nail. Standards Inst. (ANSI), 58-2, 58-8, 58-22 ANSI 816.5, 15-l 1, 15-34 ANSI B26.5, vii ANSI 831.1, 15-11, 15-34 ANSI B31.8, 15.11. 15-34 ANSI B48.1, 58-8 ANSI/API 2530, vi, 13-3, 13-59 ANSIiASME 831.3 & 31.4. 15-11, 15-34 ANSI/ASME SPPE-1 & lb, 3-34, 3-39. 340 ANSI/IEEE Std. 260, 58-8 American Petroleum Inst. (API), 24-3. 39-27. 40-2, 40.37, 40-38. 41-37, 58-2, 58-7 API Bull. D-14. 40-37. 40-38 API Bull. 2N. 18-52 API Bull. 5C2. 2-46.2-60. 2-74. 3-l. 3-40 API Bull. 5C3. 2-74
API Bull. 5C4, 2-74 API Bull. I lL3, 9-3, 9-4, 9-14 API Circ. PS-1360, 2-46, 2-74 API Circ. PS-1398, 2-74 API Code 25, 17-l API Code 27, 26-10. 26-11, 26-33 API Committee on Standardization of Steel Tanks for 011 Storage, 11-3 API Committee on Standardization of Valves and Wellhead Equipment, 3-3 API Fundamental Research on Occurrence and Recovery of Petroleum, 39-27 API Manual 14BM, 6-21, 6-72 API Manual of Petroleum Measurement Standards, ix. 16-16. 17-l. 17-3. 17-S. 19-6, 19-34. 32-16 API Manual on Disposal of Refinery Wastes, vii, 15-19, 15-24. 15-34 API Petroleum Safety Data 2210, 1l-9 API Pub. 2563 and 2564, 58-8 API RP 2A, 18-25, 18-27 API RP 2K, 18-17. 1X-52 API RP 2P. 18.16, 18-52 API RP 20, 18-17, 18-52 API RP 5C1, 3-l. 3-40 API RP 5C2, Y API RP 5C3, v API RP 6F. 3-38, 3-40 API RP 7C-IIF, 10.19. lo-37 API RP IOE, 15-10, 15-34 API RP IIAR, 8-10 API RP llBR, vi, 9-14 API RP IIER, 10-12, lo-37 API RP IlG, vi, 10-7, 10-12, 10-13, lo-37 API RP IIL. vi, 8-10. 9-2, 9-3, 9-14, 10-7, IO-37 API RP IlR. 7-17 API RP 11s. 7-17 API RP IlU. v API RP 12L, 19-7 API RP l2RI. II-14 API RP 148, 3-40 API RP l4C. 3-40, 12-43, 18-46, 18-52, 19-28, 19-34 API RP 14E, vit, 12-43, 15-7, 15-33, 19-34 API RP l4F, 3-34, 340, 18-44, 18-46, 18-52 API RP 14H. 3-40 API RP 36. 32-3, 32-16 API RP 38. 4444, 44-51 API RP 39M. 55-6 API RP 44. 39-5. 39-27 API RP 45, 19-34, 24-5, 24-22, 44-51 API RP 49, 18-20, 18-52 API RP 53. 18-12. 18-20. 18-52 API RP 66. 6-72 API RP 5008, vi, 10.37. 18.46, 18-52 API RP 520, 11-7 API Spec. 5A, v. 2-74, 3-2. 3-14, 3-40 API Spec. 5B, v, 2-64, 2-74 API Spec. 5AC. 2-74 API Spec. 5AQ, 2-74 API Spec. SAX, 2-74 API Spec. 5L. v, 2-74. 3-2, 3-40, 15-10, 15-34 API Spec. 5LE. 15.10, 15-33 API Spec. 5LP, 15-10. 15-33 API Spec. SLR. 15-10, 15-34 API Spec. 5LX, 15-12 API Spec. 6A, v. 3-l. 3-5, 3-18, 3-36. 3-38. 3-40, 15-13, 15-34 API Spec. 78-l IC. 10-17. IO-37 API Spec. I IAX. v, 8-2. 8-6. 8-10 API Spec. IlB. vi. 9-l. 9-14 API Spec. IIC. vi. 9-14 API Spec. I IE. IO-I. 10-4. 10-5. 10-7. lo-37
API Spec. IlN, 16-16 API Spec. 128, vi API Spec. 12D, 11-2, 11-14 API Spec. 12F, 11-I, II-14 API Spec. 125, 12-44 API Spec. 12K. 19-34 API Spec. l2L, 19-34 API Spec. 14A. 3-34, 3-40 API Spec. 14D, 3-34, 3-39, 3-40 API Standardtzation Conference, 2-46, 2-60, 2-63, 2-74 API Standing Subcommittee on Secondary Recovery Methods. 39-28 API Std. 5B, 2-57 API Std. 12B. 11-3. 1 l-14 API Std. 510. 12-43 API Std. 620. 11-7. 11-14 API Std. 650. 11-2, 11-7, 11-9. II-14 API Std. 1101, ix, 16-6. 16-16, 17-4, 17-7, 32-16 API Std. 1104, 12.44, 19-34 API Std. 2000, vi, 11-6, II-14 API Std. 2500, 17-I API Std. 2531 & 2533, 17-4 API Std. 2534, 17-4, 17-7 API Std. 2543, 17-5, 17-S API Std. 2545, 17-3, 17-8 API Std. 2550 to 2556, 17-3 API Technical Data Book, 21-3, 21-20 API Vocational Training Series, v. 5-57 American Sot. of Mechanical Engineers, (ASME) 46-45, 58-2, 58-7, 58-8 ASME Code for Boilers and Pressure Vessels, vi, 12-38 to 12-41, 12-43 ASME B31, 15-11, 15-33 American Sot. for Testing and Materials, (ASTM) l-80,24-3,24-5,24-22,58-2.58-7 ASTM A 123, II-14 ASTM D 1250, 17-5. 17-6 ASTM D 1298, 17-5 ASTM D 2887. 21-l. 21-20 ASTM D 4051,.17-5 ASTM E 380-82, 58-8. 58-14 ASTM Standards on Petroleum Products and Lubricants, vii ASTM Steam Tables, x Amero. R.C., 25-27 Amirijafari. B., 25-26 Amyx, J.W., 24-23, 26-l Anders, E.L. Jr., 43-19 Anderson, A.E., 49-41 Anderson, B.W., 54-13 Anderson, D.F., 47-25 Anderson, G.. 52-31 Anderson, G.L., 16-16 Anderson, M.A., 26-33 Anderson, R.A., 51-52 Anderson, T.. 5144, 51-52 Andresen, K.H., 44-51 Angier, J.D., 6-72 Angino, E.E., 24-19. 24-23 Anthony, R.G., 25-26, 25-27 Antoine, C.. 20-13. 20-17, 20-18 Aoyagi, K., 25-12, 25-23 Apache Santa Fe Intl. Corp., vii Archer, D.L.. 28-11, 28.15, 47.20, 47-26 Archie, G.E., 26-28 . 26-29. 26-31, 49-4, 49-5. 49-4 1 Ardittv, P.C., xii, 51-51 Arnold, D.M.. xi. 50-32. 50-38 Arnold, K.E., 15-l. 19-I. 19-33 Arnold. M.D.. 48-20 Arnold, R.B.. 4-l I Aron. J.. 51-51. 55-10
2
PETROLEUM
Aronofsky, J.S., 44-19, 44-20. 44-29. 4434, 4449, 4450 Arps, J.J., 30-9. 30-15, 30-16, 37-14, 37-15. 37-27, 40-1, 40-19. 40-32, 40-37, 40-38. 41-l. 41-5. 41-23, 41-37, 4450, 44-5 I Arrow Specialty Co., vi Arthur. M.G., 39-26. 39-28 Aruna. M., 36-10 Aseltine, R.J., 46-44 Ashby, W.H. Jr., 24-14, 24-23 Ashford, F.E., ix, 28-I I. 28-15 Asymyan, K.D., 25-26 Atkinson, A., 51-44, 51-52 Atkinson, H., 44-40, 4451 Atkinson, M.H.. 16-16 Attra. H.D., 43-4, 43-16, 43-19 Au, A.D.K., 48-19 Ausburn, B.E., 29-1, 51-52 Ausburn. J.R., xii, 51-51 Auvenshine. W.L., 39-16, 39-28 Azarnoosh, A., 25-25 Aziz. K., vii, 20-5, 20-9, 20-15, 20-18,45-14, 48-l I, 48-16 to 48-19, 54-14, 55-l I
B Babson. E.C., 34-55. 40-9. 40-38 Bagley, J.W. Jr., 36-10 Bailey. N.J.L., 24-22 Baiton, N., 45-15 Baker. J.R., 54-14 Baker, 0.. viii, 22-17. 22-22 Baker Oil Tool Div., v, 4-I I Baker Performance Chemicals Inc., vii Baldwin, J.. 50-38 B8lint. A.M., 28-15 Ballard, D., 25-23 Baltosser, R.W., xii, 51-52 Bansal. P.P.. 48-20 Bansback, P.L., 19-33 Banthia, B.S., 51-6, 51-50 Barakat, Y., 47-25 Barb. C.F.. 24-22 Barber, A.H. Jr., 36-10 Barbrow. L.E., I-l, 1-68 Bardgette, J.J., 18-52 Bardon, C., 28-11, 28-15 Barduhn, A-J., 25-26. 25-27 Barfield, E.C.. 4417, 4449 Barham, R.H., 38-20 Barker, C.. 24-22 Barlyaev, E.V.. 25-25 Barnes, D.F., 51-51 Barnes, K.B., 44-51 Barnes, V.E., 24-22 Barrett, M.L. Jr.. 16-16 Barrett, R.. 12-43 Barron, A.N., 54-12 Barry, A.F., 12-43 Barstow, W.F., 39-28 Bartell. F.E., 442, 4449 Bartholome. E., 25-2 I Bartlesville Energy Technology Center, vii Bartlett, E.P., 25-22 Barton, J.R., 25-21 Barton, W.C. Jr.. 43-16 Bass. D.M. Jr., 24-23, 26-1 Basset. J., 25-22 Bassiouni. Z.. 28-12, 28-16 Bateman, R.M.. xi, 53-1, 53-26 Bates, G.O., 39-28 Bates, R.L., 29-9 Battmo, R., 25-23 Batycky, J.P.. 28-12, 28-15 Baucum. A.W., 40-16. 40-38 Baugh, E.G., 45-15 Baumgaertner, M.. 25.16, 25.17, 25.23
Baumgartner, S.A., 55-l I Bavly. D., 48-18 Baxendall, P.B., 34-37, 34-55 Bayless, C.R., 16-16 Beach, F.W., 16-16 Beal, C., 22-14 to 22-16, 22-22, 46-45 Bear, J., 28-15 Beardon. P.L., 38-20 Be&y, J.W., 44-51 Bebout, D.G., 29-9 Becher, P., 19-34 Beck, R.L., ix, 34-46, 34-55 Becker, H.G., 25-22 Beebe. W.B., 29-9 Be&r, H.S., 24-22 Beeson. C.M., 26-33 Beestecher, E., 24-22 Beggs, H.D., 5-57, 7-9, 7-17, 22-1, 22-7 to 22-12, 22-15, 22-16, 22-22, 34-55, 46-7. 46-43. 46-45 Behie, A., 48-20 Beider, S.Y ., 25-26 Beirute. R., 55-l 1 Belknap, W.B., 50-38 Bell, C.A., 6-34. 6-72 Bell, C.R., vii Bell, W.E., 4451 Bellotti, P., 52-31 Benedict, M., 20-7, 20-18 Benham, A.L., 34-5.5, 46-16, 46-45 Ben-Naim, A.. 25-21, 25-24 Benner, F.C., 44-2, 44-49 Bennett, C.O., 55-11 Bennett, E.N., 39-16. 39-28 Bennett. E.O., 39-26, 39-28 Bennett, K.E.. 47-25 Bennion, D.W., 48-18 Benson, B.B., 25-22 Berg, R.A., 36-10 Berg, R.R., 36-10 Berger, W.R., 24-22 Bergman, J.C., ix, 30-16 Bergstrom, J.M., 54-14 Berkshire, D.C., 54-13 Bernard, G.G.. 45-14. 47-25 Bernard, H.A., 36-3, 36-10 Bernard, W.J , 44-51 Berry, D.W., 48-10. 48-19 Berry, F.A.F.. 24-23 Berry, I.E., 51-6, 51-50 Berry, J.F.. 28-16 Berry, P., 36-10 Berry, V.J. Jr.. 37-23, 37-25, 37-27, 40-38, 43-4, 43-16, 43-19, 46-43 Berryman. I.E., 39-15. 39-28 Bertiger, W.I., 48-19 Bertozzi, W., 50-38 Bertuzzi, A.F.. 34-1, 34-55 Bertuzzi. W.. xi Beson, J., 3-I Bessler, D.U., 19-33, 19-34 Best, D.L., xi. 4941 Biggs, W.P., 49-42 Bijl, A., 25-21 Bilhartz, H.L., 4451 Billett, F.. 25-2 I Billings. G.K., 24-23 Billingsley. R.H.. 46-44 Billitzer. .I., 25-24 Bily, C., 25-18. 25-24 Binckley, C.W., 33-1, 33-23, 34-27, 34-29, 34-55 Binder, G.G. Jr.. 45-14. 46-43 Bingham, M.G.. 52-24, 52-31 Biot. M.A.. 51-8. 51-11, 51-36, 51-47, 51-49. 51-51 Birch, F., 51-50 Bird, R.B , 47-24
ENGINEERING
HANDBOOK
Birdwell Div. of Seismograph Service Corp., xii. 51-52 Birdwell Technical Pamplet, xii Bissey, L.T., 25-26 Black, C., 25-25. 25-26 Black, C.J.J., 28-16 Black, H.N., 54-12 Black, W., 19-34 Blackwell, R.J.. 28-2, 28-4, 28-15, 45-14 Blair, C.M., 19-34 Blair, E.A., 43-16 Blair, P.M., 4429, 44.50, 48.14, 48-20 Blanton. J.R., 45-15 Blaskovich, F.T., 48-5, 48-18 Bleaklev, W.B., 4-1, 6-34, 6-72, 45-15.46-44 Blevins; T.R., 46-44 Bloomquist, C W , 48. I8 Boatright, B.B., 39-26, 39-28 Bobek, J.E., 44-49 Boberg, T.C., 46-9,46- 11,46- I3,4643,48-19 Bobrowski, F.P., 37-27. 40-38 Bockmeulen, H., 24-22 Bodine, J.A., 18-I Bodvarsson, G.S., 48-20 Bogdanov, M.I., 25-25 Bogdanov, V.S., 28-1 I, 28-15 Bohr, C., 25-21 Boley, D.W., 44-50 Boling, D.R., II-1 Bondareva, M.M., 25-27 Bone, M.P., 36-10 Boone, D.M., 6-72 Borden, G. Jr., 22-22 Borger, H.D.. 24-22 Boston, J.F., 25-24 Botset, H.G., 28-2, 44-49 Bouma, H., 29-9 Bourrel, M., 47-25 Bowen, J.F., 55-12 Bowler, J., xii, 51-51 Bowman, R.W., 46-44, 46-45. 47-24 Boyd, W.L., x. 41-31, 41-37 Boyd, W.S., 25-21 Boyle, W.G., 3-1, 3-40 Bozeman, J.F., 39-28 Brace, W.F., 5143, 51-52 Bradbury, E.J., 25-24 Bradley, H.B., iii, 24-12, 39-1, 44-20. 44.50, 58-2 Bradstreet. E.B., 25-21 Bragg, J.R., 47-25 Brainerd, H.A., 16-16 Brandt, H., 51-6. 51-50 Brannan, G.. 45-15 Braun, E.M., 28-2, 284. 28-15 Braun, P.H., x, 44-49, 45-13 Braunstein. J.. 29-9 Breeding, C.W., 41-37 Breitenbach, E.A.. 48-l4,48-16,48-18.48-20 Brewer, S.W., 4645 Brian Watt Assocs., vii Brigham, W.E., 45-15, 4645 Bright, J., 24-22 Brill, J.P., 34-37, 34-55 Brill, T.P., 46-7, 46-43 Brinkley, T.W., 37-27, 39-20. 39-23, 39-28 Brinkman, F.H., 40-38 Briscoe. C.F., 25-21 Bristol Co., The, vi Britt, H.I.. 25-24 Britton, M.W., 46-45 Broddus, E.C.. 54-12 Broding, R.A., xii, 51-50, 51-52 Brons, F., 35.16, 35-21, 40-38, 41-37 Brooks, F.A.. 56-9 Brooks, R.H.. 28-12, 28-15. 46-31, 46-34, 46-45 Brooks, W.B., 25-26
AUTHOR INDEX
3
Broussard, W.F., 12-43 Brown. A.A.. 51-49 Brown, A.R., 36-10 Brown. F.B., 6-1, 6-36, 6-66, 6.69, 6-12 Brown, G.A., 53-26 Brown. G.G.. vii. ix, x, 20-5. 20-18, 3455. 40-38. 45-13 Brown, H.D., 51-52 Brown. H.W., 26-24, 26-25, 26-33 Brown. J.N., 44-51 Brown, K., 6-28, 6-34, 6-37, 6-38, 6-72 Brown, K.E.. 7-17, 34-37, 34-55 Brown. R.B., 36-11 Brown, R.J.S., 51-8, 51-51 Brownlow, 47-26 Brownscombe. E.R., 25-23, 30-16, 38-9, 38-20 Bruce, W.A., 26-33 Bruist, E.H., 56-9 Brunsmann. J.J.. 15-34 Bryan, G.M., 25-24 Buchanan, R.D., 39-28 Bucklev. S.E.. 24-22. 28-3. 28-6, 28-7. 28.-15, 39.15, 39-28, 40-13, 40-16 to 40-18, 40-38, 43-3, 43-4, 43-16, 43-19, 447, 4410, 44-11, 44-26, 44-29, 44-49, 47-2, 47-24, 48-1, 48-18 Buckwald, R.W. Jr., 46-45 Buehner. L.O.. 6-72 Bull, A.D.. 46-45 Bunge, A.L., 47-21, 41-26 Bunting, E.N., 26-4 to 26-6, 26-33 Burcik, E.J., viii, 39-2, 39-27 Bureer. J.G.. 46-43 Burke. B.C., 18-52 Burke, R.E.. 46-45 Burkill, G.C.C., 54-12 Burkleca, L.F., 54-13 Burnett, E.S., 20-4, 20-18 Burns, G.E., 18-l Burrell, G.R., 16-l Burrows, D.B., 20-15, 20-18, 39-27 Bursell, C.G., 46-44 Burt, R.A. Jr., 45-15 Burton, M.B., 4418, 44-20, 44-21, 4449 Busch, D.A., 29-9 Bush, D.C., 50-38 Bush, J., 47-26 Buthod, P., 21-t Buxton, T.S.. 46-44 Byk, S.S., 25-23, 25-28 Byth, NJ., 54-14
C Cady, G.H.. 25-3. 25-21 Cady, G.V., 46-43, 4645 Cairns, R.J., 19-34 Calahan, D.A., 48-20 Calder. J.A.. 25-27 Calhoun, J.C. Jr., ix. 32-16, 39-28, 40-38, 4429, 4450, 45-14 California Dept. of Natural Resources, 29-9 California Research Corp., vii, viii Cahngeart, G., 20-13, 20-17, 20-18 Callahan, M.J., 55-l I, 55-12 Callanan, J.E., 25-27 Callaway, F.H., 38-20, 44-51 Callawav. R.E.. 54-14 Calver, j.c, xi Camacho, C.A., 3440, 34-55 Cameo Inc., v Cameron, R.C., 54-13 Camilleri, D., 47-25 Campbell. A.W., 45-15 Campbell, F.L., 4942, 52-31 Campbell, J.B., 45-15 Campbell, J.L.P., 50-I
Campbell. J.M.. VI, 12-43, 12-44. 13-l. 13-59. 14-6. 14-22, 25-23. 25-26. 41-37. 58-2. 58-21 Camobell. R.A.. 58-2 Campbell, W.P.; 24-22 Canadian Petroleum Assn. (CPA), 58-2. 58-8 CanOcean Resources Ltd., vii Capell. R.G., 25-27 Caraway, W.H., 26-33 Cardwell, W.T. Jr., 39-28, 40-38 Carlile, R.E., 58-2 Carll, J.F., 44-1, 44-49 Carlson, F.M., 28-12, 28-15 Carmichael, L.T., 25-27 Carmichael, R.S., 51-30. 51-52 Carothers, W.W., 24-22 Carpenter, C.W., 44-50. 44-52 Carpenter, P.G.. ix, 34-37, 34-55 Carr. A.H., 48-19 Carr, N.L., 20-9, 20-10. 20-15, 20-16, 20-18, 39-4, 39-13, 39-27 Carraway, P.M., 46-45 Carroll, H.B., 55-12 Carson, D.B., 25-5, 25-23, 25-28 Carter, R.D., 38-2, 38-3, 38-20, 55-10 Casale, C., 25-21 Case, C.H., 43-16 Case, C.R., 50-38 Case, R.C., 16-16 Casst. F.J., 46-45 Cassingham, R.W., 43-17, 45-15 Cato, R.W., 46-44 Caudle, B.H., 43-10. 43-19. 4417, 44-19, 44-20, 44-29, 44-34, 44-37, 44-49 to 44-51, 45-14, 46-17, 46-45. 47-24 Cayias, J.L., 47-25 CBI Industries Inc., vi C-E Natco, vi, vii Chaddock, R.E.. 25-25 Chambers, A., 26-33 Chan, A.F.. 47-24 Chart, S.A., 41-37 Chantey, D.G., 17-l Charm. SK., 51-52 Chappelear, J.E.. 48-20 Charles, G.J., 55-10 Chase, C.A., 48-18 Chastain, J.. IO-37 Chatas, A.T., 38-20 Chatelain. J.C., 54-12 Cheek, R.E., 44-20, 44-49 Chemineer-Kenics, vii Chen. C.-C., 25-18, 25-24 Chen, W:H., 46-43, 48-18 Chenault, R.L.. 8-l Cheng, C.H.. xi. xii, 51-50, 51-51 Chepkasov, V.M.. 12-43 Cherskii, N.V., 25-24 Chew, J.. 6-72, 7-12, 7-17, 22-14 to 22-16, 22-22, 39-4, 39-21. 46-45 Chierci, G.L., 28-12, 28-15. 34-55 Chilingar, G.V., 46-45 Chilton, C.H., vii. 20-18, 25-15 Chou. J.C.S.. 24-13. 24-14. 24-23 Christ, F.C., 6-34. 6-38, 6-72 Christensen, D.M., 51-50. 51-51 Christian, L.D., 45-15 Christie. M.A.. 4X-19 Chu, C.. 46-1, 46-13 to 46.19, 46-21, 46-43 to 4646 Church, D.C., 54-12 Cinco-Ley, H., 55-l 1 Ciucci, G.M., 34-55 Clampitt. R.L., 47-24 Clapeyron, B.P.E., 20-11 to 20-13, 20-16. 20-17 Claridge, E.L.. 45.14, 47-24
Clark. C.R., 6-72 Clark. G.A., 46-44 Clark, G.J., 54-12 Clark. J.A.. 55-l I. 55-12 Clark, J.B. Jr., 57-l Clark, J.D., 58-2 Clark. K.M.. 6-34. 6-72 Clark, N.J., 45-13, 45-14 Clark, P.E.. 55-l I Clark, S.P., 51-30, 51-52 Clausius, R.. 20-12, 20-16, 20-17 Claussen, W.F., 25-21 Clavier, C., 49-41 Clayton, J-M.. 4451 Clayton, R.N.. 24-23 Cleary, M.B , 55-11 Clementz, D.M.. 52-30 Clifton, R.J., 55-l I Clinedinst, W.O., 2-1, 2-60, 2-74 Clinkenbeard. P., 39-25, 39-28 Closman, P.J., 38-20 Cloud, J.E., 55-l I Coan, C.R.. 25-21 Coates. G.R.. xi. 49-41, 51-52 Coats, K.H., 39-22. 39-28, 43-17, 45-14, 46-11, 46-12. 46-43, 46-45. 48-l. 48-16, 48-18 to 4X-20 Coberly, C.J., 6-l. 6-66. 6-69. 6-72 Cobb, T.R., 44-50 Cobb, W.M.. 31-7. 48-18. 52-31 Coffin, C.R., 24-22 Coker, F.B., 51-52 Colegrove, G.T., 48-19 Coleman. C.F., 25-26 Coleman, H.J., 21-20 Coleman, J.M., 29-9 Coll, R.. 25-25 Collie, B., 19-34 Collins, A.G., viii, 24-1, 24-22 Collins, F.A., 38-9, 38-20 Collins. F.R.. 51-50 Collins, R.E., 44-50 Colpoys, P.J., 55-12 Combaz, A., 50-38 Combs, G.D.. 43-16 Concus, P.. 48-20 Conley, F.R., 47-26 Conlon, D.R., 30-16 Connally, C.A. Jr., 6-72, 7-12, 7-17, 22-14 to 22-16, 22-22, 39-4, 39-27, 46-45 Connell. J.G., 49-42 Connolly, J.F.. 25-26 Conway, M.W., 54.14, 55-l I Cook, A.B., 37-23, 37-27, 39-12, 39-28.40-38 Cook, G.W., 48-20 Cook, H.L., 5-57 Cook, R-E., 43.17. 48-19 Cooke, C.E. Jr., 31-7, 4451. 47-20. 47-26, 55-l 1 Cooper, F.E.. 1243 Cooper, H.E. Jr., 44-49 Cooper, R.J., 44-51 Copeland, C.T., 54-12, 56-9 Coppel. C.P., 19-34, 54-12 Cordell, J.C., 37-25, 37-27 Core Laboratories Inc., viii, x, 26-5. 26-33 Corey, A.T., 28-8, 28-12. 28-15.46-34, 4645 Cornelissen, J., 15-34 Cornell, D.. 26-28, 26-33, 34-9, 34-10 to 34-22, 34-24, 34-55 Correia, R.J., 24-23 Corteville, J., 48-19 Cosgrove, J.J., 44-29, 44-5 1 Cotter, W.H.. 43-16 Cotton, W.J. Jr.. 53-26 Coulter, A.W. Jr., 54-1, 54-12 to 54-14, 55-1, 56-l Coulter, G.R.. 54-12
4
PETROLEUM
Counihan T. M , 46-44 Courand. G., 36-10 Cox. E.R., 20-12. 20-13 20-17, 20-18 Cozzolino. J.M., 41-37 Craft. B.C., x. 37-27. 39-27, 43-16, 43-17. 43-19, 44-6. 44-16, 4417, 44-49, 48-18 Craig, F.F. Jr., 43-16. 43-17. 43-19. 44-9, 44-l I, 44-19. 4420,44-27 to 44-32.44-34, 4449 to 44-S 1145.13,46-43,4644.47-24 Craigie, L.J., 55-10 Crane Co., 15-33 Crawford, D.L.. 54-12 Crawford, J.G.. 24-22 Crawford, P.B.. 35-21, 44-18, 44-20. 44-21, 44-25. 4449, 4450, 46-46 Crawley, A.B., 55. I 1 Craze,R.C., 36-1, 40-16, 40-17, 40-38 Crenshaw, P.L., 54-12, 54-14 Crichlow. H.G., 48-17 Crichton, J.A., 40-38 Cracker, F.. 6-34. 6-72 Croft, H.O.. 26-33 Cronquist, C. I x, 37-22, 37-23, 37-27 Crookston. H.B.. 48-18 Crookston. R.B., 46-12, 46-43 Crosby, C.C., 4451 Cross, J.H.. 51-50 Crowe, C.W., 54-4, 54-12. 54-14 Crowell, D.C., 28-10, 28-15 Crowell, R.F., 55-12 Crazier, T.E., 25-21 Grump, J.S., 39-28, 45-13 Culberson, O.L.. 25-17, 25-21, 25-24 Culham, W.E., 46-43, 48-18 Cullender. M.H., 5-37, S-38, 5-57, 33-4, 33-6, 33-10, 33-15, 33-23. 34-24. 34-25, 34-27, 34-29, 34-55 Culver, R.B.. 50-38 Cunningham, R.G.. 6-36, 6-38, 6-72 Curtis. s.. IO-14 Cuthbert, J.F.. 53-26 Cutler. R.A., 55-l 1 Cutler. W.W. Jr.. 40-29, 40-38 Cyca. L.C., 45-15 D Dahm, C.G.. ix, 36-11 Dake, L.P., 32-16, 35-21, 37-3, 37-27 Dalati, R.N., 32-1 Dalton, R.L., 4451, 48-20 Daly. A.R.. 52-30 Daneshy. A.A.. 55-l I Daniel, E.F.. 55-12 Daniel Industries Inc.. vii Danniel, A., 25-24, 25-26 Dardaganian, S.G., 43-16, 43-19 DaShanzer, W.A., 569 Daugherty, R.L., 15-33 Davidson. C.D.. 45-15 Davidson, D.W., 25-4, 25-9, 25-23, 25-27 Davidson. J.F., 34-55 Davidson, R.D., 39-28 Davies. E.E., 12-43 Davis, D.H., 26-33 Davis, D-S., 20-13, 20-17, 20-18 Davis, G.J., ix. 34-55 Davis, H.T , 47-25 Davis, J.B., 24-22 Davis, J.E., 25-21. 25-24 Davis, J.J., 54-13 Davis, R.E., 41-37 Day, J.H. Jr., 10-l De. G.S., 51-49 Dean. M.R.. 25-25 Dean, P.C., 44-49 Deaton, W.M., viii, 25-2, 25-5, 25-10. 25-14. 25-20. 25-23
DeFord. R.K.. 24-22 DeGolyer, E.L., 41-7. 41-37 deHaan, M.J., 46-45 Deibert. A.D., 46-44 DeKlss. A.V., 25-21 deKlerk, F., 55-11 DeLoos. T.W.. 25-25 Delshad, M.. 28-11. 28-15 Demaison, C.J.. 52-30 DeMott, D.N., 54-13 Dempsey, J.R.. 48-19 Denekas, M.O.. 44-49 Denoo, S.A., 51-52 Deppe. J.C., 44-29, 4433, 44-34, 44-50 Derr, R.B., 25-27 Desbrandes, R., 50-38 DesBrisay, C.L., 45-15 DeSitter, L.U.. 24-20, 24-23 DeVerter, P.L., 16-16 devries, D.A.. 22-22 DeVries, W., 54-13 Dew, J.N., 46-43 deWitte, A.J., 26-30, 26-31, 26-33, 49-41 DeWitte, L.. 49-41 Deysarkar, A.K., 54.13, 55-12 deZabala, E.F., 47-26, 48-19 Dharmawardhana, P.B., viii. 25-9, 25-11, 25-23, 25-27 Dia.Log Co.. The. xiii Dias-Couto. L.E.. 37-21. 37-27 Dick, J.W.L.. 25.18, 25-24 Dickey, P.A., 24-21. 24-22, 44-49. 4451 Diepen, G.A.M., 25-24. 25-25, 25-27 Dietz, D.N., 35-6, 35-21, 46-43, 47-24 diFranco. R.. 48-20 Dill. W.R., 54-13 Dingman, R.J.. 24-23 Dixon, P.C.. 12-43, 39-26, 39-28 Dixon, T.N.. 48-18 Dobkins, T.A., 55-l 1 Doble. P.A.C.. 16-16 Dodds, W.S., 25-21 Dode, M., 25-22 Dodson. C.R., viii, 22-22, 25-17, 25-21, 37-21. 39-2. 39-27, 41-38 Doh, C.A., 51-50, 51-51 Doherty, W.T., lo-37 Dolan, J.P., 30-13, 30-17 Doll, H.G.. 49-l. 49-41 Dollarhide, F.E., 54-14, 55-l 1 Domenico, S.N., xii, 51-52 Dominquez, J.G., 47-24 Donaldson, A.B., 4645 Donaldson, E.C., 47-26 Donaruma. L.C.. x, 47-24 Donohoe, C.W., 39-1, 39-28 Donohue, D.A.T., 43-17, 45-14 Dorsey. N.E., 24-13, 24-23 Doscher. T.M.. 46-9, 46-43 Dotson. B.J.. iii. 26-33 Dotson, C.R., 24-13, 24-23, 41-5, 41-7 Dotterweich. F.H., S-57, 12-43 Douglas, E., 25-22 Douglas, J. Jr., 44-29, 44.31, 4450, 44-51, 48-14, 48-16, 48-18, 48-20 Dow Chemical Co., viii, 25-24 Dowdle, W.L., 31-7, 52-31 Dowell Schlumberger, xiii Downie, J., 45-14 Drake, E.. 18-l Draper, A.L., 45-14 Dresser-Atlas, xii. xiii, 49-41, 50-38, 51-52 Dresser Industries, v. vi Driscoll. V.J., 36-10. 48-6, 48-18 Droschak, D.M.. 51-50 Dubrevil. L.R.. 4451 Duda, J.L., 47-24 Duerksen. J.H., 46-45. 48-18
ENGINEERING
HANDBOOK
Dut’fy. J.R.. 25-21 Duggan, J.O., 34-46, 34-55 Dukler, A.E.. 34-55 Dumanoir, J.L., xi, 49-41 Dumitrescu. D.T., 34-38. 34-55 Dumort. J.M., 37-27 Dunham, C.L.. 16-16 Dunlap, H.F., 49-41 Dunlap, P.M., 54-13 Dunn, K.J.. 51-49 Dunning, H.N., 39-16, 39-28. 45-51 Duns, H. Jr., 34-36. 34-37, 34-40, 34-55 Dupal, L., xii, 51-51 DuPont Co.. 14-9 Dyes, A.B., 30-17, 35-15, 35-21. 43-8. 43-19, 44-20, 44-25, 44-49, 44-50. 45-14, 47-24 Dykstra, H., 40-18, 40-19. 40-38, 44-7 to 44-9, 4426. 44-29, 4430, 44-32. 4449, 45-14, 47-17, 47-24 Dysart, G.R., 55-12 E Eakins, J.L., 39.16. 39-28 Earlougher, R.C. Jr., x, 30-17, 32-16. 35-19. 35-21, 36-10, 44-29 to 44.31, 445 I. 46-6. 46-43. 46-44 Eaton, B.A., 51-39, 51-52 Eaton, J.R., 6-72 Ebert. C.K., 37-25, 31-27 Eckles, W.W., 39-28 Eddy, H.D., 53-26 Edmondson, T.A.. 44-5 I Edmundson, H., xi, SO-32, 50-38 Edwards, A.T.W.. 25-22 Edwards, C.A.M., xii, 51-52 Eganhouse, R.P., 25-27 Eggleston, W.S., 41-37 Ehrlich, R., 44-51. 46-43, 47-26 Eichenberg, R., v Eichmeier, J.R., 4-l I Eikerts. J.V., 55-l 1 Eilers, H., IS-34 Eilerts, C.K., x. 39-2, 39-4, 39-S. 39-27 Einarsen, C.A., 30-17 Elbel, J.L., 55-12 Elfrink, E.B., 37-27, 40-38 El-Hattab, M.I., 44-51 El-Khatib, N.A.F., 37-27 Elkins, L.E., 55-l I Ellenberger, A.R., 44-51 Elliott Co. Bull. P-l I, 14-9 Elliott, F.B. Jr., 10-l Elliott, L.S., 56-9 Ellis, A.J., 25-21 Ellis, D.V., xi, 50-I. 50-38 Ellis Engineering Inc., vi, 12-43 Ellis, G.O., 12-27, 12-43 Ellison, W.F.. 15-l Elworthy, R.T., 24-22 Ely, J., 54-13 Emanuel, A.S., 48-19, 48-20 Emery, L.W.. 44-51 EnDean, H.J., 16-16 Energy Resources and Conservation Board. 27-9, 34-55, 35-21 Engineering Specialties Inc., vii Engle, D.D., IS-52 Enick, R.M., 40.38, 47.24 Enns, T., 25-21 Enright, R.J., 4451 Erbar, J.H., 14-22, 25-16, 25-24 Erickson, D.D., 25-9, 25-23, 43-19 Erickson, J.W.. 6-72 Erickson, R-A., 43-10. 44-49. 45.14, 47-24 Ersoy, D., 4-l I Espanol, J.H.. 34-37. 34-55
AUTHOR INDEX
5
Essley, P.L. Jr.. 40-38 Eubank. P.T.. 25-21 Eucken, A., 25-21 European Continental Shelf Gutde, 27-9 Evans, H.J., 13-59 Evans, J.G., 46-43 Evans, L.B., 25-24 Evans. R.D.. xi, 50-38 Everett, J.P., 45-14 Everhart, A.H.. 51-52 Evinger. H.H., 32-4, 32-16, 34-31, 34.55, 37-19, 37-27 Ewmg. B.C., 54-14 Ewing, J.. 25-24 Ewing, R.E., 48-19 Ewing, W.M., 51-50 EXLOG. xiii Exploration Logging Inc., xii, 52-30. 52-3 I
F Fagin, K.M., 41-5, 41-37 Fagin, R.G., 48-14, 48-18 Falabella. B.J., 25-23 Fan, S.K., 47-24 Fancher. G.H. Jr.. 34-55 Farhi, L.E.. 25-22 Farkas. E.J., 25-26 Farouq Ah, SM., x, 46-7, 46-13, 46-14, 46-43. 46-46 Farshad. F.F., 35-13. 35-21, 40-38 Fash. R.H., 24-22 Fassihi. M.R.. 46-37, 46-45 Fast, C.R., 55-2, 55-10 Fatt. I.. 26-7. 26-33, 28-10. 28-15. 51-50 Faulkner. B.L., 45-14 Fay. C.H., 44-20, 44-49 Fayers, F.J., 48-18 Feillolay, A., 25-21 Fekete. L.A.. 12-43 Felsenthal. M., 44-29. 44-50 Feldman, W., 6-72 Fenix & Scisson Inc., vi, I I-13 Fenninger, W.D.. 25-2 I Ferrero, E.P.. 21-20 Ferrier. J.J., 4645 Fertl. W.H.. 50-38, 51-52, 55-l 1 Fetkovich. M.J., 34-l, 34-3 I. 34-33, 34-55, 38-8, 38-20 Fettke, C.R.. 24-i. 24-21 Fillipone, W.R., 51-52 Finch. E.M., 44-51 Firoazabadi, A., 48-19 Fischer, F., 25-2 I Fischer Governor Co.. vi Fischer, K.F., 56-l Fischer, M.J.. 4425, 44-50 Fisher Controls Co., vi Fiske. L.E., 41-2. 41-37 Fiskm. J.M.. viii. 23-13 Fitzgerald. P.E.. 54-l. 55-l. 56-l Flaim. C.. 50-38 Fleming, P.D. III, 48-18 Fletcher, C.R., xii. 51-51 Flid. R.M., 25-24 Flippen. F.F.. 54-12 Flock, D.L., 44-20, 44-50 Fluor Subsea Services. vii Fogler. H.S., 54-13 Fomina. V.I.. 25-23. 25-28 Fong, D.K.. 48-18 Forts, L.. 51-52 Fontaine, E.T.. 19-34 Ford, G., l-69 Ford, W.G.F.. 54-13 Forsyth, P.A.. 48-20 Forcer. H.P. Jr., 48-19 Fwtcr. J.H.. 3-l
Foster, K.W., 16-16 Foster. V.. 41-37 Fowler. E.D., 3-40 Fowler, F.C., 34-4, 34-55 Fowler, P.T.. 52-22, 52-31 Fox, C.J.J.. 25-22 Fox, K.B., 54-12 Fox, R.L., 46-45 Frailing, W .G.. 40-38 Franck, E.U., 25-21, 25-22. 25-24 Franklin, P., l-l, I-68 Franks, J.E., 55-10 Fraser, H.J., viii, 26-33 Frauenthal, J.C., 48-11. 48-20 French, W.S., 36-11 Frick, T.C., iii, 46-45 Fried, A.N., 45-14, 47-25 Friedman, R.L., 25-18, 25-24 Fritsch, D.R.. 16-16 Friz, H., 25-21 Frnka, W.A., 46-44 Froelich. B., 51-52 Froltch, P-K., 25-21 From, K.T., 45-15 Froning, H-R., 25-27, 47-25 Frost. E., 50-38 Frost, E.M., viti, 25-2, 25-5, 25-10, 25.14, 25-20, 25-23 Frost. J.B.. 54-13 Fuhner, H., 25-26 Fulcher. R.A.. 28-12, 28-16 Fuller, K.L., 48-18 Fulton, K.. 36-10 Funkhouser. H.J., 24-22 Fussell, D.D.. 48-18. 48-19 Fussell. L.T.. 48-18
G Gaddy, V.L., 25-15, 25-17, 25-22, 25-23 Gadelle, C.P., 46-45 Gainar, I., 25-22 Galbraith, M., 36. I I Gale. R.P., 25-26 Gall, J.W., 47-24 Galley, J.E., 29-9 Galloway, J.R., 46-44 Galloway, T.J.. viii, 25-2, 25-20, 29-9 Garb, F.A., 40-l. 40-37. 41-l. 41-5, 41-37 Garder, A.O. Jr., 37-2 I, 37-27. 48-14, 48-18 Gardner, D.C., 55-l I Gardner, F.H., 25-22 Gardner, G.H.F.. xi, xti, 26-28, 26-33, 36-11. 45-14, 45-15, 51-7, 51-47. 51.50, 51-52 Gardner, J.S.. xi, xii, 49-41, 50-38, 51-35, 5 l-52 Gardner, L.W.R., xi, 51-50 Garms, K.M., 43-l Garon, A.M., 46-43 Garrison A D , 24-2. 24-22 Garthwaite. D.L.. 43-16 Gartner. J., 51-45, 51-52 Gas Processors Suppliers Assn. (GPSA) vi, vii. viii. 12-43. 13-59. 14-17, 14-22, 20-18, 23-11. 23-13. 39-12, 39-27 Gash, B.H.. 47-24 Gaskell, M.H.. 45-14 Gaskell. T.F., 12-43 Gassmann. F.. 51-8. 51-11. 51-36, 51-49, 51-51 Gates, C.F., 46-15 to 46-17. 46-19. 46-44. 46-45 Gates. G.L.. 26-33. 44-51 Gatlm. C.. 45-13 Gearhart. 49-41 Gecrtsma, J.. 26-7.26-33. 51-E. 51-51. 55-l I
Geffen, T.M., 39-15, 39-28. 43-17, 43-19. 44-29, 44-50, 45-13, 46-13. 46-14, 46-43 General Conference of Weights and Measures (CGPM), 58-4, 58-10, 58-18 Gentry, R.W., 41-37 Geophysics, 51-50 George. C.J., 36-10 George, R.A., 4451 Geotimes, 25-24 Gernet, J.M., 45-15 Gester, G.C.. 25-26 Geyer, R.L.. xti, 51-51 Ghassemi, F., 46-9, 46-43 Ghauri, W.K., 44-51 Giacca, D., 52-3 I Gibbs, G.B., 25-26 Gibbs, J.W., 25-I. 25-20 Gibbs, S.G., IO-37 Gidley, J.L., 54-11, 54-12. 56-9 Gilbert, W.E.. 34-45, 34-46, 34.55 Gilchrist, W.A. Jr., 50-38 Gillespie, P.C., 25-15, 25-21 Gilliland, H.E., 47-26 Gillund, G.N., 45-15 Gilman, J.R., 48-5, 4X-18 Giussani, A , 25-27 Giustt, L.E., 4643 Gjaidbaek, J-C., 25-21, 25-25 Gladfelter, R.E., 38-20 Glaister, R.P., 24-22 Glasser, S.R., 45-15 Glew. D.N.. 25-23 Glinsmann, G.R., 47-25 Clover, C.J., 47-25 Goetz, J.F., xii, 51-20, 51-51 Gogarty, W.B.. 45-13. 47-25, 48-18 Golan, M., 37-21, 37-27 Gelding, B.H., 21-10. 21-11. 21-13, 21-15, 21-16, 21-20 Golding, R.M., 25-21 Goldman, R., 51-50 Goldsmith. R.G.. 52-31 Goldup, A., 25-26 Golub, G.H.. 48-20 Golynets, Y. F., 25-24 Gomaa, E.E., 4617,46-18.46-45.48.6,48-I8 Gondouin, M., 49-40 Gooch, F.W. Jr., 45-14 Goodman, J.B., 25-22 Goodman, M.A.. IS-52 Goodwill, D., 22-22 Goodwill. W.P.. 51-52 Gordon, W.C., 24-2, 24-22 Gosline. J.E., 6-36, 6-37. 6-72, 22-22, 34-55 Gottfried. B.S. 48-18 Goudouin, M., 49-4 I Gould, T.L., 3440, 34-55, 34-56 Govier, G.W., 40-38, 55.11 Goyal. A., 47-26 Grabowski. J.W., 46.12, 46-43 Graciaa, A.. 47-25 Graebner. R.J., ix, 36.10, 36-l I Graham, D.E.. 19-34 Graham, J.W.. 54-13. 55-12 Granberry, R.J.. 50-38 Grant, A.A., 6-72 Grant, B.R.. 46-43 Graton, L.C., viii, 26-33 Graue. D.J., 23- 13.445 I. 47-26.48-6. 48- I8 Graves. R.M., 26-9. 26-33 Gravia. C.K.. 12-43 Gray. K.E.. 30-17 Greaser, G.R., 46-44 Grew. G., 25-2 I Green. E.B.. 54-13 Greenberger, M.H.. 40.38.4429.4432,4451
6
PETROLEUM
Greenkorn, R A. / 36-10 Greenwalt. W.A., 41-37 Gregory, A.R.. xi, xii. 26-33, 51-8, 51-36. 51-50. 51-51 Grever, J., 25-21 Griffcth, B.L., 45-14 Griffin, F D., 10-l Griffith, J.D.. 45-15, 48-19 Griffith, P.. ix, 34-37 to 34-39, 34.55 Griffith, T.D., 47-24 Grigoriou. G.C.. 25-28 Griialva, V.E., 51-52 C&m. R.E., 41-26 Griswold, .I.. 25-27 Griswold. W.T., 24-1, 24-21 Grocneveld, H., 4451, 58-2 Groschuff. E., 25-27 Grosmangin, M., 51-52 Grossling, B.F., 41-37 Grosso, D.S., 53-26 Grove, M.L., 39-28 Grovenhurg. W.W., 16-17 Gruy, H.J., 40-38, 41-5. 41-37 Guhbins. K.E., 25-21 Guckert, L.G., 44-21, 44-50 Guerrero, E.T., x, 12.43, 37.15, 37.27, 44-29 to 443 1, 44-5 1 Guimard, A., ix. 30-16 Gum, J.A., 54-14 Gulati. MS.. 56-9 Guler, N., 55-11 Guppy, K.H.. 55-11 Gurley. D.G., 56-9 Gustavson. F.G., 48-20 Gusto, B.V., vii Guthrie, R.K., 40-38, 44-29, 44-32, 44-51 Guyed, H., xii, 4941. 51-50
H Haafkens, R., 54-13. 55-l I Haas, N.C., 25-22 Habermann, B., 4420. 4450, 45-14 Hachmuth, K-H., 25-25 Hadley, K., 51-11, 51-51 Haehnel, 0.. 25-21 Hafemann. D.R., 25-25, 25-27 Hagedorn. A.R., 34-37, 34-55 Hagernan, P.S., 30-16 Hagenar. D.S.. ix Hagoort. J., 28-l 1, 28-15, 47-24 Halbouty, M.T., 29-9 Hail. A.H., 16-17 Hall, A.L., 46-44 Hall, B.E., 54-13 Hall, C.D. Jr., 55-11 Hall, H.N., 26-7 to 26-9, 26-33, 45-13 Hall, K.R., 20-8, 20-9, 20-18. 25-21, 33-18, 33-23 Hamilton Bras. 011 Co., vii Hammerlindl, D.J.. 4-l 1. 26-8, 26-33 Hammerschmidt, E.G., 25-23 Hancock, G.L. Jr., 40-38 Hand. J.H.. 25-24, 25-28 Handy, L.L., 37-27 Hanna. M.A.. 29-9 Hannah. R.R.. 55-l I Hansen, D.N.. vii Hansen, P.W., 45-15 Hanson, J.M., 55-l 1 Hanson, M.E.. 55-11 Hanzlik. E.J.. 48-6. 48-18 Harbert. L.W.. 28-12, 28-16 Harder. A.H.. 25-21 Harder. M.L.. 32-3. 32-16 Hardy, G.W. III. 57-12 Hardy, 1-H.. 45-15 Hardy. W.C., 46-44, 46-45
Harouaka, A., 44-51 Harpole, K.J., 48-10, 48-19 Harrington, L.J., 55-l I Harris, C.D., 48-18 Harris, D.G., 36-10 Harris, F.N., 54-13 Harris, L.E., 54-13 Harris, L.W.. 55-l I Harris, M.H.. xii, 51-35, 51-47, 51-52 Harris, O.E., 54-13 Harris, P.C., 55-11 Harris, W.E., 24-22 Harrisberger, W.H., 54-12 Harrison, N.H., 39-28 Hatting, P., 25-24 Hartley, K.B., xii, 51-34, 51-52 Hartman, J.A., 36-10 Hartsock, J.H., 4450 Harvey. A.H.. 48-20 Harvey, M.T., 45-15 Harvey, R.P., 53-26 Harwell, J.H., xi, 47-25 Hasiba, H.H., 47-26 Hassan, M., 50-38 Hassler, G.L., 28-2, 28-3, 28-5 to 28-7, 28-15 Hatch, M.J., x, 47-24 Hauber. W.C.. 44-29. 44-50 Haughn, J.E., 25-25 Havlena, D.. 37-2, 37-3, 37-6, 31-7, 37-27. 38-12, 38-20 Hawes, R.I., 48-18 Hawkins, M.F. Jr., x, 23-1, 24-14, 24-23, 37-27, 39-27, 40-38, 43-16, 43.17, 43-19, 44-6, 44-16, 4417, 4449, 48-18 Hawthorne, H.R., 49-41 Hayduk, W., 25-22 Hazebroek, P.. 35-16. 35-21, 4435, 44-51 Heald, K.C., 31-7 Healy, R.N., xi, 47-13, 47-25 Hearn. C.L., 46-44, 47-24, 48-8, 48-10, 48-19 Heaviside, J.. 28-12, 28-16 Hebard, G.G., 16-16 Hegner. J.S., 54-13 He&a. A.A., 28-12, 28-16 Heinemann. Z.E.. 48-19 Heins, C., 25-23 Helander, D.P., 51-43, 51-52 Helfferich, F., 47-25 Heller. J.P., 44-50 Hellums. L.J., 48-19 Hempkins, W.B., xi, 51-51 Henderson, J.H., 46-19. 48-6, 48-18 Hendrick, J.O. Jr., 56-Y Hendrickson, A.R.. 54-I. 54-12 to 54-14 Hendrickson, G.E., 44-28, 4429, 44-50 Hendrix, J.R.. 8-l Henley, D.H., 4449 Henry, J.R., 34-46. 34-55 Henshaw, T.L., 6-72 Henson, W.L., 38-20 Hepp, V.R., 53-26 Herald, F.A., ix, 29-9 Herbeck, E.F., 45-15, 48-18 Hermanson, D.E., 9-1 Herrera, A.J. ( 46-44 Herrera. J.Q., 48-6, 48-18 Herring, E.A., xii, 51-52 Herron. E.H. Jr., 48-18 Herron. M.M., 50-38 Herschel, W.H., 22-22 Hertzberg, G., 25-21 Hertzberg, R.H.. 4645 Hertzog, R.C.. xi, 50-38 Herzfeld. J.R., 41-37 Hestenes. M R., 48-20 Heuer. G.J.. 44-50
ENGINEERING
HANDBOOK
Hewitt, C.H., 36.10, 46-44 Hewlett-Packard, 22-17, 22-22 Hiatt, W.N.. 44-29, 44-51 Hickman, B.M., 44-50, 46-45 Hicks, A.L.. 38-3, 38-20 Hicks, W.G., 51-6, 51-19, 51-50, 51-51 Higgins, R-V., x, 40.38, 4428 to 44.30, 44-32, 44-50, 45-17 Highland Pump Co. Inc., Y Hilchie, D.W., 50-38, 51-52 Hildebrand, M.A.. 25-28 Hildebrand, S.M., 16-17 Hill, D.G., 54-13 Hill, G.A., 30-17 Hill, H.G.. 41-37 Hill, H.J., 26-30, 26-31, 26-33, 47-26, 49-41 Hill, K.E., 41-37 Hill, R., 51-51 Hill, R.W., 16-16 Hillestad, J.G., 48-20 Hilterman, F.J., 36-l I Hiltz, R.G., 43-17 Hmds, R.F., 37-23, 37-21, 40-38, 45-l Hiraoka, H., 25-24 Hirasaki, G.J., 47-5,47-9, 47-24.47-25.48-20 Hitchon, B., 24-22, 24-23 Hobson, G.D., 40-38 Hock, R.L., 39-28 Hockaday, D., 4451 Hocott, C.R., 24-22, 39-28 Hodgson, H., 53-26 Hoenmans, P.J., 44-51 Hoffman, A.E., 39-12, 39-28 Hoffman, S.J., 46-45 Hake, S.H., 24-22 Holbren, J.H., 44-51 Holbrook, S.T., 47-25 Holden, W.R., 25-21 Holden, W.W., 39-28 Holder, G.D., 25-18, 25-24, 25-28 Holditch, S.A., 55-12 Hollingsworth. F.H., 54-12 Holloway, C.C., 48-19 Hollrah, V.M., 45-14 Holm, L.W., 45-l. 45-13. 45-14, 45-15, 47-9, 47-25 Holman, G.B., 54-13 Holmes, B.G., 46-19. 46-45 Holmes, C.S., 34-55 Holmgren, C.R., 44-49 Holste, J.C., 25-21 Holt, O.R.. 53-26 Homma, T., 25-22 Hon. M.S., 20-7, 20-18 Honarpour, M., 28-16 Hood, J.T., 10-l Hopkins, E.A., 52-30 Hopkinson, E.C., 50-38 Horn, A.B., 25-21 Home, A.L., 45-15 Homer, D.R., 30-9, 30-10, 30-17, 35-15, 35-16, 35-19, 35-21 Hoskold, H.D., 41-16, 41-18, 41-20 to 41-22, 41-37 Hoss, R.L., 43-17 Hossin, A., 50-38 Hottman, C.E., 51-39, 51-52. 52-30 Houghton, G., 25-22 Houston Geological Society. ix. 29.9 Howard, D.S. Jr., 38-20 Howard, G.C., 55-2. 55-10 Howard, J.V.. 46-45 Howe, L.S., 25-23 Howell, J.C., 46-42 Howell, J.V., 24-21 Howell, R.G.. 36-10 Hoyer, W.A., 50-38 Hoyt, W.V., ix, 29-l
AUTHOR INDEX
Hsiao, L., 44-5 1 Hsu, C.C., 25-21 Hsu, W., 47-25 Huang, W.. 46-43 Hubbard. M.G.. 34-55 Hubbard; R.A.,‘41-37 Hubbert. M.K.. 26-33, 29-9, 5144, 51-52 Hubby, L.M., 16-16 Hudock. K., 54-13 Hughes, D.S., 51-50 Huh, C., 47.13, 47-25 Hung, J.H., 25-21 Hunt, E.R.. xii, 51-52 Hunt, J.M., 23-13 Huntington, R.L.. 25-27, 40-38 Hurd, C.O., vii Hurdle, J.M., 43-17, 45-15 Hurford, G.T., 45-15 Hurst, R.E., 55-10, 55-l 1 Hurst. W.. 30-10. 30-14. 30-17. 35-l 35-21, 38-l. 38-E. 38-20, 39-20, 39-28, 40-37, 4417, 44-20, 44-29, 44-49, 45-15 Hutchinson, C.A. Jr., x. 30-17, 35-15, 35-21. 44-25, 44-50, 45-13, 45-14 Hutchinson, T.S., 38-20 Hutton, J.M., 25-28 Huygen, H.H.A., 46-43 Huzarevich. I.E., 43-17 Hvizdos. L.J.. 46-45 Hwang, M.K., 48-18 Hvdraulic Inst.. 6-50, 6-72 Hydrocarbon Research Inc., vii I Illiyan, IS., 53-26 Imai, S., 25-25 Independent Petroleum Assn. of America (IPAA), 41-37 Inga. R.F., 25-25 Ingersoll, A.C., 15-33 Ineram. J.D.. 51-51 Inks, C.G., 4451 Inst. Francais du P&role, 28-7, 28-15 Inst. of Electrical and Electronic Engineers (IEEE): IEEE Std. 117, IO-37 IEEE Std. 260, 58-8 IEEE Std. 268, 58-8 Interscience Encyclopedia Inc., vii Interstate Oil Compact Commission, 33-13, 33-23, 39-27 Intl. Bureau of Weights and Measures (BIPM), 58-10 Intl. Organization for Standardization (ISO), 12-43, 58-3, 58-11, 58-12 IS0 31/O, 58-8 IS0 1000, 58-8 IS0 R370. 58-8 IS0 2955, 58-8 KWIC Index of Intl. Stds., vi Intl. Union of Pure and Applied Chemistry, 58-7 Intl. Union of Pure and Applied Physics, 58-7 IPAA, 41-37 Irick, J.T., 18-52 Isenhower, W.M., IS-52 Ivey, D., 5149 Iyoho, A.W., 46-13, 46-14, 46-43 Izabakarov. M. 25-21
J Jacks, H.H., 48-19 Jackson, J.A., 29-9 Jacobs, W.L., 47-25 Jacoby, R.H. 20-8, 20-18, 25-27, 37-23 to 37-25, 37-27, 40.38, 43-4, 43-16, 43-17, 43-19, 45-14, 48-19
Jacuzzi. R., 6-34, 6-72 Jageler, A.H., 51-51 Janzen, H.B., 44.19, 4420, 4434, 4449 Jaragua S.A. Industrias Mechanicas, vi Jardetzkv. W.S.. 51-50 Jardine,‘D.. 36.5. 36-10 Jea, N.C.. 48-20 Jeffries-Harris, M.J., 44-51 Jenkins, R.A. Jr., 54-14 Jenkins, R.E., 27-1, 50-38 Jenks, L.H., 45-15 Jennings, A.R., 54-13 Jennings, H.Y. Jr., 47-19. 47-20, 41-26 Jennings. R.R., 47-24 Jensen, C.M., 23-13 Jensen, J., 24-22 Jessen, F.W., 24-22 Jhaveri, I.. 25-28 Jines, W.R., 48-18 Joffe, J., 20-7, 20-18. 48-18 Johansen, R.T., 4451 John, V.T.. 25-28 Johnson. C.E. Jr., 40-19, 40-38, 44-9, 4432, 4449, 44-51, 45-14, 47-24, 47-26. 48-18 Johnson. C.R.. 36-10 Johnson, D.H., xi, 51-50 Johnson, E.F., 45-14 Johnson, G.A., 48-6. 48-18 Johnson, H.M., 49-42 Johnson, J.P., 36-10, 44-29, 4450 Johnson, L.A., Jr., 46-3, 46-43, 4645 Johnson, O.C., 45-14 Johnson, R.K., 51-39, 51-52, 52-30 Johnson, W.M., Jr., 53-26 Johnston, N., 26-33 Jones, A., 55-10 Jones, K.E., 40-38 Jones. L.G.. 56-9 Jones, R.G., viii, 26-33 Jones. S.B.. xi, 51-50 Jones, S.C.. 28-15 Jones, T.J., 19-34 Jordan, C.A., 44-37, 44-51 Jordan, D., 25-26 Jordan, J.K.. 44-51 Jorden, J.R., 49-42, 52-24, 52-31 Joris, G.G., 25-25 Jorque, M.A.. 445 1 Josendal, V.A.. 45-14 Joseph, C., 46-45 Jossi, J.A., 20-18 J. Cdn. Pet. Tech., 46-45 Judson, L.V.. l-l. l-68 Jung, K.D., 4644 Justen, J.J., 4451, 45-14 Justus, J.B., 43-16 Justus. W.W., 6-63. 6-72 K Kamp, A.W., 53-26 Kandarpa, V., 4451 Kane, A.V., 45-15 Kansas State Corp. Commission, 39-27 Kasamovskti, J.S., 25-17, 25-24 Kasch, J.E., 25-27 Kasic, M.J. Jr., 48-20 Katz, D.L., vii, 12-43, 20-5, 20-9, 20-10, 20-18, 22-4, 22-17, 22-21, 22-22, 25-2. 25-3, 25-5, 25-10, 25-l 1, 25-16 to 25-18. 25-20, 25-21, 25-23, 25-24, 25-28, 26-28, 26-33, 34-55, 34-56, 39-1, 39-27, 40-15, 40-38, 45-14, 48-18. 48-19 Kavvadas, M., 55-l 1 Kay. W.B., 20-5, 20-10 Kazaryan, T.S., 25-25, 25-26
Kazemi. H.. 48-5. 48-18. 4X-19 Keeney, B.R., 54-13 Keese, J.A.. 46-45 Kehn, D.M.. 45-14 K&man. S.. 25-22 Keller, G.V., 49-42 Kelley, H.S.. 16-16 Kelley, L., 6-72 Kelly, J.L., 51-50 Kelly, P., 43-17 Kelm, C.H., 45-15 Kelton, F.C., 26-7, 26-33 Kemp, C.E., 38.20, 4450 Kempton, E.A., 6-72 Kendall, H.A., 45-14 Kennedy, G.C. 25-22 Kennedy, H.T., viii, 26-21, 26-33, 39.13, 39-28 Kennedy, S.L., 43-17 Kern, L.R.. 43-4. 43-16. 43-19. 55-2. 55-10 Kersch, K.M., 30-17 Kershaw, D.S., 48-20 Kerver, J.K., 4942 Kesler, M.G., 20-13, 20-17, 20-18 Kestin, J., 24-16, 24-23 Khalifa, H.E., 24-23 Khan, S.A., x, 47-25 Kharaka, Y.K., 24-23 Khitarov, N.I.. 25-22 Khoury, F., 25-20 Khristianovitch, S.A., 55-2, 55-10 Khurana, A.K., 48-20 Kieschnick, W.F. Jr., 45-14 Killian, J.W.. 4425, 4450 Killough, J.E., 48-19. 48-20 Kilmer, J.W., 39-28 Kim, J.J., 25-24 Kimball, C.V., 51-51 Kimbler, O.K., 44-2 I, 44-49 Kimmel, J.D., 32-l Kimmell, G.O., vi, 12-43 Kincheloe, R.L., 54-13 King, A.D. Jr., 25-21 King, G.E., 54-12, 54-13, 55-l 1 King, M.S., xi, 51-S. 51-9, 51-50 to 51-52 King, R.E.. 29-9 King, W.R., v, 5-12 Kinra, R.K.. 18-52 Kirby, I.E. Jr., 43-16 Kircher, C.E. Jr., 21.10, 21-20, 22-22 Kirk, R.S., 46-44 Kirkpatrick. C.V., v, 5-l. 5-37 Kithas, B.A., xii, 51-52 Klaus, E.E., 47-24 Klausutis. N.A.. 25-25 Kleppinger, K.B., 16-17 Klinkenberg, L.J., viii, 26-18. 26-33. 28-13 Kloepter, C.V., 45-15 Kloth, T.L., 4645 Klots, C.E., 25-22 Klotz, J.A., 56-9 Klovan. I.E., 24-23 Knapp, H., 25-18, 25-24 Knezek, R.B., 43-16 Knopoff, L.. 51-46, 51-52 Knox, J.A., 54-12. 54-13 Kobayashi, R., viii, 20.15, 20.18. 25-l to 25-3. 25-5, 25-10, 25-l 1, 25-15, 25-17. 25-18, 25-20, 25-21, 25-23, 25-24, 25-28, 39-21 Kobe, Inc., v, 26-6 Kobe, K.A., 25-22, 25-24 Koch, H.A. Jr., x, 43-19, 45.13, 45-14 Koch, R.L., 4643, 46-45 Koeller, R.C., 40-38 Koepf, E.H.. 27-l Koerperich, E.A., 51-24, 51-25. 51-51 Kokesh, F.P., 51-51. 51-25, 51-51
a
PETROLEUM
Kokesh. F.P.. 51-51. 51-52 Kolodzie, P.A.. 44-51, 47-26 Konen, C.E., 53-26 Koppers Co. Inc., 1 l-14 Kornfeld. J.A.. 44-5 1 Korringa, J., 51-8, 51-51 Kortekaas, T.F.M., 28-12, 28-15 Koshelev. V.S.. 25-28 Kotcher, J.S.. 36. I I Krase. N.W., 25-22 Krause, D.J., 25-22 Krautkrimer, H., xi, 51~50 Krautkramer, J., xi, 51-50 Krebill, F.K.. 43-16 Krebs, H.J.. 44-51 Kreft, A., SO-38 Krejci-Graf, K.. 24-22 Kresheck, G.C., 25-26 Krichevskii, I.R., 25-17, 25-22, 25-24 Krishnan. C.V.. 25-18. 25-24 Krueger, R.F.. 56-9 Krueger, W.C. Jr., 36-10 Krug, J.A., 26-9, 26-33 Kruk, K.F., 54-12, 5414 Krumbein, W.C., viii, 26-7, 26-33 Krutter, H., 4421. 44-50 Krynine, P.D., 29-9 Kuba, D.W., 48-20 Kufus. H.B.. 4429. 4450 Kuhn, C.S., 46-43 Kunerth, W., 25-22 Kunkel, G.C., 36-10 Kuntz, E.. 57-12 Kunz, K., 4941 Kunze, K.R., 54-13. 54-14 Kurovskaya, N.A., 25-24 Kuster, G.T., 51-34. 51-52 Kvenvolden. K.A.. 25-18, 25-24 Kwan, T.V., 48-20 Kwong. J.N.S., 20-7, 20-8, 20-18, 23-12. 23-13, 39-28 Kyte, J.R., 44-49, 48-10, 48-19
L Labrid, J., 54-13 Lacey, J.W., 45-14 Lacey, W.N., x, 21-10, 21-20, 22-22, 23-13, 25-20, 39-2, 39-21, 45-14 Lachance, D.P., 26-9, 26-33 Lackland, S.D., 45-15 Lagers, G.H.C., vii Lahring, R.I., 44-51 Lajtai, I., 25-2 I Lake, L.W., xi, 28-15, 47-1, 47-24 to 47-26, 54-14 Lam, KY., 55-11 Lamborn, R.E., 24-22 Lamont, N., 49-41 Lampe, H.W., 48-20 Land, C.S., 28-12, 28-15, 44-49 Landrum, B.L., 44-25, 44-50 Lane, A.C., 24-2. 24-22 Lane, L.C., 45-15 Langenheim, R.N., 46-7 to 46-9. 46-43 Langston, E.P.. 4436, 4451 Langton, J.R., 43-17 Lannung, A., 25-2 I Lantz, R.B., 46-9, 46-1 I, 46-43, 48-10, 48-19 Larson. R.G., 47-25 Larson. S., 25-23 Larson. T.A., 41-1 Lasater, J.A., 7-9. 7-17, 22-5 to 22-10, 22-22 Las&r, R.H., 15-l Lasater, R.M., 54-13 Last, G.J., 43-17
Laulhere. B.M., 25-2 I Laumbach. D.D.. 46-43 Law. J., 39-28 Lawrence. L.L., 1244 Laws, W.R., xii, 51-52 Lawson, J.B., 47-9, 47-25, 47-26 Lawson, I.D.. 34-37. 34-55 Lea, J.F., 5-52, 5-57 Leach, R.O., 44-40, 44-51, 47-26 Leas, W.J., 44-50 Lease, W.O.. 28-7, 28-12, 28-15 LeBlanc. R.J., 36-3, 36-10 LeBreton, J.G., 25-26 Ledbetter, R.L., 3820 Ledlow, L.B., 54-13 Lee, B.D., 4417, 4449 Lee, B.I.. 20-13, 20-17. 20-18 Lee. J.. 35-12. 35-21 Lee. M.H., 54-13 Lee, S.T.. 46-31. 4645 Lee, W.J., 55-12 Lefebvre du Prey, E.J., 28-10. 28-15 Letkowitz, H.C., 40-38 Leggett, B., 54-13 Leibrock. R.M.. 43-17 Leighton. A.J., x, 44-28 to 44-30, 44-32, 44-50. 45-14 Leland, T.W. Jr., 25-24 Lemanczvk. R.. 55-12 Lents, M.R., x, 39-19, 39-20, 39-23, 39-28 Lentz, H., 25-24. 25-25 Leonardon, E.G., 31-7, 51-50 Lerner. B.J., 12-43 Lescarboura, J.A.. 55-12 Lesem, L.B., 39-25, 39-28 Lester, G.W.. 44-35, 44-51 Letkeman, J.P., 48-20 LeVelle, J.A.. 16-16 Leverett, M.C., 26-24, 26-33, 28-2. 28-3, 28-6. 28-7. 28-15. 40-13. 40-17. 40-18. 40-38, 43-3, 43-4, 43-16, 43-19; 444, 44-7. 44-9 to 44-l 1. 44-26. 44-29. 4449, 47-2, 47-24, 48-1, 48-18 Levesque, J.M., 48-20 Levine, J.S.. 37-21, 37-22, 37-27 Levorsen, A.1.. 29-9 Lewin and Assocs. Inc., 46-4, 46-13, 46- 14, 46-43 Lewis, C.R., 52-31 Lewis, J.O., 40-15, 40-38, 44-49 Lewis, P.E., 55-I I Lewis, W.B., 44-4, 44-49 Lewis, W.K.. 22-22 Lewis, W.M., 37-27 Li, C.C., 25-25 Liabastre, A.A., 25-26 Lien, C., 48-19 Lin. C., ix, 28-12, 28-15 Lindbad, E.N., 39-27, 45-15 Lindsey, W.C., 18-52 Lipson, L.B , 49-42 Lisbon, T.N., 3446, 34-55 Little, L.A , IO-I Little, T.P., 46-44 Lockhart, R.W., 34-37, 34-55 Loa Analyst, The, xiii Logan. J.i., 4- 11 Logan, J.M.. 55-12 Lo&. R.E., 43-17 Loncaric, I.G., 44-20, 44-37, 44-50 Lone Star Steel. 2-46, 2-74 Longeron, D.G.. 28-l I, 28-15 Longstaff, W .J.. 48 19 Loomis. A.G., 28-10, 28-15 Loprest, F.J., 25-22 Lorenz, P.B.. 47-26 Lotter. Y.G.. 25-26 Loveless, G.W.. 51-52
ENGINEERING
Lovell, F.P.. 25-25 Low, J.W., 52-9. 52-30 Lowe, R.M., 38-20 Lay. M.E.. 49-41 Lubinski, A., 4-l 1 Lubojacky, R.W., 36-10 Lucas, M.. 25-21 Lufkin Industries Inc., vi Lumpkin, W.B.. 43-17 Lund, K., 54-13 Luque, R.F., 54-13 Lybarger, J.H., 54-13 Lynch, E.J., xii, 44-29, 4450,
HANDBOOK
51-51
M Maas, 0.. 25-22 MacDonald, R.C., 48-14, 48-20 Mace, C., x, 4644 MacLean. M.A.. 46-44 MacNaughton. L.W., 41-37 Macon, R.S., 45-15 Macrygeorgos. C.A., 40-38 Maddox, R.N., 14-l. 14-22 Maerker, J.M.. 47-6, 47-24 Maharijh, D.M., 25-27 Maher, l.c., 52-9, 52-30 Maini. B.B., 28.12, 28-15 Majani, P., 51-52 Makogon, Y.F., 25-18, 25-23, 25-24 Malesinska. B.. 25-22 Malik, V.K., 25-22 Malinin, SD., 25-22, 25-24 Maly, G.P., 56-9 Mantillas, G., 54-13 Mandl, G.. 46-8, 46-9, 46-15, 46-43 Maney, E.. 47-26 Mann, L.D., 48-6, 48-18 Manning, R.K., xi, 47-6, 47-24 Mansurov, RI.. 19-34 Mapes, G.J., 1243 Markham, A.E.. 25-22 Markhasin, IL., 28-11, 28-15 Marrs, D.G., 45-15 Marshall, D.L., x, 39-20, 39-21, 39-28 Marshall, D.R., viit, 25-2, 25-5, 25-20, 25-24 Marshall, P.W., 18-52 Martin, F.D., x, 47-22, 47-24, 47-26 Martin, J.C., 35-2. 35-21, 43-16, 44-50 Martin, J.J., 20-8, 20-18, 39-28, 48-18 Martin, J.W., 7-17 Martin, M., 49-1, 49-41 Martin, R.C., 54-12 Martin, W.A.. 40-38 Martin, W.L., 4643, 46-45 Martinelli, R.C., 34-37, 34-55 Martinez, S.J., 54-l. 55-1, 56-l Marx, J.W., 46-7 to 46-9. 46-43 Marzetta, T.L., 51-51 Maslennikova. V.Y., 25-22, 25-23, 25-26 Matheny, S.L. Jr., 16-16 Mathews, J-D., 48-18 Mathews, M.A., 51-52 Matous, J., 25-22 Mattax. C.C.. 44-49. 48-19. 48-20 Matthews, C.S., 35-16, 35-21. 40.38, 4425, 44-50. 44-51 Matthews, T.A., vii, 20-9, 20-10, 20-18 Matthies, E.P., 36-10 Mauerer, O., 25-18, 25-24 Maurette, C., 51-50 Mayer, C.. 49-42 Mayer, E.H., iii, 22-22. 47-26 Mayhill, T.D., 54-12 Mayland, B.J., x, 46-37. 46-45 Mayorga, G., 25-24 Mazzullo. S.J.. 29-9
9
AUTHOR INDEX
McAdams, W-H.. 46-43 McAuliffe, C.D.. 24-23, 25-21. 47-20. 47-26 McBain. J.W.. 25-25 McBean. W.N. 1 46-44 McBride. J.R., 54-13 McCaffery. F.G., 28-11. 28-15 McCann. C.. 51-52 McCann, D.M.. 51-52 McCarter. E.D.. 48-18 McCarty, D.G.. 44-17. 44-49 McCarty, E.L., 25-2 I McCarty. G.M.. 44-17, 44-49 McCaskill, N.. 45-15 McCay. R.C., 25-22 McClaflin. G.G.. 6-72. 19-34 McClellan, J.H., xii. 51-51 McClendon, R.. 52-54. 52-31 McCormick. G.W.. viii McCord, D.R.. 43-16 McCracken. T.A.. 48-11. 48-19 McCray. A.W.. 41-37 McCrossan, R.G., 24-22 McCulloch. R.C.. 43-17 McCune. C.C., 44-37. 4451. 54-13 McCurdy, R.C.. 26-33 McDaniel, R.R.. 55-I I, 55-12 McDonald, A.E., 48-20 McDonald, G.H.F., 51-46, 51-52 McDonald, J.A.. 36-l I McDow. G.. 54-13 McElwee, P.G.. 58-S McEvoy Co., v McFarlane, R.C.. 43-17 McGarry. M.W. Jr., 40-37. 41-38 McGhee. E.. 16-16, 19-34 McGinty, J.E., 54-14 McGrain, P., 24-22 McGraw. J.H.. 43-17 McGuire, W.J., 54-9, 55-10 McKelvey. J.G.. 24-23 McKetta. J.J.. 25-l. 25-16. 25-17, 25-21. 25-23. 25-24. 25-25. 25-26, 25-27 McKinley, D.C., 16-16 McKinney. O.B.. 24-22 McKay. V., 25-5, 25-23 McLaughlin. W.A.. 54-13 McLean, A.M.. 25-22 McLeod, H.D. Jr., 25-23 McLeod, H.O., 54-13, 54-14 McLeod, H.O. Jr., 55-12 McMahon, J.J., 37-27, 38-9, 38-l I. 38-20 McMahon, W.F., 6-34. 6-72 McMenamin. M.A.. 25-18. 25-24 McNeal, R.P., 52-9, 52-30 McNeil, J.S., x, 46-14, 46-19, 46-43 to 46-45 McNellis, J.M., 24-19, 24-23 Meabon. H.P., 47-25 Mead. H.N., 7-17 Meads, R., 28-16 Mechem, O.E., 26-33 Mechtly. E.A., 58-8, 58-14 Meckei, L D., 36-10 Meenta, W.F.. 24-22 Megyesy, E.F., vi. 12-43 Mehta, B.R.. 25-28 Meijerink, J.A., 48-14, 48-20 Melcher, A.F., 26-3 Meldau. R.F., 46-45, 46-46, 48-6, 48- I8 Melnyk, J.D., 54-13 Melrose. J.C., 24-16, 44-51 Meltzer, B.D., 43-17, 45-15 Mennie. J.H., 25-22 Mennon. V.B., 19-34 Menten. P.D., 25-27 Menzie, D.E., 44-20, 4449 Merrill, L.S., 48-19 Maser, P.H., 34-55
Meww. E.S.. 26-24 Metcalfe. R.S.. 20-I. 23-9. 23-13. 45-10. 45. I4 Meter, D.M.. 47-4. 47-24 Meyers. D.C.. 16-16 Michaelis, A.M., 54-12 Mtchels, A., 25-21 Mid~Continent Dist. Study Commission, 24-22 Mid-Continent Oil and Gas Assn., 41-37 Mtkesha, F.J.. 16-16 Milburn, J.D.. 26-30. 26-31, 26-33 Miles, L.H.. 56-9 Miller, B., 25-27 Miller, B.D., 54-12. 54-14 Miller. C.C., 30-9. 30-12, 30.17, 35.15. 35-2 I Miller, F.G., 43-17 Miller. M.A., 28-12, 2X-16 Miller, M.G.. x. 39.19, 39.20, 39-23, 39-28 Miller. S.L., 25.25, 2527 Mtllican, M.L., 49-42 Millikan, C.V., 30-l. 30-16, 31-l Mills, F. van A.. 24-l. 24-22 Mime. J.H., 24-23 Milton, H.W. Jr., 47-25 Minear, J.W.. xii, 51.34. 51-51, 51-52 Minnich. B.H.. 25-22 Minor, H.E., 24-22 Minor, S.S., 54-12 Minssieux, L.. xi. 41-26 Mintz. F.. 41-37 Misk. A.. xii, 51-22, 51-51 Mitchell, R.W., 4451 Modine. A.D.. 48-20 Modular Production Equipment Inc., vii Mohanty. K.K.. 28-12. 28-15, 28-16. 47-25 Moilliet, J.L., 19-34 Molokowu, F.W., 36-10 Monroe, R.R., 22-22 Montadert. L., 36-10 Moody, L.F., ix, 34-38, 34-52. 34-55 Moore, C.H., 29-9 Moore, E.W., 54-14 Moore, G.T., 29-9 Moore, J.C.. 25-21 Moore, J.L., 45-l Moore, J.W., 25-27 Moore, T.V., 32-3, 32-16, 34-37 Moore, W.D., 38-20 Moorwood, R.A.S., 25-23 Moran, 1.. 49-41 Moranville, M.B., 48-18 Morel-Seytoux. H.J.. 4429, 44-51, 47-24 Moreland. E.E., 33-23 Morgan, C.O., 24-19. 24-23 Morgan. J.T.. 46-44 Morkill, D.B., 41-16, 41-19, 41-22, 41-37 Morris, C.F., xii, 51-51 Morris, F.C.. 26-33 Morris, J.K., 12-43 Morris. R.L., 49-42 Morrisey. N.S., 41-37 Morrison, J.B., 4451 Morrison. T.J., 25-21 Morse, R.A.. 43-17. 4429. 44-49, 45-13 Mortada, M., 38-1, 38-20, 44-25, 44-50 Mosburg, L.G. Jr., 57-12 Moscrip, R. III, 43-16 Moseley. N.F.. 4-10. 4-11 Moses, P.L., 39-l. 39-16, 39-28 Moshfeghian, M., 25-16, 25-18. 25-24 Moss. J.T., x, 4420. 44-50 4643, 46-44 Moughamian. J.M.. 48-6, 48-18 Mounce, W.D., 49-41, 51-50 Mower, L.N., 5-57 Mrosovsky, I.. 40-38. 48-17. 48-20
Muecke. T.W.. 54-14. 56-2. 56-9 Mueller, T.D.. 38-20. 43-17 Mulac. A.J.. 46-45 Miiller. G.. 51-51 Miiller. H.G.. 25-5. 25-23 Mullins. L.D., 37-27. 40-38 Mungan, N.. x, 44-51, 48-19. 54-12 Munjal. P.K., 25-22 Munn. M.J.. 24-1, 24-21 Murphy, G.B.. 21-20. 39-27 Murray, C.N.. 25-22 Murray, J.. 51-51. 55-10 Murzin. V.I.. 25-25 Muskat, M., 6-37, 6-39. 6-72, 28-2. 28-5. 28-15, 30-9. 30-I I. 30-16, 30-17. 32-4, 32-16. 34-3 I. 34-55. 37-7, 37.10. 37-13. 37-14. 37-19. 37-27. 39-19. 39.20, 39-27. 39-28, 40-9. 40.10. 40-18. 40-38, 43-17. 43-19, 44-13, 4414, 44.16, 44.17. 44-20. 44-21. 44-26. 44-29, 44-33, 44-49. 4450, 45.14, 45.15, 48.17, 48-18 Myhill, N.A., 46-9. 46-15. 46-43 Myung, J.I.. xii, 51-43, 51-51. 51-52 N Naar, J., 28-15 Nabor, G.W., 38-20. 44-25, 44-50 Nagata, I.. 25-5, 25-23 Naw, B.. 25-2 I. 25-22 Nario Chemical Co. CTS-V3. 19-34 Namiot. A.Y., 25-21. 25-26. 25-27 Nath. A.K.. 51-52 Nations, L.F., xii. 51-35, 51-51 Natl. Aeronautical and Space Admin, (NASA): NASA SP-7012. 58-8 Natl. Assn. of Corrosion Engmeers (NACE). 12-43, 19-34, NACE Std. MR-01-75, 3-36. 3-37. 3-40. 9-14 NACE Std. RP-01-75, I I-14 NACE Std. RP-03-72, I l-14 NACE Std. RP-05-75. I I-14. 19-34 NACE Std. TM-01-73, 44-51 NACE Std. TPC-5, 19-34 Natl. Bureau of Standards (See U.S. Natl. Bureau of Standards) Natl. Electrical Code (NEC), 3-34, 3-40, 10-26, 18-44, 1846, 18-52 Nat]. Electrical Manufacturers Assn. (NEMA). vi, IO-17 through 10-20, 10-24, 10-25, 10-27. IO-37 Natl. Fire Protection Assn. Bull. 496. 1846, 18-52 Natl. Oilwell. v Natl. Petroleum Council, 1S-52 Natl. Production Systems, 6-72 Natural Gas Assn. of America (NGAA). 39-12, 39-27 Natural Gas Supply Mens Assn. (NGSMA), vi Navone, R., 25-21 Neal, E.A., 55-12 Needham, R.B., 47-24 Negri, G.. 25-21 Neilsen, R.F., 35-l Neilson. I.D.R., 44-20, 44-50 Neinast, G.S.. 46-42 Nelson, C.C., 6-34, 6-72 Nelson, D.E.. 4451 Nelson. E.F.. 21-20. 39-27 Nelson, R.C.. 23-13. 47-20, 47-25. 47-26. 48-18 Nelson, T.W., 46-14, 46-19. 46-45 Nelson, W.L.. vii, 21-9, 21-20, 22-22 Nemeth, L.K., 39-13, 39-28 Neuman, C.H.. 46-9, 46-43
PETROLEUM
10
Neustadter, E.L., 19-34 Newburg, A.H., 16-16 Newendorp, P.D., 41-37 Newman, G.H.. 26-8, 26-33 Newman, S.A., 25-18, 25-24 New Mexico Oil Conservation Commission, 39-27 Nezdoiminoga, N.A., 25-22 Ng, H.J., 25-5, 25-9, 25-l I, 25-20, 25-23, 25-24, 25-28 Nghiem, LX., 48-18 Nichols, D.T., 21-20 Nichols, E.A., 31-7 Nicholson, R.W., 4451 Nicklin, D.J.. 34-39, 34-55 Niebrugge, T.W., 6-72 Nielsoi.-R.F., 25-26 Niemann, H., 25-25 Nierode. D.E.. 54-12. 54-14 Nikolaeb, N.A’., 12-4; Ninth Oil Recovery Conference, 39-28 Nisle, R.G., ix, 34-28, 34-55 Noad, D.F., 24-22 Noaker, L.J., 25-5, 25-23 Nobles, M.A., 4419, 4420, 44-34, 44-49 Nolan, T.J. III, 54-14 Nolen, J.S., 48-20 Nolte, K.G., 55-12 Nordgren, R.P., 55-12 Norman, L.R., 54-14 Northern, T.P., 16-16 Northrup. D.A., 55-l 1 Norton.‘A.E., 22-22 Nosov, E.F., 25-25 November, M.H., 13-59 Novotny, E.J., 5414 Nowak, T.J., 44-35, 44-51 Nur, A.M., 51-51 Nute, A.J., 45-15 Nutting, P.G., 26-3, 26-33, 44-40, 4451
0 O’Brien, L.J., 45-15 O’Brien, M.P., 6-36, 6-37, 6-72 O’Connor, J.J., 25-25 OCS Order No, 5, U.S. Dept. of the Interior, 3-34, 3-40 Odeh, AS., 28-15, 32-16. 33-23, 37-2, 37-3, 37-6, 37-7, 37-19, 37-27, 38-12, 38.20, 48-2, 48-18, 56-9 O’Dell, P.M., 48-18, 48-19 Offeringa, J., 45-14 Offshore Services and Technology, 12-43 Oglesby, K.D., 46-44 Oil and Gas I., vii, x, 16-16, 16-17, 19-34, 21-21, 40.38, 46-3, 46-43 to 46-45 Oilfield Publications Ltd., viii Oilwell Div. of U.S. Steel Corp., v Oilwell Research, 26-6 Olds, R.H., 21-10, 21-11, 21-20, 23-13, 25-2, 25-l I, 25-20 Oleinikova, A.L., 25-25 Oliver, D.W., 50-38 Oliver, F.L.. 29-l Oliver, L.R., x, 39-20. 39-21, 39-28 O’Meara, D.J. Jr., 28-7, 28-12, 28-15 Omnes, G., 51-52 O’Neil, R.K., 7-17 Organick, E.I., 21-10, 21-11, 21-13, 21-15, 21-16, 21-20, 39-4, 39-27 Orkiszewski, J., 7-12, 7-17, 34-37 to 3440, 34-55 Orr, F.M. Jr., 23.l,23-13,45-14,48-9,48-19 Osborn, F.E. III, 54-12 Osif, T.L.. 24-13, 24-23 Osoba, IS., 28-15 Ostroff, A.G., 24-22, 4451
O’Sullivan, T.D., 25-21 Otis Engineering Corp., v Otsuka, E.. 25-24 Otto. F.D.. 25-23. 25-28 Ovchinnikov, A.A.. 12-43 Overbeek, J.Th.G., x, 47-25 Overton, H.L., 49-42 Owen, J.D., 26-33 Owen, L.B., 55-l 1 Owen, W.W., 28-11, 28-15 Owens, W.W., 45-13, 47-20, 47-26
P Paasch, R.D., 41-37 Pabley, A.S., 54-14 Pacific Energy Assn., 13-59 Packard, H.C., 16-16 Padmanabhan. L., 48-19 Paillet, F., 51.13, 51-51 Paine, P., 41-37 Palmer, F.S., 45-15 Palmer, I.D.. 55-12 Palmour. H.H., 6-72 Pankov, A.G., 25-25 Panteleev, V.G., ix, 28-15 Panvelker, S.B., 40-38, 47-24 Paragon Engineering Services Inc., vii Paratella, A.A., 25-22 Pardue, G.H., 51-52 Parent, C.F., 44-51 Parker, P.D.M., 25-22 Parks. A.S., 12-43 Parks, T.W., xii, 51-51 Parmley, J.L., 55-12 Parrish, D.R., 46-40, 46-43, 46-44 Parrish, W.R., 25-2,25-5.25-S, 25.20,25-27 Parsons, R.L., 39-28, 40-18, 40-19, 40-38, 44-7 to 449, 4426, 4429, 44-30, 44-32, 4449, 45-14. 45-15 Parsons, R. W. ) 46-44 Pasternack, E.S., 51-52 Pate], C., 45-15 Patnode, H.W.. 49-41 Patterson, D.R., 16-1, 16-16 Patton, C.C., 24-22, 445 1 Patton, E.C. Jr., 39-28, 43-9, 43-17, 43-19 Patton, J.T., 47-8, 47-25, 48-19 Patton, L.D., v, 4-1, 4-11 Paul, G.W., 47-25, 47-26 Pauley, P.O., 54-12 Paulsell. B.L., 44-20, 44-50 Pavlova, S.P., 25-26 Pavnter. D.D.. 36-10 Paiton, E.. 29-9 Peaceman, D.W., 4451, 45-14, 48-16 to 48-20 Pearson, A.J., 52-1, 53-l Peerless Manufacturing Co., vi, 12-43 Peery, J.H., 48-18 Peni, D.Y., ix, 20-7, 20-8, 20-18, 23-13, 25-8, 25-16, 25-17, 25-23, 39-28, 48-18 Penick, D.P., 12-43 Pennbaker, P.E.. 53-26 Penny, G.S., 55-12 Perkins, T.K., 44-49, 45-14, 4643 Perkins, T.K. Jr., x, 55-2. 55-10 Perry, C.W.. 25-25, 46-45 Perry Equipment Co., vi1 Perry, J.H., 20-18, 22-22 Perry. R.H., vii, 25-15 Pet. Engr., 16-16 Pet. Equipment. 16-16 Peters, B.A., 1243 Peterson, A.V., 39-16, 39-28 Peterson, M.E.. 46-44 Peterson, R.A., 51-52 Peterson, R.E., 25-22
ENGINEERING
HANDBOOK
Peterson. R.L., 45-15 Petrie, H., 6-l. 6-34. 6-72 Petrie, T.A., 41-37 Petroleum de Venezuela S.A.. 27-9 Petroleum Publishing Co.. 18-52 Petrov, A.N., 19-34, 25-25 Petrunia, J.P., 25-28 Peveraro, R., 53-26 Pickett, G.R., 51-50 Pierce, H.R., 30-8, 30-16 Pierre, M.L., 54-12 Pierson, N.O., 54-14 Pierson, R.G., 48-18, 48-19 Pinson. J., 4450 Piper, A.M., 24-19, 24-23 Pirie, G., 50-38 Piros, J.J.. 16-16 Pirson, S.J., ix, 29-9, 39-28, 40-17. 40-38. 43-16, 43-17, 4449, 4942 Pittman, D., 51-52 Pittman, G.M., 46-44 Pittman, R.W., 34-55 Pitzer, K.S., 20-13, 24-15, 24-23, 25-24 Plasek, R.E., xi, 50-38 Platt, C.R., 37-27 Platteeuw, J.C., 25-2, 25-5, 25-6. 25-10, 25-20, 25-23 Plenty Metro1 Ltd., vi, 12-43 Plisga, G.J., 30-1, 31-l Plummer, F.B., 24-22 Poettmann, F.H.. ix, x, 25-25, 34-1, 34-4, 34-9, 34-28, 34-37, 34-46, 34-55. 34-56, 39-28, 46-13, 46-14. 46-16. 46-37. 46-44, 46-45 Polglase, M.F., 25-21 Pollak, A., 12-43 Pollard, P., 54-14 Pollard, T.A., 39-l. 40-38, 58-2 Pollitzer, F., 25-22 Pollock, C.B., 46-44, 55-10 Pontious, S.B., 45-15 Pontius, P.E., l-71 Pope, G.A., xi, 23-13, 47-5. 47-24 to 47-26, 48- 18 Pope, S.H., 16-16 Porta-Test Systems Ltd., vi. 12-43 Postgate, J.R., 24-22 Poston, S.W., 36-1, 36-10, 46-37, 46-45 Pottier, J.. 45-15 Poupon, A., 49-4 1 Powers, W.J., 7-l Pozzi, A.L., 45-14 Prats, M., 37-20 to 37-22, 44-20, 44-25, 44-28 to 44-32, 44-34, 4449, 4450, 46-43, 46-45, 46-46 Prausnitz, J.M., 20-18, 23-13, 25-2, 25-5, 25-8. 25.14, 25-20, 25-21 Pray. H.A., 25-22 Prehn, W.L. Jr., 26-33 Prentice-Hall Inc., 57-12 Press, F., 51-50 Price, H.S., 43-17, 45-14, 48-16, 48-20 Price, P., 24-22 Prince, L.C., 24-23 Prokop, C.L., 49-42 Province of Manitoba, 24-22 Province of Saskatchewan, 24-22 Pruess, K., 48-l 1, 48-20 Pryor, J.A., 4645 Pryor, W.A., 36-10, 46-42 Puerto, M.C., 47-25 Pujol, L., 46-13, 46-43 Pursley, S.A., 46-43 Purvis. S.B.. 54-12 Pusch, W.H., 46-45 Pushkar, P., 24-22 Pye, D.S., 56-9 Pyndus, G.T., 45-14
AUTHOR
11
INDEX
Q Quadir, J.A., 55-l I Quirein. J.A., SO-38 Quisenberry. J.L., 54-12
R Rachford, H.H. Jr., 38.20, 4451, 45-14, 48-16, 48-18, 48-20 Rachinskii, MA, 25-21 Radar, D., 51-51, 53-26 Radke, C.J., 47-21, 47-26 Raghavan, R., 34-9, 34-55, 55-11 Rahme, H.D., 44-29, 4450 Railroad Commission of Texas, ix, 34-55 Raimondi, P., 47-26 Rambow. H.. 4451 Rail. C., 24-22 Ramagost, B.P., 35-13, 35-21, 40-38 Ramakrishnan, T.S., 47.26 Ramesh, A.B., 48-19 Ramey, H.J. Jr.. 4-11, 28-12, 28-16, 30-17. 33-23, 34-9, 34-55, 35-10, 35-21, 36-8, 36-10. 43-16, 4420. 44-29, 44-34, 4450, 46-S, 46-6. 46-8, 46-15 to 46-17, 46-19, 46-43 to 46-45, 55-I I Ransom, R.C., xii, 51-51 Rapoport, L.A., 44-29, 4450, 4452 Rathbone, M.J., 54-13 Rathmell, J.J., 44-49 Rau. R., xi Rawlins. EL., ix, 30-8, 30-16, 33-3, 33-5. 33-13, 33-23, 34-45, 34-55 Raymer. L.L.. xi, xii, 49-42, 50-38, 51-33, 51-34, 51-52 Raynal, J.C., 53-26 Rayne, J.R., 45-14 Reader, P.J., 43-17 Reading, H.G., 36-10 Reamer, H.H., viii, 23-13, 25-24, 25-26, 25.27, 25-28 Records, J.R., 25-10, 25-12, 25-23 Redlich, O., 20-7, 20-8, 20-18, 23-12, 23-13. 39-28 Reed, C.D.. 25-26 Reed, G.A., 16-16 Reed. R.L., xi. 47-13, 47-25 Reeds, C.B., 18-I Reese, C.P., 16-16 Regier, 8. 39-28 Reheis, G.M., 43-17 Rehkopf. B.L., 46-44 Rehm, B.. 52-24, 52-31 Reid, L.S., 25-21, 25-27 Reid, R.C., 20-18, 23-13 Reid, T.B., 47-24 Reid. W., 33-1, 33-23 Reineck, H.E., 36-10 Reistle, C.E., 24-19, 24-23 Renon, H., 25-18, 25-24 Republic Bank of Dallas, x Resen. L., 16-17 Reudelhuber, F.O., 37-23, 37-27, 40-38 Reuss, A.. 51-51 Reynolds, A.C.. 55-l 1 Reynolds, F.S., 41-7, 41-37 Reznik, A.A., 40-19, 40-38, 47-24 Rhodes, A.E., 3-40 Rice. J.D.. 38-20 Rice. P.A.. 25-26 Rich, J.L.. 24-2. 24-22 Richards, L.A., 28-2, 28-6. 28-15 Richards. W.L., 25-27 Richardson, E.A., 54-13 Ridings, R.L., 37-13, 37-21. 37-27, 48-20 Rigby, M., 25-14, 25-21 Riley, J.P., 25-22
Rintoul, B., 18-52 Ripmeester, J.A., 25-27 Ritchie, P.D., 25-22 Ritterbusch, W.H. Jr., 9-l Rittenhouse, G., 24-22 Roberts, G.I., 54-14 Roberts, G. W., 46-45 Roberts, L.D., 54-13, 54-14 Roberts, 0.L. 25-23 Roberts, S.J., 48-20 Roberts, T.G., 37-14, 37-15, 37-27, 40-38, 44-29. 44-50 Robinson, D.B., viii, 20-7, 20-8, 20-18, 23-13. 25-5, 25-8, 25-9, 25-11, 25-16, 25-17, 25-20, 25-23, 25-24, 25-28, 39-28, 40-38, 48-17 Robinson, F.M., 51-51 Robinson, G.E., 48-19 Robinson, J.. 12-43 Robinson, J.D., 51-47, 51-52 Robinson, J.R., 22-15, 22-16, 22-22, 46-31, 46-45 Robinson, R.L. Jr., 20-8, 20-18 Roddy, J.W., 25-26 Rodgers, J.K., 39-15, 39-28 Roe, R.P., 23-13, 39-13, 39-15, 39-28 Roebuck, IF. Jr., 43-l Roger, P.S.Z., 24-15, 24-23 Rogers, G.S., 24-22 Rogers, H.D., 24-21 Rogers, J.H., 47-24 Rogers, R.E., SS- 12 Rogers, W.B., 24-21 Roland, C.H.. vii, 20-18 Rollins, J.T., 55-10 Rolshausen, F.W., 24-22 Romero-Juarez, A., 3 l-7 Romocki, J.M.E., 54-14 Ronk Electrical Industries Inc., vi Roof, W.E., II-1 Ros, N.C.J., 34-36, 34-37, 34-40, 34-46, 34-55, 34-56 Rosbaco, J.A.. 37-21, 37-27 Rose, SC., 52-31 Rose, W., ix, 28-1, 28-3, 28-5, 28-15 Rosenbaum, J.H., 51-47, 51-51 Rosenbaum, M.J.F., 4451 Rosenberg, R.J., 55-12 Rosene, R.B., 54-13, 55-12 Rosepiler, M.H., 55-12 Rosman, A., 45-14, 48-19 Ross, J S., 24-22 Ross, W.M., 54-14 Roszelle, W.O., 28-15 Rouher, 0.8, 25-27 Rowan, G.. 54-14 Rowe, A.M. Jr., 24-13, 24-14, 24-23 Royle, R.A., 54-14 Rubin, L.C., 20-7, 20-18 Ruble, D.B.. 44-36, 44-51 Rushing, M.D., 45-14 Russel, W.L., 29-9 Russell, D.G., 35-21 Russell, G.B.. 25-21 Russell, G.F., 25-27 Russell, J.T., 25-28 Russell, T.F., 48-19 Russell, W.L., 26-3, 26-4, 26-33 Rust, C.F., 26-33 Rust, W.M. Jr., 49-41 Ryabtsev, N.1.1 25.25. 25-26 Ryan, J.C., 54-12 Rzasa, M.J.. 22-22, 34-55, 39-1, 39-27, 45-14 S
Sackash, M.L., 7-17 Saddington, A.W., 25-22
Sage. B.H.. viii. x, 21-10, 21-11. 21-20. -23-13, 25-20, 25-27, 45-14 Sage, W.H., 22-22, 39-2. 39-27 Sagramora, G., 25-22 Sahuquet, B.C., 46-43, 46-45 Saito,.S., viii, 25-2, 25-5, 25-20, 25-23, 25-24 Salter, S.J., 28-12, 28-15. 28-16, 47-25 Salthiel, W.M., 54-14 Samaniego-V., F., 55-11 Sams, H., ix, 29-9 Sanchez, M., 25-24, 25-25 Sandberg, C.R., 40-38 Sander. W.. 25-22 Sandiford, B.B., 44-39, 44-51 Sandier, 8, 25-18. 25-24 Sandmeyer. D.J., 4-I 1 Sanyal, SK., 51-52 Saref, D.N.. 28-10, 2X-15 Sarem, A.M., 28-10, 28-15 Sargent, E.C., 24-22 Sargent Oil Well Equipment Co., vi Sarmiento, R., 51-50 Sass, L.C., 24-22 Satman, A., 46-14, 46-45 Satter, A., 46-6, 46-43 Sattler, A.R., 55-l 1 Saucier, R.J.. 56-6, 56-9 Saunders, C.D., 55-12 Sauve, E.R., 18-l Savel’eva, NJ., 25-22 Savins, J.G., 47-24 Sawabini, C.T., 46-37, 46-45 Saye, H.A., 16-17 Scala, C., 49-41 Scarborough, R.M., 4645 Scauzillo, F.R., viii, 12-44, 25-24 Schaaf, D., 24-22 Schatz, J., 55-10 Schauer, P.E., 44-29, 44-51 Schechter, R.S., 47-24, 47-25, 54-12, 54-14 Scheffer, F.E.C., 25-24, 25-27 Scheidegger, 28-5, 28-7, 28-15 Schellhardt, M.A., ix, 33-23 Schenk, L., 46-45 Scheraga, H.A., 25-25 Scherubel, G.A., 544, 54-12 Scheuerman, R.F., 56-9 Schilling, J.R., I243 Schilthuis, R-1.. 22-22, 24-2. 24-22, 34-37, 37-S, 37-27, 38-8, 38-20, 40-37 Schlumberger, xii, xiii, 50-38, 51-51. 51-52 Schlumberger Ltd., 53-26 Schlumberger Offshore Services, xiii Schlumberger Well Services, xi, 49-4 I, 49-42, 53-26 Schlumberger Well Surveying Corp., 49-41 Schmalz. J.P., 44-29, 44-50 Schneider, F.N., 28-11, 28-15 Schneider, H.. 25-25 Schneider, R.D., 44-51 Schnitz. L.B., 43-16 Schoewe, W.H., 24-22 Scholander, P. F.. 25-2 1 Scholle, P.A., 29-9. 36-10 Schoonovers. L.G.. 53-26 Schrider, L.A., 44-29, 44-50 Schrteter, F.E., 54-12 Schroeder, W., 25-2 1 Schroeter, J.P., 25-28 Schueler, S.. 33-23 Schuetze. H., 25-24 Schultz, H.E., 7-17 Schultz. W.P., 42-l. 45-14 Schulze, R.P., xi. 49-41 Schweickent. C.E.. 25-22 Sclocchi. G.. 34-55 Scott, A.C., 53-26
12
Scott, J.O., 16-17 Scott, V.B.. 16-17 Scovill, W.E., 16-16 Striven. L.E. 47-25 Sears. F.W., xi, 51-50 Seelv. D.H. Jr., 25-10. 25-12, 25-22. 25-23 Se&an, B.. 51-51, 51-52 Seaesman, F., 49-l. 49-41, 50-15. 50-38 Sejnfeld, J.H., 48-19 Selleck, F.T., 25-27 Selley, R.C., 36-10 Sells, R.L., 50-38 Selly, R.C.. 36-10 Seright, R.S., 47-24 Serra. 0.. 50-38 Sessions, R.E., 45-15 Settari. A., 45-14, 48-16, 48-17, 48-20. 55-12 Shah. P.C., 48-19 Shane. L.E., xii, 51-50 Shank, G.D., 48-18 Shari@, A., 25-16, 25-24 Shatto. H.L., 16-17 Shaughnessy, C.M., 54-13, 54-14 Shaw, J.K., 44-51 Shaw, M.S., 54-12 Shaw, S.F.. 34-55 Shearin. H.M., 42-1, 45-14 Sheffield, M., 48-18 Sheffield, R., IS-52 Shehabi, J.A.N., 43-17 Sheil. A.G.. 6-72 Sheldon, J.W., 4814, 48-18 Sheldon, W.C., 39-28, 45-15 Shell Development Co.. vii Shell Oil Co., 36-10 Shelton, J.L., 45-14, 45-15, 48-19 Shen, J., 44-51 Sherwood, T.K., 20-18, 23-13 Shiba, F.F., 45-10 Shipley, R.G.. 46-45, 48-18 Shirer. J.A., 4451 Shirley, H.T.. 39-28 Shirley, O.J., 52-24, 52-3 1 Shut. K.S.. 5-57 Shoor. SK., 25-21 Shore, R.A., 46-44, 46-45 Showalter, E., IO-14 Showalter, W.E., 46-13, 46-16, 46-17, 4643, 46-44 Shreir, L.L.. 19-34 Shreve. D.R.. 43-4, 43-16, 43-19 Shtof. 1.K.. 19-34 Shumaker. E.G., 55-12 Shupe, R.D.. 47-24 Shutler. N.D.. 48-18 Sibbit, A.. 49-42 Sibbitt. W.L., 25-22 Srfferman. T.R.. 52-30, 55-12. 6-72 Sigmund. P.M.. 28-11. 28-15 Sikora. V.J., 38-l. 38-20 Stkora. V.J., 37-l. 37-14, 37-23, 37-27, 54-9. 54-10 Silberberg. I.H., 44-50. 46-45, 54-12 Silcox. W.H.. 18-1, 18-52 Silva. M.K.. 45-14, 48-19 Simandoux. P.. 48-19 Simard, G.L.. 49-41 Simmons. G., 51-30, 51-43, 51-51. 51-52 Simmons, J., 44-50 Simon. R.. 45-14. 48-19 Simpson. L.B.. 25-25 Sims. W.P.. 40-38 Simulation Sciences Inc.. vi, 12-33. 12-43 Sinaiskii. E.G.. 12-44 Sinanoglu, 0.. 25-5, 25-23 Sinclair. A.R.. 55-12 Singh. D.. x. 37-15. 37-27
PETROLEUM
Singh. I B., 36-10 Singhai, A.K., 46-43 Skelton. N., 54-13 Skiba. F.F., 45-14 Skinner, W. Jr., 25-12, 25-23 Skirvin, R.T., 29-l Sklar, I.. 46-44 Skripka, V.G., 25-21, 25-26 Slattery. J.C., ix. 28-12. 28-15 Sleinikova, A.L., 25-25 Slider, H.C.. 4430, 44-32, 44-50 Sloan, E.D., viii. 25-l. 25-2, 25-4, 25-9, 25-10, 25-20, 25-23, 25-27 Sloan, J.P., 39-1, 39-27 Sloat, B., 44-51, 47-26 Slobod, R.L., x, 26-25, 26-33, 43-19, 44-17, 44-19. 44-20. 44-49. 45-13. 45-14 Slonneger, J.C., 10.18, IO-37 Sloss. L.L., viii, 26-7. 26-33 Smart, E.E.. 6-72 Smart, G.T., 48-19 Smeaton, R.W., vi Smith, A.E.. 30-9. 30-16 Smith, C.F.. 5414 Smith, F.W., 46-43 Smith, G.L., 40-l Smith, H.D. Jr., xi, 50-38 Smith, H.V., 12-1, 19-I Smith, M.B., 55-12 Smith, N.A.. 25-21 Smith, N.O., 25-21, 25-22 Smith, O.E.. 48-19 Smith, R.C.. 31-7 Smith, R.H.. 40-15. 40-38 Smith, R.L., 21-11. 21-20 Smith, R.S., 12-43 Smith, R.V., 5-37, 5-38, 5-57, 33-l. 33.15, 33-18, 33-23, 34-24 to 34-27. 34-29, 34-46. 34-55, 34-56. 46-44 Smith, R.W., x Smith, S.S., Y, 5-57, 25-27 Smits, L.J.M., 49-41 Sneider, R.M., 36-6, 36-10 Snell, L.E., 25-23 Snyder, L.J.. 48-18 Snyder, R.W.. 43-16, 44-29, 44-50 Soave, G., 20-7, 20-8. 20-18, 23-13, 48-18 Sot. of Automotive Engineers Inc., IO-12 Sot. of Petroleum Engineers (SPE), 12-42. 23-13, 35-21, 39-27, 40-2. 40-37, 41-37. 45-14. 46-44. 46-45 Board of Directors, 58-l Metrication Subcommittee, 58-22 Metric Standard, 17-7 Symbols Committee, 59. I Sot. of Professional Well Logging Analysts (SPWLA), 52-3 Soldate, A.M., 25-25 Sollami. B.J., 25-21 Somasundaran. M.C., 47-26 Somerton. W.H., 46-37. 46-45, 47-26 Song, K.Y.. viii, 25-l. 25-10, 25-15. 25-23 Spalding, J.S.. 51-51 Spangler. M.B.. 26-33 Sparlin, D.D., 56-9 Spearing, D., 36-10 Spence. K., 48-19 Spencer, C.F., viii. 25-23 Spencer. G.B.. 37-27. 39-28. 40-38 Spillette, A.G.. 48-14, 48-20 Spisak. C.D., 6.34. 6-72 Spivak. A.. 43-17 Squire, K.A , 54-13 Squires. F., 44-40. 44-5 1 Squires, L., 22-22 Staadt, H.E.. 54-l Staal, J.J., 51.47. 51-52 Staggs. H.M., 48-18
ENGINEERING
HANDBOOK
Stahl, C.D.. 4417. 44-49 Stahl. R.F., 40-38 Stalkup, F.I. Jr., 23.13, 45-14 Stamm, H.E. III, 43-16 Standing, M.B., vii, viii, 6-21, 6-38, 6-39, 6-72, 7-9. 7-12, 7-17. 20-5, 20-9, 20-18, 21-9, 21-16, 21-18 to 21.20, 22-l. 22-5, 22-6, 22-8 to 22-l 1, 22-13, 22-14, 22-21, 22-22, 23-13, 24-13, 24-23, 25-17, 25-21, 34-34, 34-35, 34-55, 37-19 to 37-21. 37-27, 39-2. 39-11 to 39-13, 39-15, 39-19, 39-27, 39-28, 40-38, 45-15 Starling, K.E.. 20-7, 20-18 Staron. Ph., xii, 51-51 State of Kansas, 33-13. 33-23 Steanson, R.E., 55-l Steel, G., 36-10 Steffensen, R.J., 31-7, 37-1, 45-15 Stegemeier, G. L., 46-9, 46-13, 46-15, 46-43, 47-25 Stein, N.. 51-52, 56-9 Steinle, P., 40-16, 40-38 Stelzer, R.B., x, 39-20 to 39-22, 39-28 Stenmark, D.G., 47-25 Stephenson, E.A., 41-37 Stephenson, R.E., 48-18 Stevens, A.B.. viii, 26-4 to 26-6 Stewart, C.H. Jr., 48-14, 48-18 Stewart, F.M., 38-20. 43-16 Stewart, M., 19-33 Stewart, P.B.. 25-22 Stiefel, E., 48-20 Stiel, L.I., vii, 20-18 Stiff, H.A. Jr., 24-19, 24-23 Stiles, L.H., 36-7, 36-10 Stiles, W.E., 36-6, 36-10, 40-18. 40-19, 40-20, 40-38, 43-7, 43.19, 44-7 to 44-9, 44-26, 4428 to 44-32, 44-39. 44-49, 44.51, 45-14 Stock, L.G., 47-26 Stockwell, A , 19-34 Stokes, D.D., 46-43. 46-44 Stall, R.D., 25.18, 25-24 Stone, H.L.. ix, 28-8. 28-15, 37-21. 37-27. 45-13. 48-14, 48-16, 48-18, 48-20 Stormont, D.H., 16-17 Stosur, J.J., 46-45 Stout, W., 24-22 Stovall, S.L., 46-43 Strange, L.K., 46-20. 46-45 Strawn, J., 55-10 Strebel. E., 25-22 Strickland, R.F., 43-17 Strickler, W.R., 44-50 Stright, D.H. Jr., 48-18 Strong, E.R. Jr., 25-27 Stubbs, B.A., 54-12 Stutz, R.M., 16-16 Stutzman, L.F., 25-21, 43-16 Suau. J., 51-45, 51-52 Suciu. S.N., 25-22 Suder, F.E., 44-29, 44-50, 45-14 Suti, A.H., 28-12, 28-15 Sukkar, Y.K.. 34-9, 34-10 to 34-22. 34-24, 34-55 Sultanov, R.G., 25-21. 25-26 Suman, G.O. Jr., 56-9 Summers, G.C., 51-50 Sunwall, M.T., 24-22 Surface, R.A., 46-44 Sustek, A.J., 46-44 Suter, H.H.. 24-22 Swan Wooster Engineering Ltd., vii Swanson, B L.. 54-14 Swearingen. J.W.. 44-17. 44-49 Swendenborg. E.A., 24-22 Swerdloff, W., viii. 22-17, 22-22
AUTHOR INDEX
Swetnam. J.C.. 7-17 Sydansk. R.D.. 47-26 Symbols Committee of SPE. 59-l Szasz, S.E., 46-43
Taber. J.J.. 23-1, 44-5 I, 47-22, 47-26 Taggart, MS. Jr., 24-22 Takahashi. S., 25-23 Takenouchl. S., 25-22 Tan, T.B.S., 48-20 Tanguy, D.R., 49-41 Tannahill. C.A.. IX-52 Tamer. J.. x. 37-7. 37.10. 37.27, 40.9, 40-10. 40-38 Taylor. D.M., 16-17 Taylor, H.S.. 25-25 Taylor, M.O.. 37-10, 37-13, 37-14, 37.27, 40-38 Taylor, T.J.. xi), 51-52 Tek. M.R.. 34-50, 34-55, 34-56 Templeton. C.C., 54-4, 54-12 Terry, L.F., 41-37 Terry. W.M.. 45-14 Terwilliger. P.L.. 40-38. 46-45 Teubner. W.G., 45-15 Teufel. L.W.. 55-12 Texas Railroad Commission. 36-10. 39-27 Thakur, G.C.. 48-6. 48-18 Tham. M.J., 45-15 Thiercelin. M.. 55-12 Thqssen. H.A.C.. 22-22 Thodos. G., vii, 20-9, 20-10, 20-15. 20-16, 20-18. 43-16 Thomas, C.P.. 48.18 Thomas. D.H., xii. 51-17, 51-51 Thomas, E.C.. 49-41 Thomas. C.B., 30-10, 30-17 Thomas. G.R.. 24-22 Thomas. G.W., 48-14. 48-17, 48-20 Thomas. J.E., 48-6. 4X-18 Thomas, L.K.. 34.1,43-17.48.5.48-18.48-19 Thornab. R., 34-55 Thomas. R.D., 47-26 Thomas, R.L., 54-4, 54-12, 54-13, 55.12 Thompson, D.D.. xi. 51-50 Thmmon. E.S.. 25-25 Thomson, I.. 6-72 Thornhill-Craver. 5-8 Thrash, J.C., 45-15 Thrasher. W-B.. 12-43 Threikeld. C.B.. 47-24 Throop. W H., xi. 49-41 Thurnau. D.H.. 48.14, 48.18, 48-20 Thury. G., 25-21 Tickell, F.G.. 24-19. 24-23. 26-2, 26.33 Tldman. J.. xi Tiffin. D.L.. 45-14 Till. M.V.. 54-13 T~mmerman. E.H., 37-27. 38-9. 38-l I. 3X-20, 40-37, 44-28. 445 I Timur. A.. xi. xii. 51-l. 51-4. 51-50, 51-51 Tinker. C.N., 36-10 Tinker. GE.. 47-24 Tinnemcyer. A.C., 54-13 Tinhley, J.M.. 55-12 Tittle. R.M., 45-15 Tixler. M.P.. 26-29, 26-33, 49-l. 49-41. 49-42. 51-50 to 51-52 Todd, M.. 16-17 Todd. M.R.. 48-11. 48-18. 48-19 Todheide. K.. 25.21. 25-22. 25-24 Tokstiz. M.N.. xi. xii. 51-35. 51-50 to 5 I-52 Torcaao. M.A.. 40-38 Tarp. S.B.. 4X-IY Torrey, P. D., 24-I. 24-3 I. 24-22, 4439.4452
13
Tosch. W.D.. 45-13 Towler, B.F., 4X-20 Tracy. G.W.. 30-17. 37-7 to 37-10, 37-21. 37-27. 38-2. 38-3, 38-20, 43-17 Tramer. R.R.. 22-22 Trantham, J.C., 46-43 Traverse, E.F., 46-44 Travis, R.H., 16-17 Trebin. F.A.. 25-23 Tretolite Div.-Petrolite Corp., 19-34 Trico Industries, v Trimble. A.E., 46-18, 46-45 Trimble. R.H., 48-20 Tripp. H.A.. 9-14 Trofimuk, A.A., 25-18, 25-24 Troatel, E.G., 46-35 Trube, A.S. 20-11. 20-16, 20.18, 22.11, 22-12. 22-22 Trushenskl. S.P.. 47-25 TRW Energy Product Group, Reba Pump Div., v Tsang, L.. 51-51 Tsarev. V.P., 25-24 Tsaturyanta. A.B.. 25-21 Taaur. K.. 47-24 Tsiklis. D.S., 25-22, 25-23, 25-26 Turner, J.. 54-13 Turner. R.G., 34-46. 34-55 Tyler. J.C.. 48-18 U Udell, K.S.. 46-45 Underwood, P.J., 54-13 Underwr&cra’ LaboratorIes Inc., IO-27 University of Texas, I l-14, 12-43, 19-34 University ot Tulsa, 24-22 Unruh, C.H., 25-5, 25-23 U.S. Bureau of Mines IUSBM). l-80. 13-45, 19.34. 24.21, 24-23, 30-8, 30-16 U.S. Bureau of Standards, 14-9 USCG Regulation 30CFR, 18.52 USCG Regulation 33CFR. IS-52 USCG Regulation 46CFR, 18.44. 18.52 U.S. Dept. of Commerce. 25-15 U.S. Dept. of Energy (DOE). x, 40.38. 46-21, 46-45. 48-18 U.S. Dept. of Interior. 12-43, 18-52, 57.11, 57-12 U.S. Fdter, Fluid System Corp., vii U.S. GeologIcal Survey (USGS), 3-39 U.S. Natl. Bureau of Standards (NBS), I-68, l-69, I-71. I-80, 58-9 NBS LC 1071, 58-8 NBS Special Pub. 330. 58-8 U.S. Securities and Exchange Comm., 40-38 U.S. Steel Corp., Bull USS, v U.S. Weather Bureau, IX V Valleroy. V.V., 46-44 van Cleeff. A., 25-23. 25-24. 25-27 Van der Knapp. W.. 26-8. 26-33.51-50.51-51 van der Poel. C.. 44-25. 44-50. 45-19 van der Waala. J D.. 20-17. 20-18. 23-12, 25-2, 25-5. 25-6. 25-10, 25-20. 25-23 Van Der Worst. H.A.. 48-20 Vanderzee, C.E.. 25-22 VanDljlk. W.J.D.. 32-13 van Dijk, C.. 46-44 van Domaelaar, H.R.. 47-25 van Everdmgen. A.F., 30.14, 30.15. 32-5. 32-16, 3.5-l. 35-21, 37-5. 37-27. 38-1, 38-9. 3X- 1I. 38-20. 39-28, 40.37, 40-38 Van-Guy, N , 48-19 VanMeter. O.E.. viii. 26-33 Van Oratranil, C.E.. 31-7
Vanpce. M.. 25-23 Van Poollen. H.K.. 48-18. 48-20. 51-45. 51-52. 55-12 van Wineen. N.. 43-16 van Wjik: W.R., 22-22 Varga. R.S.. 48-16. 48-20 Var;,en. J.P.. 36-6, 36-10 Vasquez, M.. 7-9, 7-17. 22-7 to 22.12. 22-16, 22-22 Vatalaro, F.J., 7-17 Vdovina, N.A., 25-22 Veatch. R.W., 55-12 Verbeek, C.M.J., 55.12 Verma, V.K., 25-18, 25-24. 25-28 Vernado, S.G., 53-26 Verrien, J.P., 36-6, 36-10 Vestal, C.R.. 48-18 Vetter, O.J., 44-5 1 Vilcu, R., 25-22 Villard. P., 25-2, 25-20 Villarreal. J.F., 25-26 Vine, J.D., 24-23 Vink, D.J., 21-16, 21.20. 22-22 Vinsome, P.K.W.. 48-19, 48-20 Vispatch. 19-34 Vivian, T.A., 54-14 Vizilog Inc., xiii Vogel, C.B., 51-50 Vogel, J.V., 7-9, 7-17, 34-3 I. 34-32. 34-34, 34-35, 34-55. 37-19. 37-21, 37-27, 46-9. 46-43 Voigt, W., 51-51 Volek. C.W.. 46.8.46.9,46-15.46-43. 46-45 Vondy. D.. 12-31, 12-43 van Rosenberg, D.V.. 45-14 van Stackelbcrg. M.. viii, 25.5. 25.23 Vortec Inc., 12-43 W Wachter, A., 25-27 Wade, R.P.. 54-14 Wade, W.H., 47-25 Wagner, O.R., 44-40, 44-5 1. 46-2 I, 46-45, 47-26 Wagner, R.J., 44-29. 44-50 Wahl, H.A., 55-12 Wahl, J.S.. xi. 50-38 Wahl, W.L., 37-27, 40-38 Walker, C.J.. 39-28 Walker, R.D. 25-21 Walker, T., xii, 51-44. 51-52 Walkley, J.. 25-27 Wallace, W.E.. 24.22 Wallis, G.B.. vii, 34-37 to 34-39. 34-55 Wallis. J.R., 48-20 Walsh, J.B.. 51-43. 51-52 Walsh, M.P.. 54-14 Walstrom. J.E.. 53-26 Walters, I.D., 44-51 Walton. D.L.. 38-l Wang, H.. 5 l-30, 5 I-52 Ward, D., IO-37 Warembourg. P.A., 54.12. 54.14 Warner. B.J.. 12-44 Warner, H.R. Jr.. 45-15 Warpinski, N.R., 55-12 Warren. F.H., 16-17 Warren. J .E.. 44-29. 44-5 I, 45. II. 49-4 1 Washburn. E.W., 26-J to 26-6. 26-33 Wasicek. J.J.. 16-17 Wason, C.B.. 36-10 Wassan, D.T , 19-34. 47-26 Wasserman. M.L.. 4X-19 Wasson. J.A., 44-29. 44-50 Waters, A.B.. 55-12 Watkins. D.R.. 54-14 Watkins. J.W.. 24-l. 24-22
14
Weaver. E.G., 16-17 Weaver, R.H., 56-9 Webb, G.B., 20-7, 20-18 Weber, A.G., 38-20 Weber, K.J., 36-6, 36-7, 36-10 Webster’s New International Dictionary, 58-20 Weeks, L.G., 29-9 Wegner, R.E., 44-50 Wehe, A.H., 25-l. 25-21, 25-25 Weidner, C.R., ix, 34-55 Weidner, R.T., vii, 50-38 Weijdema, J., 46-43 Weiler. B.E.. 25-9. 25-23 Weinaug, C.F., 20-1, 40-38, 48-14, 48-20 Weinbrandt, R.M., xi, 46-37, 46-45, 51-51 Weinstein, H.G., 48-16, 48-18, 48-20 Weiss, R.F., 25-22 Welch, L.W. Jr., 43-4, 43-16, 43-19 Welchon, J.K., 34-1, 34-55 Welex Inc., 49-41 Welge, H.J., 26-24, 26-33, 40-14, 40-17, 40-38, 43-4. 43-16, 43-19, 44-7, 44-11, 44-32, 44-49, 45-14, 48-18 Weller, W.T., 37-19. 31-22, 37-27 Wellington, S.L., 47-24 Wells, L.E., xi, 51-30, 51-52 Wen, W.-Y., 25-21 Wendorff, C.L., 55-12 Wenzel. H., 25-16, 25-23 West, R.C.C., 46-11, 46-43 West, T.J., 47-24 Westaway, M.T., 25-26 Westawav. P.. 50-38 Wetlaufe;, D.B., 25-26 Wharton, J.B. Jr., 40-37 Wharton, R.P., 49-41 Wheeler, D., 4451 Wheeler, J.A., 48-18, 55-12 Wheeler, M. F., 48- 19 Whinery, K.F., 12-44 Whitaker, A.H., 52-l Whitaker, S., 28-16 White, D.E., 24-1, 24-22 White, J.E., 51-13, 51-50, 51-51 White, J.L., 55-12 White, P.D., 4644 White, P.E., 4450 White, V.C., 24-22 Whiting, R.L., 24-23 Whitsitt, N.F., 55-12 Whitson, C.H., 39-11, 39-27, 48-19 Whittingham, K.P., 19-34 Whittington, H.M. Jr., 45-15 Wharton, L.P., 45-14 Wichert, E., vii, 20-5, 20-9, 20-15, 20-18 Wichmann, P.A., xii, 51-52, 53-26 Wiebe. R., 25-15, 25-17, 25-22, 25-23
PETROLEUM
Wieland, D.R., 54-12 to 54-14 Wiggins, W.R., 22-22 Wijen, A.J.M., 25-25 Wilcock, R.J., 25-23 Wilcox, W.I., 25-5, 25-23 Wilde, H.D. Jr., 34-37 Wiley, C.B., 54-14 Wiley, R., xii, 51-52 Wilf, J., 25-21 Wilhelm, O., 29-9 Wilkes, J.O., 34-55 Willard, R.O., 56-9 Willhite, G.P., 46-6, 46-43, 47-24 Williams, B.B., 56-9 Williams, D., 55-11 Williams, D.M., xii, 51-47, 51-52 Williams, H.L., 18-1 Williams, R.E., 44-51, 47-26 Williams, R.L., 48-6, 48-18 Willis, D.G., 51-44, 51-52 Willis, M.E., 51-51 Willits, K.L., vii, 18-52 Willman, B.T., 46-4, 46-12, 46-43 Willmore, C.B., 25-27 Wilson, D.L., 18-l Wilson, G.M., 25-15, 25-18, 25-21, 25-24 Wilson, J.F., 45-14 Wilson, J.M., 54-14 Wilson, K., 39-16, 39-28 Wilson, P., 6-72 Wilson, P.M., 6-28, 6-34, 6-72 Wilson, W.W.. x. 41-31. 41-37 Winkler, H.W., v, 5-1, 5-57 Winkler, L.W., 25-21, 25-23 Winsauer, W.O., 26-29, 26-33, 49-4, 49-41 Winsor, P.A., 47-l 1, 47-12, 47-25 Winter, W.K.. 48-18 Witherspoon, P.A., 38-20 Witte, M.D., 44-29, 44-34, 44-50 Wittick, T.R., 51-52 Wong, J.Y ., 48-20 Wang, T.C.T.. 54-12 Woo, P.T., 46-45, 48-16, 48-19, 48-20 Wood, J.W., 41-37 Wood, M.D., 55-12 Wood, P.M., 12-43 Woodard, R.G., 57-12 Wooddy, L.D. Jr., 26-33, 38-20, 43-16 Woodland, A.W., 29-9 Woodroof, R.A. Jr., 54-14 Woods, E.G., 36-10, 48-18, 48-20 Woods, R.W., 37-27, 40-13, 40-38 Woodward, P.J., 21-20 Wooley, G.R., 31-7 Work, L.T., 12-43 Worley, S.M., 12-44 Wright, F.F., 44-51 Wright, H.T. Jr., 26-33
ENGINEERING
HANDBOOK
Wright, J., 24-22 Wright, J.W., 53-26 Wrightman, L.S., 16-17 Wroblewski, S., 25-22 Wu. B.-J., 25-23 Wycoff, R.D., 30-11, 30-15. 30-17, 44-14, 44-16, 4417, 44-19 to 44-21, 44-49 Wygal, R.J. Jr., 46-43 Wyllie, M.R.J., xi, xii, 24-23, 26-20, 26-28, 26-30. 26-31, 26-33, 28-l. 28-8, 28-10, 28-15, 40-38, 49-41, 49-42, 51-6, 51-29, 51-47, 51-50 Wyrick, J., 11-13 Y Yaacobi, M., 25-21, 25-24 Yamamoto, S., 25-21 Yanosik, J.L., 48-11, 48-19 Yarborough, L., 20-7 to 20-9, 20-18, 23-9, 23-13, 33-18, 33-23, 45.14, 48-19 Yashida, F., 25-24 Yasunishi, A., 25-24 Yeh, S.-Y., 25-22 Yellig, W.F., 45-14 Yen, T.F., 50-38 Yoelin, S.D., 46-45 Yokoyama, Y., 28-11, 28-15 Youmans, A.H., 50-38 Young, A., 29-9 Young, D.M., 48.16, 48-20 Young, E.C., 14-1 Young, L.C., 48-18 Young, P.J., 54-14 Youngren, G.K., 46-12, 46-43, 48-18 Yuster, S.T., 28-15, 39-16, 39-28, 44-29, 44-50
Zaba, J., lo-37 Zana, E.T., 23-13, 45-14, 48-6, 48-19 Zanker, K.J., 19-34 Zapata, V.J., 47-24 Zarrella, W .M . 24-22 Zawisza, A., 25-22 Zeilo, GA, 36-6, 36-10 Zel’evskii, Y.D., 25-22 Zemanek, J., 51-52 Zemansky, M.W., xi, 51-50 Zerbe, C., 25-21 Zerpa, C., 25-25 Zhavoronkov, N.M., 25-22 Zheltov, Y.P., 55-2, 55-10 Zinc Institute, vi, 1 l-14 Zlomke, D., 47-26 Zublin, J.A., 6-34, 6-72 Zudkevitch, D., 20-7, 20-18, 48-18
Subject Index A Abandonment pressure, 39-8, 39-10, 39-11. 39-14, 39-16, 39-23. 40-8, 40-10, 40-16, 40-24, 40-33, 40-34 Abandonment time, 41-21 to 41-23, 41-27 ABC transaction, 41-8, 57-7 Abrasion-resistant coatings, 1l-6 Abrasive jet cleaning, 56-1 Abrasive well fluids, 6-34 Absolute open flow, 33-6 to 33-10. 34-33. 34-35 Absolute ownership. control, 57-2 definition, 57-1 theory, 57-l Absolute permeability, effect of temperature on. 46-37, 46-38 Absolute pipe roughness, 15-4, 34-2, 34-24, 34-27 Absolute viscosity, definition, 22-13 Absolute zero, definition, 20-l Absorbed dose, unit and definition, 58-10, 58-23, 58-36 Absorption, 26-11, 39-27 Absorptive interactions, 50-9 Abstract of API manual, 17-3 to 17-S Abstracts examination, 57-9 Acceleration head, 6-50, 6-5 1 Accelerometer, 534 Accessory equipment for liquid hydrocarbon metering systems, 17-4 Accounting method of valuation, 41-16, 41-17, 41-19, 41-22 to 41-24 Accumulator, 18-13 to 18-15, 18-50, IS-51 Accuracy and rounding of numbers, 58-5, 58-6 Accuracy, of bubblepoint pressure correlations, 22-8, 22-9 of Organick-Golding correlation, 21-15 vs. precision, 58-S. 58-9 Acentric factor, 20-13 Acetic acid (HAc), as sequestering agent, 54-7 in acidizing, 54-3, 54-8, 54-10 Acetylene water system, 25-24 Acid, concentration, effect on limestone dissolved, 54-2 emulsions, 54-8 major types for acidizing, 54-l primary requirements for acidizing, 54-l solubility test, 54- 11 solution of limestone in, 54-2 strength, estimated in field, 54-3 treatment design, 54-9 to 54- 11 Acid additives, alcohols, 54-8 corrosion inhibitors, 54-6 gelling and fluid-loss agents, 54-8 iron-control agents, 54-7, 54-8 liquefied gases, 54-8 retarded acids, 54-8 sequestering agents. 54-7 silicate-control agent, 54-7 surfactants, 54-6, 54-7 thickeners, 54-8 Acid concentration. effect on acid reaction rate, 54-5 Acid fracturing, 54-8, 54-9 Acid gases removal. 14-21, 14-22
Acid-in-oil emulsion, 54-8 Acid inhibitor, 54-10 Acid number, 47-19, 47-23 Acid penetration of matrix. 54-10 Acid reaction rates, factors affecting, acid concentration, 54-5 area/volume ratio, 54-5 flow velocity, 54-5 formation composition, 54-6 pressure and temperature, 54-4, 54-5 Acid solubility, 5416 Acid solubility tests, 54-9 Acid-soluble &ales, 54-6, 56-2 Acid solvent, 56-2 Acid strength, 54-2 Acid-swellable synthetic polymers, 54-10 Acid-thickening additives, 54-8 Acid treatment design, fracture acidizing-carbonate formations, 54-11 matrix acidizing-carbonate formations, 54-10, 54-l 1 matrix acidizing-sandstone formations, 54-11 Acids used in acidizing!. 54-l to 54-4 Acidizing, acid reaction rates, 54-4 to 54-6 additives, 54-6 to 54-8 critical wells, 54-l 1, 54-12 general principles, 54-l to 54-4 general references, 54-12 to 54-14 introduction, 54-l laboratory testing, 54-9 references, 54-12 solutions, 54-3 summary, 54- 12 techniques, 54-8, 54-9 treatment design, 54-9 to 54-l 1 well treatment, 6-3, 354. 56-3 Acme thread profiles, 2-1, 2-38 Acoustic array logging, 51-25 Acoustic array sonde, 51-27, 51-28 Acoustic backup system, 18-15, IS-16 Acoustic beacons, 18-2 1 Acoustic energy, 51-I. 51-11, 51-20. 51-24, 5141 Acoustic impedance, 5146, 5147 Acoustic intensity, 51-3 Acoustic log correlation, 51-30 Acoustic log vs. core analysis porosity, 51-32 Acoustic logging, acoustic wave propagation in rocks, 514 to 51-l 1 acoustic wave propagation methods, 51-l 1 to 51-14 applications, 51-28 conclusions, 5147, 5148 elasticity, 51-l to 514 introduction, 5 l-l methods of recording acoustic data, 51-14 to 51-28 nomenclature, 5 148 references, 51-50 to 51-52 theory of elastic wave propagation in rocks, 5149, 51-50 Acoustic logs, 41-8, 51-30 lo 51-33, 51-37. 51-38 Acoustic positioning beacons, 18- 10 Acoustic properties of rock, 514, 51-5 Acoustic signal transmission system, 18-3
Acoustic telemetry, 53-l Acoustic transit (travel) time, 5 l-16 to 51-33, 51-35, 51-39, 5140, 5145, 51-47, 53-l Acoustic velocities, 3445, 3446, 51-29, 51-31, 5143 Acoustic velocity log, 5 l-5 Acoustic wave propagation in rock, acoustic properties, 514, 51-5, 5143 borehole modeling, 5 l-25 fluid composition, 51-7, 51-8 introduction to, 514 porosity, 5 l-5 rock composition, 51-5 stress, 51-6, 51-7 studies, 51-34 summary of, 51-11 temperature. 5 1-7 texture, 51-S to 51-11 understanding of, 5 148 Acoustic wave propagation logging, 5 l-27 Acoustic wave propagation methods, in fluid-filled borehole. 51-12 introduction to, 51-l 1 reflection, 51-2 transmission, 5 l-2 Acoustic wave propagation properties, 5 1- 1 Acoustic wave train analysis, 27-l Acoustic waveform, 51-12, 51-14, 51-18, 51-24. 51-26, 51-27, 5140 to 5143, 51-45, 5147, 5148 Acoustic waves, characteristics. 51-3 compressional, 5 l-2 information contained in, 5 I- 18 shear, 51-2 transit time of, 51-29, 51-30 Acoustical survey, 540, 49-l Acoustical well sounder, 30-7 Acoustics, units and conversions, 58-36 Acquisition and acquisition costs, 4 l-13, 41-15 Acre-feet diagram, 404 Acrylamide polymer, 44-39 Activated aluminas, 14-21 Activation energy, 46-12 Activation gamma ray, 50-3 Activity coefficient of water, 25-3 Activity coefficient plot, 254 Activity of radionuclide, unit and definition, 58-10, 58-23 Actuator ratio, 3-27 Actuator specifications, 3-27 Ad valorem taxes, 39-27, 41-1, 414, 41-7, 41-9, 41-12 Adapter, 3-9, 3-39 Adapter flange, 3-8, 3-9, 3-13 Adaptive implicit formulation, 48- 14 Adiabatic horsepower, 3442, 34-44, 3445 Adjustable choke, 5-54, 14-3 Adjustment factors, critical flow prover, 33-13 to 33-15 Administration and supervision costs, 41-12 Administrator of an estate, definition, 57-3 Adsorption approach, statistical mechanics for, 25-5 Adsorption cycle, 14-10 Adsorption dehydration unit, 14-20 Adsorption ion exchange, 48-5 Adsorption rate of an emulsion, 19-5 Adsorption reaction, Darcy’s law, 26-l I
16
Advanced Ocean Drilling Program, 18-15 Advantages. of batch-type meters, 32-10, 32-l I of gas lift. 5-l. 5-2 of positive-displacement meters. 32. I I, 32-12 of Sl units. 58-9 Adverse moblllty ratio waterfloods, 48-1 I Adverse possession, 57-2 Aeolian dune sandstones, 36-4 Aerobic bacteria, 24-16, 24-17 After breakthrough performance, 44-20 to 44-25 Afterflow, 30-9, 30-10, 31-6 Agglomerator. 12-12 Agitation. in crude oil emulsions. 19-6 to 19-9. 19-12, 19-13, 19-27 in foaming oils, 12-7 in removing nonsolution gas, 12-13 in separation of water from oil, 12-27 Agitation of stored product, evaporation loss. I I-12 Air-balanced pumping units, IO-1 to 10.3, IO-X, IO-9 Air buoyancy, effect of, I-70. I-71 effect on mass, l-70 Air-buoyancy risers. 18-15 Air circuit breaker, IO-28 Air compressors, 46-20 Air counterbalance diagram, 10-3 Air flotation process, 15-27 Air injection, fireflood. 46-28, 46-29, 46-3 I, 46-32 Air injection rate, tireflood, 46-19. 46-28. 46-33 Air motor engine starters. IO-19 Air/oil ratio. 46-17. 46-19, 46-28 to 46-30 Air Products-Greenwich, 46-3 I A)r requirements, firefloods, 46-13. 46.16, 46-19 An-steam injection, 46-23 Air/steam ratio. 46-23 Air/water ratio, 46-33 Airy phase. 51-12, 51-13 Alabama. 24-20, 4436 Alarm-signal loops, 16-9 Alaska, 18-3, 18-38, 1X-41, 18-42, 24.20, 24-21, 27-9, 27-19, 51-8, 57-11 Alberta, characteristics of produced waters, table, 24-8, 24-12 ptlot proJect, 44-40 Redwater D-3 reef reservoirs, 40-2, 40.20 reservoirs, water-oil displacements, 48-6 sedimentary strata in, 24-19 Alcohols, in acidizing, 54-8 in hydrate Inhibiting, 14-6 in phase environment shifts, 47-13 in removing water blocks, 56-2 Algae, 4442. 4444 Algorithms, for applicability in jet pump performance, 6-46, 6-47 for computing dipmeter plots, 53-16 for computing relative permeability, 28-14 for screening of micellaripolymer flooding, 48-6 Alkaline flooding 48-5, 48-7 Alkaline processes, 47-l Alkaline water breakthrough, 4440 Alkalinity, 44-44 Alkanolamine condensates, 19-10 Allowable depletion, 41-13. 41-14 Allowable gas velocity, 12.22 Allowable loading, 9-4 Allowable stress, 94, 9-8, 9-13, 12-38, 12-41 Allowable working pressure, maximum, 12-40
PETROLEUM
Allowable working pressures for piping, 15-l I Allowables, discovery. 32-2, 32-3, 32-15 history of. 41-9 production rate. 32-l. 43-2, 43-10 Texas rule, 32-l yardstick schedule, 32-3 Allowance factor. 39.24 All-welded screens, 56-7, 56-8 Alpha emitter, SO-6 Alpha radiation, 50-2 Alternative minimum tax, 41-14, 41-15 Alternative subsea control systems, 18-49, 18-50 Alternating-direction iterative methods (ADI), 48-16 Aluminum, 12-41, 24-9, 50-3, 50-4. 50-8, 50-18. 50-23. 50.34, 50-35 Aluminum bolted tanks. II-9 Aluminum pellets, 55-S Alundum, 26-6 Amagat’r law, 20.4 Amerada gauge temperature element, 3 I 1 Amerada pressure gauges, 30-I. 30-2, 30-4, 32-6 American Assn. of Petroleum Geologists (AAPG). 40-2 American Gear Manufacturers’ Assn., 10-12, IO-13 American Natl. Standard Inst. (ANSI), piping pressure ratings, 15-14 American Petroleum Inst. (API), API analysis of oilfield waters, 24-5, 4443 API barrel, 58-23 API casing and tubing threads, 6-2 API casing hangers. 3-39 API circumferential displacement values, 9-9 API commtttee. gamma ray calibration standards. 50-20 API committee, standardization of steel tanks for oil storage, I l-3 API committee, statistical study of recovery efficiency, 44-32 API esttmation of oil and gas reserves, 40-12 API flanged or clamped wellhead equipment, adapters. 3-9 backpressure valves. 3-8 bottomhole test adapter, 3-13 casing hangers. 3-5, 3-6 casinghead and tubing-head flanges, 3-4 Christmas-tree fittings, 3-13 clamp-type connectors, 3-5 crossover flange. 3-9 flange data, 3-18 to 3-25, 3-27 intermediate casmg hangers, 3-8 intermediate casing heads, 3-6 to 3-8 joint gaskets, 3-28 to 3-32 lowermost casing heads, 3-2 to 3-5 multiple-completion equipment, 3-13 to 3-18 physical properties, 3-2 to 34 thread limitations, 3. I tubing hangers. 3-8, 3-9 tubing-head adapter flange, 3-9 to 3-l I tubing heads, 3-8 valves, 3-11 to 3-15 wellhead assembly, 3-2 working and test pressure terminology, 3-1, 3-2 working pressure ratings, 3-2 API flanges, 3-39 API gravity, 58-24
ENGINEERING
HANDBOOK
API gravity. correction of observed value, 17-5. 17-6 API gravity of crude petroleum, 17-5 API gravity of fluid columns. 6-22. 6-23. 6-26 API gravity of light hydrocarbons, 17-5 API gravity of liquid petroleum products, 17-5 API gravity scale hydrometer test method, 17-l API horsepower rating curves. IO-17 API independently screwed wellhead equipment, 3-39 API joint committee. proved reserve definition. 40-2 API magnetic tape standard. 49-37 API maximum working pressure ratings, casinghead and tubing-head flanges. 3-4 flanged-end connection, 3-4 valves, 3-l 1 wellhead assembly, 3-3 wellhead equipment, 3-3 API Midwest Research Inst., IO-7 API modified Goodman diagram, 94. 9-5, 9-8, 9-9 API oil-water separator, 15-25 API pin thread, 9-12 API piping pressure rating. 15-14 API preferred metric tutus. 17-7 API pump barrel tolerance, 8-5 API pump designation. 8-2 API recommended practice for design calculations for sucker rod pumping systems, 8-10, 9-2. 9-3 API Research Project 25, 3 I-1 API rod grades, 9-5. 9-X API safety and pollution prevention equipment (SPPE), 3-39 API scale, relative density, l-80 API separators, 15-23. 15-24 API spec. for bolted productton tanks, 11-l API spec. for pumping units, IO-4 API spec. for reinforced plastic sucker rods. 9-t I API spec. for shop-welded tanks for storage of production liquids. I l-l API spec. for sucker rods, 9-l API spec. for wellhead and Christmas-tree equipment. 3-36 API std. for hydraulic pumps, 6-21 API study on well spacing. 40-16 API Subcommittee on Recovery Efficiency, 40-12, 40-17 API subsurface pump bores, 8-l API subsurface pump classification. 8-3, 8-4 API subsurface pumps and fitttngs, 8-2, 83, 8-6 API sucker rod pins, 9-10 API sucker rod pumping system design book, 9-4 API task force on performance properties, 2-54 API test method, 55-5 API threading data, 2-64 to 2-72 API torque rating, IO-5 API unit of radioactivity, 50-15, 50-20, 50-24 API valve rods, 8-2 American Sac. of Mechanical Engineers (ASME), ASME code for unfired pressure vessels, 12-38 ASME qualification as SPPE certificate holder, 3-39
SUBJECT
INDEX
American Sot. for Testing Materials (ASTM). ASTM, API scale approved, l-80 ASTM. Committee D-19 standardizes methods of analyzing oilfield waters. 24-S ASTM distillation method. 26-22 ASTM RVP technique, 14-13 ASTM std. viscosity/temperature charts, 19-x ASTM viscosity charts, 6-67 ASTM wood-back or corrosion-resistant metal cup case, 17-l American Standards Assn.. valves. 3-l I American wire gauge. 7-S Amine gas desulfurizer, 14-21 Ammeter chart record, 7-6 Ammeter spikes, 7- 14 Ammonia, 14-8, 14-9 Ammonium fluoride. 54-4 Amoco, 16-13. 46-14, 46-15, 4618, 46-30, 46-33. 47-22 Amortization, 41-5, 41-7, 41-16 to 41-18, 41.20, 41-21, 41-23, 41-24 Amount of substance, 58-7. 588, 58-23, 58-27 Amphoterics. 47-7 Amplitude attenuation, 51-14 Amplitude log, 51-45 to 51-48 Amplitude/time recording. 5 I I8 Anaerobic digestion, 25-18 Analog computer, 9-2 Analog methods for areal sweep efficiency, 44-17 Analog model, 39-22, 4418 Analogies, single-phase value to multiphase equivalent, 35-2 Analogy technique for reserve estimation. 40-l Analysis methods, for oilfield waters. 24-S for water drive reservoirs, 38-4 to 38-9 Analysis, of a reservoir. 42-3 of condensate liqurd and gas. 21-8 Analytic models for pump performance, 7-12 Analytical-appraisal method for fair market value, 41-2 Analyzing crude oil emulsions, 19-6 Anchor line tension, IX-IO Angle-averaging method of calculating directional surveys, 53-5 Angles of incidence, Sl- I2 Angles, Sl units for. 58-5 Angular velocities. conversion of, table, I-76 Anhydrite, 50-34, 50-35, 51-31 Aniline point, 21-3 to 21-5. 21-9 Anion exchange capacity (AEC), 52-21 Anionic repulsion, 47-3 Anionics, 47-7. 47-8, 47-21 Anions, 24-9, 24-12, 24-17. 44-45 Anions conversions, 49-4 Anisotropy of strata. 49-S Annual deferment factors, 41-27, 41-30 Annuity. tables, amount of, l-63 amountmg to a given sum (sinking fund), l-65 present worth of an, l-66 provided for by a given capital, 1-66 Annular preventers, 18-I I, 18-12, 18-15 Annular temperature, 53-2, 534 Annular velocities, 52- I8 Annulus, effect on induction log, 49-17 Antelope field, Texas, 16-12 Anticlinal folds, 29-2 Antisludge agents. 54-7
I7
Antoine equation, 20-13. 20-17 Appalachian area. 24. I. 24-6. 24-7 Appalachian oil fields, 44-44 Apparent convergence pressure, 39-l 1 Apparent formation resistivity factor, 26-30. 26-3 I Apparent formation thickness, 53-15, 53-16 Apparent limestone porosity. 50-21. 50-28. 50-30 Apparent liquid density, definition, 22-20 of natural gases, 22-4 Apparent mole weight. 20-14 Apparent molecular weight of gas mixtures, 20-4 Apparent viscosity, 47-S. 55-5 Apparent water-filled porosity, 49-34 Application and selection, of gas scrubbers, 12-35. 12-38 of separators, 12-35 Application of acousttc logging, cased-hole evaluation, 51-42, 5 143 cement bond quality. 5140 fracture evaluation, 51-45 to 51-47 geopressure detection. Sl-39, 51-40 hydrocarbon content. 51-35 to 51-38 introductron to, 5 l-28 lithology, 51-35 mechamcal properties, 51-43 to 51-45 permeability. 51-47 porosity, 5 l-29 to 51-35 seismic and geologrcal interpretation, 51-28. 51-29 Application of metric system, general, 5X-3 style and usage, 58-3 units and names to be avoided, 58-5 usage for Gelected quantrties, 58-3 to 58-5 Applications, of BHP. 30-8 to 30-15 of caliper logs. 53-17 of dipmeter and directional data, 53-10 to 53-16 of ESP system, 7-1, 7-2 of fiberglass sucker rods, 9-12 of floating production facilities, 18-34, 18-35 of gas Itft. 5-l of range of jet pumps, 6-46, 6-47 of stzing of jet pump, 6-41, 642 of sucker rods, steel, 9-2 of wellhead equtpment. 3-36 to 3-39 Appraisal equations, or1 and gas reserves. 41-17, 41-18 Appraisal value: methods for computation, Intermediate interest rate, 41-8 safe interest rate, 41-3. 41-5, 41-6 speculative interest rate. 41-6 to 41-8 Approach factor, 13-2, 13-3 Approximate methods for water drive behavior. 38-8. 38-9 Appurtenances, II-6 Aquathermal pressuring, 52-22 Aqueous phase relative permeability, 47-9 Aqueous/volatile gas systems. 25-3 Aquifer conductivity. 38-9 Aqutfer geometry, 38-1, 38-4. 38-5, 38-8 Aquifer material balance, 38-8 Aquifer permeability. 38-9 Arabian Gulf. 18-2 Aramid fiber, 6-50 Archie equation, 26-3 I, 49-5 Arctic, drscovery, commercial, 18-3 environmental conditions, IS-38 to 18-40 production structures, 1840 to 18-42 special considerations, 18-43 transportation systems, 18-42, 18-43
Arctic Marine Hydrocarbon Production project, I X-3 Arctic mobile drilling structure. 18-42 Arctic Ocean, 18.38, 18-43 Arctic oil fields, 18-43 Arctic Pilot Project, 18-3 Arctic pipelines, 18-43 Arctic polar pack, 18-39 Area equivalents, table, 1-73 Area ratio, jet pump, 6-36 to 6-43. 646 Area units, SI metric system, 58-22. 58-23 Area/volume ratio, effect on acid reaction rate, 54-5 Area1 coverage, 44-39 Area1 coverage factor, 44-7, 448 Areal cusping. 48-10 Areal pattern efficiency. 44-S. 44-12 to 44-2s Area1 sweep, 46-14, 46-21. 46-30. 46-31 Area1 sweep efficiency. 39-15. 39-t 7 , .*, 39-18, 39-22. 39-23, 43-3, 43-7 to 4 3 9, 44-2, 44-28. 46-24. 47-2 Area1 sweep efficiency. at breakthrough, 44-20, 44-25 by analog investigations. 4417 by mathematical analysis, 44-13 to 44.-1 7 by numerical models, 4417 directional permeability effects, 44-25 methods of determining, 44-13 to 44-2 15 mobility ratio effects, 44-17 to 44-24 reservoir dip effect, 44-25 reservoir fractures effect. 4425, 44-26 Areas of circles by eighths, table, l-28, l-29 Areas of circles by hundredths. table, l-26. l-27 Areas of circles, sq ft. table, I-30 Argentina, 51-33. 58-20 Arithmetic average temperature. 34-8 Arkansas, 21-4, 21-7, 24-8, 24-21. 27-2, 27-3, 46-3, 46.15, 46-24 to 46-26 Arkose sediments, 29-7. 29-8 Aromatic solvents, 56-2 Arrhenius equation, 46-12 Arrhenius reaction rate, 48-5 Arrow mot. 53-10. 53-l I Arsenic, in emulsion-treating chemicals. 19-10 Arsenic inhibitors, 54- 1 Articulated loading tower. 18-30 Articulated tower, 18-34, 18-35 Artificial ignition devices, 46-20 Artificial islands, 18-40 Artificial lift, 5-l. 5-28, 6-l. 6-6, 6-7. 6-60, 6-69. 1844. 39-16. 40-4 Artificial lift system, 36-2 Artificial lifting, 30-S. 30-14. 30-15 Artificial lifting equipment. 41-3 Artificial radiation, 50-6 Asbestos-cement pipe, 15-7, 15-10 Asphalt quality. 2 l-7 Asphalt Ridge field. Utah, 46-16, 46-30, 46-31. 46-33, 46-34 Asphalt seals, 29-S Asphaltene buildup, 46-22 Asphaltenes. 19-10, 19-30 Asphaltic-based oils, 19-5 Asphaltic crudes, 6-67 Asphaltic oils, 24-18 Asphalts, 39-l Assignments hy landowner, 57-6 Assignments by lessee, 57-7 Associated/dissolved gas, 40-3 Associated gas, 40-3 Asymmetrical anticlines, 29-2 Athabasca tar sand, 46-34 Atlantic Refining Co., 38-4
PETROLEUM
Atomic C/O density ratio, 50-2, 50-35 Atomic densities, 50-35 Atomic H/C ratio, 46-16 Atomic number, 50-2, 50-3. 50-7 Attenuation, 51-3, 51-4. 51-11. 51-12, 51-38, 51-47 Attenuation curve, 49-34, 49-35 Attenuation factor, 49-33, 49-34 Attenuation rate, 49-32 Attic oil, 43-l. 43-2 Austin chalk, 36-l Australia, 12-39, 27-9, 27-19 Austria, 12-39 Authority for expenditure (AFE), 15-31 Automated water jets, 19-29 Automatic backwash, 16-14 Automatic casing hanger, 3-6 Automatic control, installations, 16-10 of dry-desiccant-type gas dehydrators, 16-15 of injection-pumping rate, 16-15 of water-supply wells, 16-15 valves, 164, 16-11, 16-12, 16-15 Automatic controller, 13-50 Automatic controls, for rod-pumped wells, 16-l I of gas-lift well, 16-l I Automatic custody transfer (ACT), 12-3, 16-2, 16-5, 16-6, 16-13 Automatic cycling of desiccant beds, 16-15 Automatic lease process control, 16-14 Automatic positive choke. 13-57 Automatic production-control equipment, 16-2 to 164 Automatic production programmers. 16-3 Automatic quantitative liquid measurement, 16-5 Automatic safety shut-in system, 18-47, IS-48 Automatic sampler. 16-7 Automatic tank battery, 32-14 Automatic water-treating plant, 16-14 Automatic well manifolds, 16-l 1, 16-12 Automatic well testing, 16-12 Automatic wellhead controls, 16-10 Automatic wellhead safety controls, 16-10 Automatic well-testing system, 16-12 Automatically controlled valves and accessories, 16-2. 16-3 Automation of lease equipment, BS&W monitor, 16-7 control installations, 16-10 to 16-12 gas measurement, 16-6, 16-7 general references, 16-16 introduction, 16-1, 16-2 netail computer, 16-7, 16-8 production control equipment. 16-2 to 16-4 production safety controls, 16-4, 16-5 quantitative measurements, 16-S. 16-6 references, 16-16 sampler, 16-7 supervisory control and data transfer (SCADA) systems, 16-S to 16-10 temperature measurement, 16-7 well testing, 16-12 IO 16-16 Autotransformer converter, 10-35, IO-36 Average annual ROR method, 41-17, 41-19, 41-21, 41-23, 41-24 Average book method of valuation, 41-22 Average deferment factor, 41-25, 41-29, 41-31 Average GOR, 32-15 Average reservoir pressure, 30-S. 30-9 Average reservoir pressure, determination, 35-16 Avogadro’s number, 50-6, 50-35
Avogadro’s principle, 5- 1 I Axial-flow pump, 6-1, 15-15 Axial-flow turbine meter, 1348 Axial load(s) or loading, 2-2. 2-20 to 2-28, 2-34, 2-35, 18-6. 18-17, 18-22, 18-24 Axial stress, 2-3, 2-34, 2-35. 246. 2-55, 2-56, 9-9 Axial stress on casing, 2-20 to 2-28, 2-32, 2-35 Azimuth, of hole, 53-1, 53-2, 53-7, 53-10, 53-17 of hole deviation, 53-10 of reference electrode, 53-10 Azimuth angle, 53-5, 53-6, 53-8 Azimuth frequency diagrams, 53-12
B Bachaquero field, Venezuela, 24-13 Backflow, 44-35 Backflow method, 56-5 Backpressure controller, 13-51. 13-58 Backpressure curve, 34-3. 34-31 to 34-34, 34-46 Backpressure equations, 33-5. 34-30 to 34-35 Backpressure regulation, 13-54 Backpressure test data, 39-23 Backpressure testing, 33-3 to 33-6, 33-10, 33-20 Backpressure valve mandrel. 3-9 Backpressure valves, 3-8, 3-9, 11-10, 13-56 Backsurging method, 56-5 Backup control systems offshore, 18- 15 Backwash cycle, 16-14 Backwashing, 39-26, 44-43, 4447 Bacteria, 18-30. 44-46 Bacteria control equipment, 24-2 Bactericide, 44-41 to 44-44 Baffle plates. 19-12, 19-13 Baffling, 12-7. 12-13 Bahama Islands, 29-8 Balance line valve, 3-27 Balanced tangential method of calculating directional surveys, 53-5. 53-6 Balanced-type gas lift valves, 5-39 Ball bearings. 13-48 Ball joint angle, 18-17 Ball sealers, 55-9 Ball valve seat, 5-14, 5-15 Ballasting systems, 18-7 Ballooning effect of tubing string, 4-9, 4-10 Baltic Sea, 24-19 Bat&line-Owen field, Texas, 40-33 Barge-launched jacket, 18-25 Barge-mounted deck, IS-23 Barges, measurement and calibration, 17-3 Barium, 24-9, 44-44, 4445, SO-16 to 50-18 Barn. definition, 50-6 Barrier bar, 36-4 Barrier-island sandstones, 364 Bartlesville Energy Technology Center (BETC), 21-9 to 21-11 Bartlesville sand, 44- 1, 444 Base conditions for natural gas fluids, 17-7 Base of crude oil, 21-1, 21-3 Base pressure, 32-14 Base units, SI metric system, l-69, 58-3, 58-9, 58-10, 58-21. Basic data required, solution-gas-drive reservoirs, OIP, 37-3 pseudorelative permeability, 374, 37-5 PVT. 37-3 relative permeability, 37-3 saturations, initial fluid, 37-3 Basic energy equation, 34-2, 34-9
ENGINEERING
HANDBOOK
Basic orifice factors, 33-13 Basic orifice flow factor. 13-3 to 13-11 Basic sediments and water (BS&W), 16-2, 16-7, 16-13, 17-2, 19-1, 19-6, 19-10, 19-15, 19-31, 32-6, 32-7, 32-10 BS&W monitor, 12-16 Batch treatment method, 19-l I Batch-type meters, 32-6. 32-9 to 32-11 Bathymetry. 18-16, 18-39 Battrum No. 1 field, Saskatchewan, 464 Baum& scale, relative density, l-80 Bauxite, sintered particles, 55-8 Bay Marchand field, Louisiana, 44-37, 44-38 Beal’s correlation for dead-oil viscosity. 22-14 Beam-balanced pumping units, 10-I to IO-3 Beam-type pumping unit, 10-16, IO-23 Bean, 34-45 Bearings in turbine meters, 1348 Bed detection and definition of well logs. 49-25 to 49-36 Bed thickness, effect on acoustic velocity logging device, 51-16 Beggs and Brill correlation, 46-7 Beggs and Robinson correlation, 22-15, 22-16 Behavior index. 55-5 Bell Creek MP flood, Montana, 47-16 Bellamy field, Missouri, 46-3 Bellevue field, Louisiana, 46-4, 46-15. 46-18, 46-19, 46-34 Bellows-assembly load rate, 5-16, 5-17, 5-37 Bellows BHP element, 30-l. 30-6, 30-7 Bellows-charge pressure, 5-16, 5-17, 5-33 Bellows-charged dome pressure, 5-3. 5-6, 5-7, 5-18, 5-19, 546, 549 Bellows-charged gas lift valves, 5-6, S-12. 5-16, 5-17, S-20, 5-21, 5-23, 5-37, S-39, 542 Bellows guide tube, 5-12 Bellows meter, 13-36. 13-37 Bellows PD meter, 32-12 Bellows protection. 5-16 Bellows-type chari recorder, 16-6 Bending failure, 18-39 Bending load fracture strength of casing, 2-61 Bending moment, Sl unit for, 58-5, 58-34 Bending stress, 18-13, 18-17 Benedict-Webb-Rubin EOS, 20-7 Benzene, 244, 24-18 Berea cores, 47-8 Berea sandstone, 28-8, 28-9, 28-11, 51-6, 51-8 Bering Sea, 1842 Berl saddles, 12-10 Bernoulli’s theorem, 15-l. 15-2 Beryllium, SO-6 Bessel factor, l-61 Beta radiation, 50-2 Bid shopping, 15-31 Bimetallic corrosion. 3-36 Binary liquid/vapor system, 23-3 Binary uhase diagrams. 23-2 to 23-6 Bino&l coefti&nts, table, l-37 Binomial distribution, SO-5 B&ides, 47-5, 47-10 Biofouling, IS-51 Biogenesis, 25-18 Bioherm reefs, 36-5, 36-6 Bioherms, 294, 29-8 Biological degradation, 47-5 Biological surveys, IS-5 Biopolymers, 47-4 Biostrome reefs, 36-5, 36-6
SUBJECT INDEX
Biostromes, 29-4, 29-8 Biot theory, 51-8 Birdwell, 51-18, 51-27 Bi-rotor PD meter, 32-l 1, 32-12 Bit guide, 3-6 to 3-8 Bittern, 24-20 Bitumen, 19-30, 46-31 Black iron sulfide scale, 9-8 Black-oil material balance, 37-25, 37-26 Black-oil model, 484 to 48-7, 48-9, 48-14 Black-oil reservoirs, 48-2, 48-8 Black-oil rings, 39-5, 39-22 Black-oil simulator, 36-10, 45-13 Black oils, 37-22, 37-23, 37-25, 37-26, 39-17, 39-26, 40-13 Black Sea, 24-19 Blank runs, 26-21 Blanking tool, 6-48 Bleed-type sensors, 3-34 Blender iar. 52-9. 52-10 Blenders”, 55-9 Blind and test flanges, 3-25 Blind-shear ram, 18-l 1, IS-20 Blind zone on lateral curves, 49-13, 49-14 Block-and-bleed-type sensors, 3-34 Block diagram, 15-30, 51-28 Blocking agent, 56-l Blocking fluids, 56-2 Bloomer field, Kansas, 16-12 Blotter model, 39-2 1, 44 17 Blowdowns, 1l-6 Blowout, 18-l 1, 56-3 Blowout preventer (BOP), 3-2, 3-6, 3-9, 3-38, 3-39, 7-13, 18-4, 18-6, 18-9, 18-11 to 18-21, 18-34 Blowout preventers, annular, 18-11, 18-12 hydraulic connectors, 18-12 kill and choke (K&C) valves, 18-12 ram. 18-11 unitized stack, 18-12 Blowout preventer stack, 18-11 to 18-19, 18-31, 18-34 Bluff body, 16-6 Boberg and Lantz method, 46-9 Boberg and West correlation, 46-l 1 Bodcau field, Louisiana, 46-21 Boiling point, cubic average, 21-12, 21-15 definition of types of, 21-11, 21-12 mean average, 21-11, 21-15 molal average, 21-6, 21-11, 21-13 to 21-15, 21-17 molar distribution of SCN groups, 39-l 1 of hydrocarbons, 19-7 of six refrigerants, 14-10 volumetric average, 21-11, 21-12 vs. K-value, 39-12 Boise sandstone, 51-8. 51-9 Boll-weevil casing hanger, 3-6 Boll-weevil tubing hanger, 3-9 Bolted-steel tanks, 11-l to 11-3. 11-6, 11-9, 11-11 Bonding conditions, cement, 51-40 to 5 l-42 Bonus, oil and gas lease, 57-4, 57-7 Booster application, ESP, 7-2, 7-3 Booster pump, 15-17, 44-47 Borehole acoustic measurements, 51-28, 51-29, 51-44. 51-45, 51-47, 51-48 Borehole-compensated (BHC) acoustic log, 51-1.5 Borehole-compensated device, 50-15 Borehole-compensated sonde, 5 l- 15 Borehole-compensated sonic log, 49-15, 51-16, 51-17, 51-24, 51-26, 51-30, 51-32, 51-37 Borehole-compensated sonic tool, 49-32
19
Borehole-compensated sonic travel time, 5 1-22 Borehole-compensated transit time, 51-21 Borehole configuration, 53-16, 53-17 Borehole corrections, IL, 49- 18 Borehole, fluid-filled, acoustic wave propagation in, 51-12 to 51-14 Borehole geometry, 51-19, 51-28 Borehole geometry log, 53-17 Borehole geophysical devices, 58-25 Borehole measurement of transit times, 5 1-26 Borehole reflection method, 51-46 Borehole size effects, 51-19 Borehole televiewer, 51-27 to 51-29, 5141, 51-46, 53-17 Borehole televiewer log, 51-46 to 51-48 Boron, 24-4, 24-5, 24-12, 50-6, 50-l 1, 50-12, 50-14, 50-32, 50-36 Borosilicate glass, 244 Boscan field, Venezuela, 6-24, lo-18 Bottle tests, 19-10, 19-15 Bottom discharge application, ESP, 7-2, 7-3 Bottom gas lift valve, selecting, 5-26 Bottom intake application, ESP, 7-2, 7-3 Bottom-seating holddown, 8-3 Bottom-seating stationary-barrel rod pumps, 8-8 Bottom-unloading gas lift valve, 5-51 Bottomhole assembly (BHA), 6-3 to 6-6, 6-3 1, 6-39 Bottomhole bumper spring, 5-52, 5-53 Bottomhole collar lock, 5-52 Bottomhole GOR, 37-23, 37-24 Bottomhole pressure (BHP): gas wells, 34-3 to 34-27 gas-condensate wells, 34-27, 34-28 gas injection wells, 34-28 to 34-30 liquid injection wells, 34-28 Bottomhole pressure buildup analysis, 40-27 Bottomhole pressure calculations, by Cullender-Smith method, 34-25, 34-26 by Sukkar-Cornell method, 34-9 to 34-24 flowing gas wells, 34-23, 34-24 gas-condensate wells, 34-27 static gas well, 34-8, 34-9 Bottomhole pressure gauge, 3 I- 1 Bottomhole pressure instruments, 30-l to 30-6, 30-15 Bottomhole pressure, steamflood, 46-17 Bottomhole pressures, 30-I to 30-15 Bottomhole test adapter. 3- 13 Bottomhole valve temperature, 5-46 Bottom-water, 24-2 Bottomwater drive, 40-15, 41-10, 48-4 Bounded
reservoirs,
shape factors,
35-5
Bounding additive, 46- 19 Bourdon tube, 13-38, 13-56, 16-4, 16-7. 30-1, 30-2, 304, 30-6, 30-7, 31-1 Box and pin entrance threads, extreme-line casing joint, 2-64, 2-69, 2-70 Box and pin subcoupling, 9-4 Boyle’s law, 20-1, 20-2, 26-6, 26-7, 27-1, 30-B Boyle’s-law-type porosimeter, 26-4, 26-6 Bradford field, Pennsylvania, 24-I) 24-2, 44-1, 44-4, 47-22 Brake horsepower, 10-9, 10-17, IO-19 Brazil, 12-2, 12-21, 46-3, 46-4, 58-20 Brea field, California, 46-16, 46-18, 46-24, 46-25 Brea-Olinda field, California, 46-15, 47-22 Breakdown pressures, 44-3, 4446, 56-l Breakthrough of free gas, 40-10 Breakthrough of gas, 40-14 Breakthrough of inert gas, 39-17 Breakthrough of polymer, 44-40
Breakthrough of water, 40-18, 40-19, 44-4. 44-7, 44-9, 44-11, 44-12, 44-14, 44-15, 44-34 Breakthrough sweep efficiency, 44-15, 44-16, 44-25 Breast mooring system, 18-2 Breathing losses in tanks. I l-12, 1 J-13 Breccia, 29-8 Bridge plugs, 55-9 Bridging in flow channels, 54-l 1 Brightness of emulsions, 19-5 Brine displacement of product method of solution mining, 11-13, 11-14 Brine/oil ratios, 47-14 Brine salinity, 47-3 to 47-5, 47-10, 47-l 1, 47-13, 47-21 Brinnell hardness. 2-2, 2-37, 9-5 British Commonwealth countries, l-69 British imperial gallon, l-69, l-70 British system of weights and measures, l-69, l-70 Bromide, 19-10, 24-9, 24-12, 24-18, 24-20 Bromine, 24-5, 24-20, 24-21 Brownscombe-Collins method of water-drive predictions, 38-9 Bubble flow, 34-36 to 34-39 Bubble Reynolds number, 34-38, 34-39 Bubble rise coefficient, 34-38, 34-39 Bubble rise velocity, 34-38, 34-39 Bubble size range of foams, 47-8 Bubblepoint c&e, 20-2 Bubblepoint equation, constants for, 22-8 Bubblepoint liquid, definition, 22-21 Bubblepoint of a system, definition, 22-20 Bubblepoint of crude, 6-21 Bubblepoint pressure, 6-39, 22-1, 22-5 to 22-9, 22-11, 22-12, 22-21, 23-3, 23-11, 24-12, 24-14, 24-15, 34-31, 34-33, 34-34, 35-2, 37-1, 37-3, 37-5, 37-6, 37-8 to 37-10, 37-15, 37-22, 39-6, 40-6, 40-7, 40-10 to 40-13, 40-19, 44-5 Bubblepoint pressure correlations, accuracy, 22-8 empirical, 21-9, 21-10 Lasater, 22-5 to 22-7 Standing, 22-5 Vasquez and Beggs, 22-7, 22-8 Bubblepoint pressure factor, 22-7 Bubblepoint viscosity, 22-16 Buckley-Leverett calculations, 48- 1 Buckley-Leverett equation, 28-3 Buckley-Leverett frontal-drive method, 40-13 Buckling, of ice, 18-39 of pipe, 18-37 of tubing string, 4-9, 4-10 Buildup curve, 30-9 to 30-13, 30-15 Buildup test, 354, 35-14 to 35-16, 35-19 Bulk density, 50-l to 50-4. 50-7, 50-8, 50-17, 50-26 to 50-28, 50-30, 50-33, 51-14, 51-37 Bulk modulus, 6-55, 51-1, 51-2, 51-4, 51-14, 51-43, 51-44, 51-49 Bulk pore compressibilities, 51-43 Bulk volume (BV), 26-l to 26-7, 26-22. 27-1, 37-11 Bumper subs, 18-13, 18-14, 18-18 Bundle of capillary tubes model, 28-12 Buoyancy effect, 2-2, 13-51, 18-2, 18-15 to 18-17, 18-24, 18-25, 18-29, 18-37, 18-49, 24-2 Buoyancy, effect on water-drive recovery, 40-20 Buoyancy method of gravity measurements, 52-19, 52-20 Burbank unit, Oklahoma, 44-4 I
70
PETROLEUM
Bureau
of Land
Management,
Buried
bar with
shale
Burners
for
of tank
57-12
drape.
53-12.
emulsion-treating
53-13
equtpment,
as IC
engine
Butterfly
charts,
Butterfly
diagram,
Butterfly
valve,
of upright
13-58 casing
2-7.
2-19.
24-19
2-9.
and coupling,
2-11.
2-13,
2-29
to 2-31.
2-57
thread
profile,
2-38
2-15,
Bypass
valve.
50-20. 6-5,
18-3,
19-2,
19-5,
24-7,
24-8,
24-20,
27-4,
27-5,
29-2,
40-23, 46-3,
46-16.
46-18.
46-19,
46-35.
47-22.
58-20
California
condensate
California
otl systems,
Californium.
Cable
field,
Venezuela,
junction
Cable-tool Cable
cores,
tray,
Cabled
box.
26-20,
Caliper
transmission
Cablmg
systems Lake
Cadiz.
58.20
for
field,
Cadmium.
SCADA,
Caisson
tutus,
52-9, 19-5,
18-40
Calcium
acetate,
Calcium
aluminate
Calcium
carbide
Calcium
carbonate.
51-6
52-l
194..
51-46
53-16.
and tubing
chloride,
Calctum
citrate
Calcium
fluorides,
Calcium
formate,
Calcium
magnesium
Calcium
scale.
Calcium
sulfate,
Calculated
8-9, 54-4,
46-4
Calvin
field.
53-5
54-2
4444
methods.
30-7,
30-S
surveys,
to 53-7
Calculation
of relative
automated lnstitut
permeabihty,
centrifuge
Fran&
Calculation
procedure,
method.
37-23
Calculation equations.
jet
programming
and Berry
12-10,
12-39,
24-20,
21-9.
27-20,
46.18,
6-42
6-46
and return
flw,
6-42.
6-44,
6-46
18-2,
18-3,
24-8,
24-l
33-5,
46.21,
sizing
prime
for
sucker
rods.
movers,
IO-17
to IO-19
Calculattons:
problems
programs,
for HP-4 Calibrate
O-2 to 9-4
see also example I C.
I,
52-12,
Calibration,
49. I8
of barges.
of bellows
meter.
of bottomhole of capacity
13-36
gauges,
30-2,
standard,
of conventional of dipmeter
17-3
acoustic
tool,
30-3.
logs,
of horizontal
17-3
of standard
tanks. lop.
18-3
29-7
of a process,
13-50
IO-35
probes,
16-7,
16-2,
of orifice
well
Capacities
of spherical
Capacitive
reactance,
Capacitive
transducer,
16-8,
testers.
13-38
12-21
to
separators,
12-25
30-5,
IO-32
for
12-30
to
30-6
to IO-35
separators,
45-10.
12-27
to
44-8
table,
l-73
of a process,
t;f API
bolted
of API
shop-welded
steel tanks,
standard
Capillary
desaturetion
of mass.
I-70
oil
47-9,
forces,
Capillary
imbibition,
Capillary
number,
Capillary
pressure.
28-3
37-l
46.13.
47-9
48-4 47-9,
47-17
as threshold
pressure.
2X-6
floods.
CO2
in acidizing,
of data,
26-25
to reservoir
CO,
injection,
26-24.
26-26.
26-23,
on unit
26-25
28-5
26-27.
dtsplacement
28.3 efficiency,
52-Y
to 25.15.
54-8
48-2,
system, required
displacemen;, miscible
48-8
system,
CO,
density
to 54-10
48-7,
CO$k,k,,
23-13
23-9 23-9 for
miscible
45-6
process,
system,
Carbon/oxygen
45-5,
25-3,
ratio:
Carbon
steel pipe,
Carbon
steel,
see C/O
I l-2,
banks
reservoirs.
15.10,
15-12
21-3,
or shoals.
reefs,
25-15 ratio
of materials.
ratto,
Carbonate
45.6
25-14.
properties
Carbonate bioherm
23.10
23-9
system.
12.41
2 1-5
36-5.
36.6
36-5
reefs,
36-5
deposits.
carbonates,
36-6 36-6
46-27
29-8 rocks,
laboratory
26-6,
acid.
measurement
(COS),
14-22 cellulose
47-3
cycle.
14-10
gas viscosny, Carried
interest,
Carrter
fluid,
Carthage
method
20-9, 41-1,
20-10. 41-2.
for
natural
20-15.
20-16
57-10
56-8
field.
Carved-out
of
26-7
9-8
(CMHEC),
Cartridge
to 26-27 conditions,
to 52-7,
19-28
Cartography,
converting
systems.
Carr-Kobayashi-Burrows
I, 44-31,
44-43, 46-22.
25-13
Carboxymethylhydroxyethyl (CDC),
44-42, 46-12,
52-4
25-8.
system,
CO,
Carnot
Captllary
43-2. 45-9.
26-18. 39-14.
19-28
Carbonylsulfide
curve
39-6,
25-20
Carbonic
I-71
23-12,
24-17.
52-16
25-5,
porosity.
58-31
14-17. 19-31.
23-7,
39-5,
to 48-11,
52.13,
analyzer,
Carbonate
I l-5
58-30,
of.
discontinmty,
43-6
42-2.
content,
14-13,
24-16,
to 45-6.
steamflood.
I l-7
Capillary
effect
40-22,
types.
I l-3
tanks.
, 58-25,
Capactty.
definition, 17-3
39-2,
shelf
13-5 1
requirement,
curves.
49-18
and spheroids.
13-l
37-24,
nearshelf
45-12
curve.
equivalents,
24-5.
4-4,
9-9.
19-29,
22-17,
28-10,
biostrome
Capacity-dtstribution
22-5,
48-5
9-8,
14-3.
24-4,
50-22
to 3-37,
15-29.
23-13,
45-4
50-22
50-4.
9-5,
12-X.
20-6.
I,
3-35
8-9,
Carbon-to-hydrogen
12-32 distribution,
(CO,).
20-5,
COJwater
IO-35
10-25,
50-3,
12-3,
CO,
to
IO-34
converter.
57-8
rays,
to 14-22,
CO,
I
50-l
14-20
CO, ot separators.
venting
26-20 26.19,
57. I 1
a well,
6-62,
COhrouane
13-44 Capacities
curves
26-10,
network,
57-l
CO,/methane/decane
19-31
averaging
equipment,
of induction
5 l-17
53-8
of gas measurement
of spheres
30-5
l-7 I
6-4,
COJcrude
18-3
Sea,
Capacitance
Capacities
flow
section,
dioxide
10-16,
47-10
22-17
tails,
gamma
44-40,
51-1,
kilovars.
of eqmpment
Calculations
Islands,
20-6.
Capacity,
6-45
for
Capture
53-17
Capacitance
Capacity
worksheets,
Calculator
rock,
Capacity
646 considerations.
Calculations
Beaufon
Capacity nozzle,
considerations.
cross
COJdecane Arctic
26-25,
47-5 of,
definition,
to 52-11.
24-19.
Capacitors,
pump. through
to drill
Capture
40-33 24-6,
Capacitor
and supplemental
performance
6-43.
28-7
to 37-26
flow
Capital
53-17,
12-32
28-7
method,
Jacoby
sequence
power-fluid
sizing
technique,
du Petrole
gains.
39-16,
19-2.
16-12,
directional
expenditure.
53-16
18.30,
Canadian
for
Capital
46-28,
46-4.
26-22,
bundle
Capital
45-1,
Illinois.
l-70.
Capacitance 44-45 pressure.
tubes
58-28
Canadian Cap
54-3
bottomhole
Calculation
56-5
44-44,
Capillary
53-16
18.38. 46-3.
54-7
carbonate,
tubes.
to 53-18
value,
Caltex,
4444,
54-2
precipitation,
tube concepts,
Capillary
4-5,
58-22
Calcium
Capillary
53-17
inspection,
of recording.
53-16
from,
446
Carbon
and application,
44-45
pump
51-24,
51-45,
53-l.
I
24-2,
51-38,
introduction,
46. I9
leg tests,
20-17
49-34,
51-23,
interpretation
Canada,
54-3 cement,
20-13.
49-1,
configuratton.
methods
to 26-27 based on.
26-26
saturation
27-8,
2 l-12
equation,
51-19,
51-33.
Calorific
49-37
52-21
5L-5.
58-38
water
logs.
types.
analysis.
Calcimeter, Calcite.
island,
18-41
wzllsite
data,
standards.
53-18
50-15 production
saturation
to 46-25,
49-39
51-16.
for casing
16-9 18-l
26-24
calculation
26-20
49-38,
borehole
17-4
Louisiana.
Caisson-retained CAL
system,
measurements. permeability
tests. 44-4 to
22-5
and surveys,
log,
51-26,
26-2 1
1846
Caddo
curve
Caliper
34-45,
46-14
46-22
40-14
4410
28-8
26-30,
44-37,
46-4.
systems,
and Davis
49-35,
24-13
7-13
34-41,
22-17.
40-17,
relative
21-7,
26-23,
41-5,
to
50-35
Calingeart Caliper
Cabimas
29-8.
4440,
18-l
21-4,
26-19,
40-22,
C
gradient,
17-2.
21-2,
44-39,
13-59
17-3
HANDBOOK
28-7
22-16,
laboratory
6-59,
40-15,
2-63,
forces,
50-29
6-24,
2-l.
to 2-61,
17-3
tanks.
2-17,
2-64 Buttress
end effect,
method,
cylindrical
California.
IO-16
49-28
Buttress-thread 2-5,
fuel,
17-3
liquid
standards,
19-28 Butane
cars.
of tanks,
ENGINEERING
Texas,
39-3
58-5 filters,
15-20,
production
Case
cup thermometer,
Case
histories
44-47 payment,
of gravity
Lakeview
pool,
40- 15
Oklahoma
Cny
Wtlcox
4 I- 1
17-I drainage,
reservoir,
40-15
SUBJECT
INDEX
Case histories. thermal recovery. Fireflood projects, Asphalt Ridge, 46-30. 46-31. 46-33. 46-34 combination reverse/forward combustion, 46-30, 46-31. 46-33. 46-34 deepest. 46-28 to 46-30 Forest Hill, 46-3 I, 46-34 Gioriana, 46-29 10 46-32 largest, 46-28, 46-29 oxygen-enriched air, 46-3 I, 46-34 Sloss. 46-30. 46-33 Suplacu de Barcau. 46-15. 46-28, 46-29 thinnest producing reservoir. 46-29 to 46-3 1 West Heidelberg, 46-28 to 46-30 wet combustion, tertiary recovery, 46-30. 46-33 Steamflood projects, Brea, 46-24. 46-25 carbonate reservoir, 46-27 to 46-29 distillation drive. 46-24. 46-2.5 fracture-assisted. 46-26 to 46-28 gas-cap reservoir. 46-24 to 46-26 Kern Rover, 46-23, 46-24 Lacq Sup&ieur, 46-27 to 46-29 largest. 46-23. 46-24 Slocum, 46-26. 46-27 Smackover, 46-24 to 46-26 Street Ranch. 46-26 to 46-28 watersand reservoir, 46-26. 46-27 Cased-hole completions, 56-9 Cased-hole evaluation, 5 l-42. 5 1-43 Cased-hole logging. 50-I Cash contributions to drilling well. 57-9 Cash flow, multiwell template effect on. IS-32 Cash-flow prqjection preparation. 41-3. 41-4 Casing anchor. 8-9 Casing and tubing inspection by caliper logs. 53-17. 53-18 Casing and tubing leaks, 33-21, 33-22 Casing, API liners. 2-1, 2-2 API types, 2-l axial stress on, 2-20 to 2-28, 2-32, 2-35 centralizers, location of, 53-17 collapse, 53-18. 56-3 collapse pressure. 2-l IO 2-3, 2-20 to 2-28. 2-32. 2-34. 2-35. 2-46. 2-55. 2-56, 18-20 collapse pressure under axial-tension stress, 2-55 collapse resistance. 2-l to 2-4, 2-6, 2-8, 2-10, 2-12, 2-14. 2-16. 2-18. 2-32. 2-46. 2-55. 2-56 collapse resistance under axial load, 2-20 to 2-28, 2-34, 2-35 collar-locator log, 53-26 combination strings. 2-2 to 2-4 design of strings. 2-1, 2-2 dimensions, 2-28. 2-29, 2-57 to 2-59. 2-63. 2-64. 2-66 elongation, 2-2 equations for calculating performance properties, 2-46. 2-54 to 2-56 extreme-line, 2-l. 2-4, 2-6, 2-8, 2-10. 2-12. 2-14. 2-16. 2-18. 2-29 to 2-31. 2-62 to 2-64. 2-67, 2-68 extreme-line joint, 2-5. 2-7. 2-9, 2-l 1. 2-13. 2-15, 2-17. 2-19. 2-60. 2-63. 2-67 to 2-72 flow (annular) installation design, 5-37, 5-38 gross linear footage from net footage. 2-29, 2-31
hanger, S-5. 3-6. S-X. 3-l I, 3-37, 33-39 hanger bowl. 3-2, 3-6. 3-8 hanger-seal assembly, 18-20 injection-gas pressure. 5-54 internal pressure leak resistance. 2-5, 2-7, 2-Y. 2-l I, 2-13. 2-15. 2-17, 2-19. 2-57 to 2-59, 2-64 internal pressure resistance, 2-5. 2-7, 2-9, 2-11, 2-13, 2-15. 2-17. 2-19 joint strength, 2-2. 2-5, 2-7, 2-9, 2-l I, 2-13, 2-15. 2-17. 2-19, 2-60. 2-61 leak. 31-5. 31-6 long thread, 2-S. 2-7. 2-9. 2-11, 2-13, 2-15, 2-17. 2-19, Z-31. 2-58. 2-64 minimum-ID calipers, 53-18, 53-19 multiplication factor, 2-29, 2-31 non-API steel grade. 2-5, 2-7, 2-9. 2-11, 2-13, 2-15. 2-17, 2-19 non-API weight and grades. 2-4. 2-6, 2-8. 2-10 performance properties, 2-4 to 2-19 plain-end liner. 2-32 potential profile. 53-20 profile calipers, 53-18. 53-19 range lengths, 2-3 round-thread. 2-l. 2-5. 2-7, 2-9, 2-l I, 2-13, 2-1.5. 2-17. 2-19. 2-28, 2-30, 2-57, 2-58. 2-61, 2-64 round-thread height dimensions, 2-66 safety factors, 2-l to 2-3. 2-34, 2-35 short-thread. 2-5, 2-7, 2-9, 2-11. 2-13, 2-15, 2-17. 2-19, 2-29, 2-57, 2-64 single-weight string suspended in rotary mud. 2-37 sizes. F, values for. 34-25 special ,joint?. 2- 1 stress in, 2-36 stretch in. 2-35 to 2-37 tensile strength, 2-2 threads, 3-2 tolerance. 2-28. 2-29 travel time, Sl-41 weight. 2-28, 2-29 with helical glrakes, IX-21 yield strength, 2-2 Casing head\. 3-2 to 3-6. 3-8. 3-l I. 3-13, 3-37, 3-39 Casing inspection logs, caliper logs for, 53-17 electrical potential logs. 53-19 electromagnetic devices. 53-19, 53-20 introduction. 53-l. 53-17 Casing/tubing annulus, 3-8 Casinghead bowl. 3-5 to 3-7 Casinghead flange, 3-5, 3-6, 3-8 Casinghead gas, definition. 40-3. 57-5 Cast-iron pipe. 15-10 Cat Canyon field, California, 46-34 Catalyst poisoning. 56-2 Catalyst selection, guidelines, 15-30 Catalysts, 24-5 Catalytic combustion detector (CCD), 52-3 to 52-5, 52-l I Catalytic converters. 15-16 Catalytic ignition systems. 46-20 Catenary mooring configuration, 18-10, 18-16 Cathodic protection, 3-36. I l-6, 15-10, 18-29, 1X-33. 18-34. 53-19, 53-20 Canon exchange, 24-20, 47-20. 47-21 Cation exchange capacity (CEC), 50-15. 52-2 I Cationics. 47-7 Cations. 24-9. 24-19, 4445 Cations conversions. 49-4 Caustic Roodmg. 19-28. 44-40, 48-5, 48-7 Caustic soda. 14-22
Cavern storage application. ESP, 7-l. 7-2 Cavmgs. 33-2 1 Cavitation, 6-32 to 6-36, 6-41 to 6-43, 6-45, 6-46, 6-50. 6-60 Cavitation area, 6-37 Cavitation correction, 6-38 Cavity pumps. 19-5 Cellophane diaphragm, 26-24 Cellulose derivative thickener, 55-5. 55-6 Celsius scale. 58-5, 58-39 Celsius temperature, umt and definitmn. 58-7, 5X-10 Cement bond, 35-4, 56-4 Cement bond logging, 51-40 Cement bond quality; bond to casing and to high velocity formation. 5 l-40. 51-4 I bonding conditions summary. 5 l-42 free pipe. 5 I-40 good bond to casing and formation, 51-40 partial bonding, 5 I-41 Cement evaluation log. 5 l-42 Cement Evaluation Tool. 5 I-4 I Cement lining for steel pipe, IS-IO Cement sheath, 51-40. 51-41 Cement slurry, 56-4 Cementation, 26-2. 40-8. 40- 1 I, 5% I Cementation factor, 26-29 Central America, 25 18. 58-20 Central battery systems, 6-60, 6-62. 32-7 Centralized control room, 18-46 Centrifugal compressor. 14-8 Centrifugal compressor efficiencies, 14-9 Centrifugal force, 6-63. 12-7. 12-8. 12.10, 12-13, 12-14, 12-19. 12-20. 13-45. 14-3. 19-6, 19-15 Centrifugal gas scrubbers, 12-20, 12-21 Cenlrifugal (elbow) meters. 13-45, 13-49 Centrifugal pump. 6-l. 6-34. 6-49, 6-S I, 6-62. 7-2. 7-3. 15-15, 15.17. 19-S. 44-42. 4447 Centrifugal separator. 12-20 Centrifuge extraction method. 26-22 Centrifuge method for determining water and sediment in ml, 17-1, 17-5 Centrifuge method of capillary pressure measurement, 26-24. 26-25 Centrifuge technique for determining relative permeability. 28-7. 28. Il. 28-12 Centrifuges, 15-20, 19-6, 26-22 Cenlripetal flow, 12-20 Cerveza platform. 18-2. 18-23 Chain drives, lo-12 Chain rule for derivatives. 37. I3 Chaining, 19-13 Chamber installations. gas lift. 5-19, 5-50 to 5-52 Chamber length equation, 5-51, 5-52 Chamber operating gas lift valves. 5-51 Channel cut and fll. S3-12. 53-13 Channeling, m acidizing, 54-8, 54-10 in cement bonding, 51-41 in emulsion treater, 19-23 in glass wool packing, 19-14 of injection water, 44-3 Channels. permeability of, 26-15. 26-16 Chanslor-Western Oil and Development Co., 46-15, 46-19 Chapel Hill field, Texas, 39-3, 39-20 to 39-22 Characteristics of well fluids. 12-3, 12-21 Characterization factor, 21-3 to 21-l I. 21.13, 21.14. 21.21. 39-l 1 Characterization of the reservoir. engineering, 36-6 to 36-8 geology, 36-3 to 56-6 geophysics, 36-8, 36-9
PETROLEUM
Charge pump, 6-62 Charged particle accelerators, SO-6 Charles’ law, 20-1, 20-Z Charpy impact values, 18-21 Charpy tests, 12-41 Charpy V-notch impact requirements, 3-38 Chart Rcor- I, 49-21 Chart Rcor-2, 49-21, 49-24 Chart Rcor-4, 49-18 Charts used in BHP gauges, 30-2 Chase water, 47-2, 47-11 Chatter condition, 5-16 Cheater bars, 9-10 Checklist, deck and subsea BOP testing, 18-12 Chelating agents, 44-45 Chemical absorption, 48-2 Chemical alteration of formation, 51-20 Chemical analyses, interpretation of, 24-18 Chemical analyses of produced waters, 24-2 Chemical analysis, 21-1, 21-2 Chemical and mechanical properties of plastic sucker rods, 9-l 1 Chemical corrosion inhibitor, 8-9 Chemical degradation, 47-5, 47-22, 48-2 Chemical demulsifiers, 19-9 to 19-12, 19-32 Chemical destabilization, 19-7, 19-8 Chemical diffusion. 28-13 Chemical distributor for flowlines, 19-11 Chemical flood model, 48-4, 48-5, 48-7 Chemical flooding, chemical agent numerical dispersion, 48-10 high-pH processes, 47-18 to 47-22 improved (enhanced) recovery, 40-4, 48-2 introduction, 47-1 low-IFT processes, 47-9 to 47-18 mobility control processes, 47-1 to 47-9 production, 46-3 ieferences, 47-24 to 47-26 summary, 47-22, 47-23 Chemical jnhibitors, 3-35, 6-55, 44-42 Chemical injection valves, 3-35 Chemical kinetics, 46-12, 46-13, 46-37 Chemical potential, 25-6, 25-9 Chemical potential sink, 47-1.5 Chemical properties of oilfield waters, 24-5 Chemical reaction kinetics, 46-1 I, 46-12 Chemical reservoirs, 29-6, 29-8 Chemical scavengers, 15-29 Chemical stain kit, 52-9 Chemical stoichiometry, 46-12 Chemicals in oil and gas separation, 12-7. 12-13 Chevron, 46-14, 46-15, 46-18, 47-22 Chevron Oil Field Research Co., 5149 Chevron packing, 18-15 Chew and Connally method, 22-14, 22-15 Chile, 58-20 Chiller, 14-8 to 14-10 China, People’s Republic of, 12-39 Chloride stress cracking, 3-35, 3-36 Chloride test, 27-l Chlorides, 24-9, 24-18, 44-44 Chlorine, 44-43, 46-20, 50-3, 50-4. 50-11. 50-12, 50-18, 50-21, 50-34 Choke capacity chart, 5-8 Choke-control operation, 5-41 to 5-44 Choke nipple, 13-56 Choke performance curve, 34-46, 34-50 Christmas-tree assembly, 3-8 to 3-l 1, 3-13, 3-17, 3-39 Christmas-tree tittings, 3-13 Christmas trees, offshore, 18-3, 18-28, 18-31, 18-32, 18-34, 18-37, 18-38 Chromatogram interpretation, 52-16
Chromatograph/thermaI conductivity detector, 52-6 Chromatography, 39-6 Chromic acid, 11-6 Chromium, 9-5 Circuit breakers, 10-28, lo-30 Circular conduits, fluid flow in, 26-10 Circular drainage area, 35-6 Circular flotation chamber, 15-27 Circumferences of circles by eighths, table, l-28, 1-29 Circumferences of circles by hundredths, table, l-24, 1-25 Circumferential bond image, 51-42 Circumferential displacement, 9-9, 9-10 Cities Service, 46-14, 46-15, 46-18, 46-20, 46-2 1 Citric acid as sequestering agent, 44-45, 54-7 Clamp-type connectors, 3-2, 3-5 Clamp-type permeameter, 26-18 Clamp-type riser coupling, 18-15 Clapeyron equation, 20-12, 20-13 Clarification of water produced with emulsions, 19-28 Classification of oil and gas separators by, application, 12-17 to 12-19 configuration. 12-16 function, 12-16 operating pressure, 12-16, 12-17 principle used to accomplish primary separation, 12-19, 12-20 Classifications, of hazardous areas, 10.36, lo-37 of insulation for motors, lo-26 of material balance equation, 40-7 of NEMA, for control enclosures, lo-27 of production packers, 4-1 of reservoir rocks, 29-6 to 29-8 of surfactants. 47-7 Clastic porosity, 29-8 Clastic reservoirs, 36-3, 36-4 Clastic rocks, 29-7 Clastic sedimentary deposits, 29-4 Clastic sediments, 36-3 Clathrates, 14-2 Clausius-Clapeyron equation, 20-12, 20-16, 20-17, 46-13 Clay control, 56-5, 56-6 Clay hydration, 51-19 Clay minerals, 44-2, 50-37 Clay stabilization, 56-3 Clay types, identification and quantification, 50-2 Clay yield, 58-29 Clean-sand points, 50-34 Cleaning vessels, 12-42, 19-28, 19-29 Cleanup, remedial, abrasive jet cleaning, 56-l large-volume injection treatments, 56-2 mud removal, 56-l paraffin removal, 56-2 reperforation, 56- 1 scale deposits, 56-2 steam injection, 56-2 water blocks and emulsions, 56-2 Clearance volume, definition of. 6-21 Climatological data, 31-2, 31-3 Closed aas lift installation, 5-2, 5-3 Closed linear system, 38-9 Closed-loop control, 16-2 Closed power-fluid system, 6-4, 6-5, 6-25 to 6-28, 6-30, 6-55. 6-59, 6-60, 6-63 Closed radial system, 38-9 Closed regeneration system, 14-l 1, 14-12 Closed, rotative, gas-lift system, 5-l to 5-3, 5-11, 5-24. 5-38
ENGINEERING
HANDBOOK
Closure, 29-3, 29-8 Closure stress, 55-8 CLUSTER log analysis, 49-37 CO&O ratio in produced gas. 46-16 Coal caving, 52-19 Coal tar coating, I l-5 Coal tar epoxy internal coatings, 6-62 Coal-tar-epoxy system, 15- 10 Coalescence, 12-8, 12-10. 12-11, 12-19, 12-35, 15-22, 15-23, 19-1, 19-3 to 19-7, 19-9, 19-12 to 19-15, 19-17, 19-19. 19-21, 19-23, 19-25, 19-26, 19-28 Coalescing material, 19-14 Coalescing packs, 12-10 Coalescing-type mist extractor, 12-8, 12-l 1 Coanda effect, 12-20 Coastal interdeltaic environment, 36-3 Coatings, corrosion prevention, 18.29. 18-33, 18-34 Coatings for bolted tanks, 11-l Coatings, protective, 3-36 Code authorities for various countries, 12-39 Code vectorization, 48-17 Codes and regulatory authorities, 18-44 Coefficient, of adsorption, 51-4 of compressional wave attenuation, 5 1-4 of expansion, 26-20 of isothermal compressibility, 20-l 1, 20-16 of shear wave attenuation, 5 l-4 of thermal expansion, 58-34 Coefficients, for choke nipple, 34-45 interaction, 28-3 transport, 28-1, 28-3 COFCAW pilot or process. 46-2. 46-14, 46-33 Cogeneration of steam and electricity, 46-19 Cognac platform, 18-2, 18-23 Coherence, definition and usage SI metric, 58-8, 58-9, 58-22 Co-injection of gas and steam, 46-22, 46-23 Coke, 19-29, 46-12, 46-21 Cold drawn steel, 9-2 Cold electric grid, 19-25 Cold environment, 18-21 Cold Lake field, Alberta, Canada, 46-4. 46-34 Cold oil productivity, 46-10, 46-l 1 Cold-separation unii, 12-1 Collapse equation factors, 2-54 to 2-56 Collabse pressure equations, 2-46 Collapse pressure, of casing, 2-l to 2-3, 2-20 to 2-28, 2-32, 2-34, 2-35, 2-46, 2-55, 2-56 of line pipe, 2-48, 2-49 of tubing, 2-39, 2-41, 2-43, 246 Collapse pressure under axial load, 2-32 Collapse pressure under axial-tension stress, 2-55 Collapse resistance, of casing, 2-1 to 2-4, 2-6, 2-8, 2-10, 2-12, 2-14, 2-16, 2-18, 2-32, 2-46, 2-55, 2-56 of line pipe, 248 of tubing, 2-39, 241, 243, 246 Collapse resistance under axial load, casing, 2-20 to 2-28, 2-34, 2-35 Collapse safety factor, 2-l to 2-3, 2-32, 2-34, 2-35, 2-39, 2-45, 2-46 Collar locator, 53-26 Colombia, 21-2, 46-3, 58-20 Color of emulsions, 19-5, 19-6 Colorado, 24-8, 24-l 1, 24-20, 40-23 Colorado School of Mines, 25-9, 25- 11 Column-stabilized drilling vessel, 18-2 Combination casing strings, safety factors, collapse, 2-2, 2-3, 2-34
SUBJECT INDEX
internal yield, 2-32, 2-34 joint strength, 2-32, 2-34 pipe-body yield strength, 2-32, 2-34 Combination drive reservoirs, 43-16, 45-8 Combination recovery procedures, 39-24 Combination reverse/forward combustion, 46-30, 46-31, 46-33, 46-34 Combination thermal and epithermal neutron device, 50-37 Combination traps, 29-5 Combination valve operators, 16-3 Combustible-gas detectors, 1847 Combustion efficiency, 19-28 Combustion, in-situ, dry forward, 46-1, 46-2 production by, 46-4 reverse, 46-2 wet, 462, 46-3 Combustion of coke, 46-12 Combustion tubes, 46-13, 46-15, 46-19 Comlith log analysis, 49-37 Common fractions of an in. to mm, table, 1-72 Common logarithms, table, 1-38 to 1-41 Common subsurface point, 53- I5 Common surface point, 53-15, 53-16 Communication adapter, 16-8 to 16-10 Communication facilities for SCADA, 16-9, 16-10 Compaction, 55-I Compaction correction factor, 5 l-33 Compaction disequilibrium, 52-21, 52-22 Compaction, effect on porosity, 26-7 Compaction of porous rocks, 26-7 to 26-10 Comparison of fluid saturation measurement methods. averaging capillary-pressure data, 26-25 to 26-27 converting laboratory data, 26-25 introduction, 26-24, 26-25 water saturation from capillary-pressure data. 26-25 Comparison of predicted vs. actual reservoir performance, 37-25, 37-26 Comparison of project execution formats, 15-32 Comparison of separators, 12-21 Comparison of Tamer’s and Tracy’s method, 37-10 Compatibility of coatings, 11-4 Compatibility tests, 19-10 Compensated density device, 50-17 Compensated Formation Density (FDP), 49-23, 49-24, 49-36, 49-38 Compensated formation density log, 46-21 Compensated Neutron Log (CNLTM),49-36. 49-38, SO-29 Complementary error function, 46-8 Complementary metal-oxide silicon (CMOS), 16-9 Completion costs, 41-9 Completion factor, 40-27 Completion flow efficiency, 37-21 Completion intervals in firefloods and steamfloods, 46-17 Completion string inspection, 53-17 Completion/workover system controls, 1B-48 Complex propagation factor, 49-33 Complexing agent, 56-3 Component parts of a pumping unit, 10-4, IO-5 Composite reservoir, 35-7 Composition of oiltield waters, Appalachian area, 24-6, 24-7 California, 24-7, 24-8 Canada, 24-8, 24-12
23
Illinois basin. 24-7, 24-9 midcontinent area, 24-8 to 24-10 Rocky Mountain area, 24-8. 24-1 I U.S. Gulf Coast, 24-7, 24-8 Venezuela, 24-9, 24-13 Composition of produced stream, GC system, 39-14 Composition ranges, GC systems, 39-2 Compositional analysis, 17-7 Compositional-balance equation, 43-6 Compositional material balance, 39-8 Compositional model, 43-2, 484, 48-6, 48-7, 48-9, 48-14 Compositional simulator, 36-10, 45-10, 45-13 Compound interest, 41-25 Compound interest factor, 41-17 Compound interest, table, l-62, l-63 Compound units, Sl metric system, 58-12 to 58-14 Compressed air, 3-3 1 Compressed vapor recovery unit, 11-13 Compressibility factor, of ethylene, 17-7 of gas. 20-4, 20-7, 20-8, 20-10, 20-l 1, 20-14, 34-28, 40-22 of injected dry gas, 39-24 of natural gas, 5-4. 20-5, 20-6, 40-21 of nitrogen, 39-16 of pure compounds, 20-5 Compressibility factor charts, 20-5, 20-6, 40-2 1 Compressibility of CO*, 45-5 Compressibility of formation. 40-7 Compressibility of formation water, 24-12, 24-15 Compressibility of gas. 51-37 Compressibility of hydrocarbon liquids, 22-3, 22-5 Compressibility of natural gas mixtures, 17-7 Compressibility of oil, 40-7 Compressibility of pore fluid, 51-30. 51-31, 51-37 Compressibility of porous rocks, 26-7 to 26-10 Compressibility of reservoir fluid, 58-38 Compressibility tests, 51-44 Compressibility, total, 35-2 Compression, 39-27 Compression loading, 9-13 Compression packer, 4-2 to 4-4, 4-8 Compression plant, 39- 17, 39-24 Compression ratio, 6-10, 6-21, 8-9, 8-10, 10-15. 18-14, 39-24 Compression refrigeration system, 14-9 Compression stress in pipe, 2-35 Compression stroke, lo-14 Compression system. 1 l-13 Compression-type seal, 3-6 Compressional energy, 34-28, 34-29, 39-40 Compressional forces, 29-2, 29-3 Compressional transit time curves, 5 l-29 Compressional-wave attenuations, 51-2, 51-6 Compressional-wave transit time, 51-19, 51-24 to 51-27, 51-29 to 51-31, 51-35 to 51-37, 51-39, 51-43 Compressional-wave velocities. 5 l-l. 5 1-2, 5’1-4 to 51-9. 51-12, 51-15, 51-20, 51-24. 51-25. 51-30. 51-34, 51-35. 51-37, 51-38. 5143 Compressional-wave velocity log, 51-28 Compressional waves, 51-2, 51-3, 51-12 to 51-15, 51-25, 51-27, 51-28, 51-30, 51-35, 51-46 Compressive load, 18-22
Compressive strength of cement, 5140, 51-42 Compressor, field booster, 13-57 Compressor fuel consumption, 39-24 Compressor-oil carry-over, 39-24 Compressor suction pressure, 13-58 Compton scattering, 50-6 to 50-8, 50-12 to 50-14, 50-16 Compton tail, 50-13, 50-14 Compulsory unit operations. 57-8 Comsand log analysis, 49-37 Concentration, definitions of, 48-5 Concentration, units and conversions, 58-29, 58-30 Conceptual studies, 15-30 Concrete dust, 1 l-5 Concrete (gravity) structures, IS-l, 18-2, 18-23, 18-25 Condensable vapors, 12-3, 12-8 Condensate content, 39-23 Condensate (distillate) liquids, 22-20, 39-23 Condensate-liquids recovery, 39-6 Condensate properties and correlations, 21-8, 21-10 to 21-16 Condensate well fluids, 20-7, 34-4 Condensates, 11-12. 12-3. 12-32. 14-1. 14-3, 14-5 to 14-8, 14-11, 14-14, 18-28, 39-10, 39-11. 40-3. 57-5 Condensing-gas drive. 45-l to 45-4, 45-l 1. 45-12 Conductance ratio, 44-34 Conduction, 46-25 Conductive cloth model, 44-20 Conductive solids, effect on electrical properties of rock, 26-30, 26-31 Conductivity, 44-33 to 44-35 Conductivity log, 51-38 Conductivity units, 49-1 Conductor casing, 18-18, 18-19 Conductor strings, 3-3 Cone-bottom tanks, I l-2, 1l-3 Configurations of separators. 12-16, 12-22, 12-31, 12-35 Confining pressure, 5 l-7 Conformance efficiency, 39-9, 43-3, 43-5 to 43-7, 43-9, 44-9, 44-32, 45-6, 45-7, 45-10, 45-13 Conformance factor, 39-18 Conformity of flood, 44-46 Congo, 46-3 Conjugate gradient, 48-17 Connate water: see also interstitial water Connate water, 24-2. 24-16, 24-18, 24-19 Connection gas indicating underbalance, 52-17, 52-18 Conoco Inc., 46-15, 46-26 Conservation, 43-l Conservation commission, 30-8 Conservation commission completion, 41-8 Conservation equations, steam injection model, energy balance, 46-12 mass balance of coke, 46-12 mass balance of H,O. 46-12 mass balance of hydrocarbons, 46-12 mass balance of inert gases, 46-12 mass balance of oxygen, 46-12 Conservation laws, 39. I6 Conservation of mass, 34- 1 Consistency index, 55-5 Consolidated rocks, porosity of, 5 l-29 to 5 I-3 1 Constant-composition expansion, 39-7 Constant-enthalpy expansion, 14-l. 14-2 Constant-enthalpy expansion system, 14-3 to 14-8 Constant-flow control valve. 6-5 I, 6-54, 6-56 Constant percentage decline, 40-28 to 40-32, 41-9, 41-10, 41-12, 41-17
PETROLEUM
24
Constant-percentage-decline deferment factor, 41-24, 41-27, 41-28 Constant-pressure controller, 6-5 1, 6-54 Constant-pressure cycling, 39-23, 39-24 Constant-rate case for DCF-ROR, 41-18, 41-22, 41-23 Constant-rate deferment factor, 4 l-24, 41-25, 41-27 to 41-29 Constant-rate income, 41-18, 41-21 Constant-rate production, 41-5, 41-I 1, 41-12 Constant ratio of net profit. 41-20 Constant surface closing, gas-lift valve. 5-44 Constant-terminal-pressure case, 38-I to 38-3 Constant-terminal-rate case. 38-l. 38-2 Constant valve surface closing pressure, 5-46, 5-47 Constant-volume gas reservoirs, 40-34 Constraint equations, 48-4 Construction codes for separators, ASME code for unfired pressure vessels, 12-38 ASME design equations for separators, 12-38 materials of construction for separators, 12-38 Construction design factor, 15-I I, 15-13 Construction materials for separator, 12-38, 12-39. 12-41 Constructton of meters, 13-37 Construction types for underground storage, 1l-13 Contact angle, 28-10 Contact log, 443 Contact resistivity devices, 26-3 1 Containers for samples, 24-4 Containment of fracture, 55-5 Contaminants of water, IS-30 Continental sediments, 36-3 Continental shelf, 29-7, 53-12, 53-14 Continental slope and abyssal environments, 53-12, 53-14 Continuity of reservoir rock, 44-3 Continuity principles. 37-2 Continuous compounding, 41-26, 41-28, 41-30, 41-35 Continuous dipmeter surveys, 53-3 Continuous-flow gas lift, bottom valve, selecting, 5-26 casing (annular) flow in&llation design, 5-37 depth of top valve, 5-24, 5-25 design procedures, 34-40 to 34-45 flowing pressure gradient curves, 5-25, 5-26 flowing temperature at depth. 5-26 installGion design. 5-22, 5-26 to 5-35 introduction, 5-2 I, 5-22 multiphase-flow correlations, 5-25, 5-26 operations, 5-24, 541 ortfice-check valve for the operating gaslift valve, 5-23, 5-24 production pressure (flurd)-operated valves. 5-35 to 5-37 safety factors in simplified installation, 5-22, 5-23 slope of static load fluid traverse. 5-25 us& gas energy fully, 5-I Continuous-flow installations, 5-21 to 5-26, 5-30. 5-31, s-34, 5-35, 5-37, 5-43 Contraction of pipe, lateral, 2-35 Control agent, gas regulation. 13-50 Control circuit logic, 3-27 Control curves, gas regulation, 13-52, 13-53 Control Data Corp. 1 48 I7 Control enclosures for motors. 10-26. IO-27 Control fluids, subsea control systems, 18-49 Control for odtield motors, IO-27 to lo-29 Control fuses for oilfield motors, IO-29
Control-head compression packer, 4-2, 4-3, 4-9 Control-head tension packer, 4-2, 4-9 Control lines in subsea completions, 18-33, IS-34 Control manifolds, 6-54 Control of field compressors, 13-57 Control of subsea production facilities, IS-48 Control system, 3-31, 3-33, 3-34 Control systems offshore, alternate approaches, 18-49, IX-50 control fluids, 18-49 direct hydraulic control. 18-50 discrete-piloted hydraulic. 18-51 drilling, 18-15. 18-16 introduction, 18-43 to 18-48 multiplexed electrohydraulic, 18-52 operational considerations, 1849 redundancy, 18-48. It-49 reliability/mamtainability, 18-48 safety systems, 18-47 sequential-piloted hydraulic, 18-51, 18-52 subsea productton facilities, IS-48 umbdtcals, 1849 Control-valve travel, 13-55 Controlled~solubility particulate solids, 54-10 Controller types, 16-3 to 16-5 Controllinginjection-pumping rate, 16-14 Controls nomenclature, 13-49, 13-50 Convection. 46-4, 46-12. 46-25 Convection heat-transfer coefficient, 46-5 Conventional acoustic logging. calibration. 51-17, 51-18 curves recorded, 5 I - 16 cycle skipping and triggermg on the noise, 51-16. 51-17 log presentation, 51-16 tool characteristics, 51-15, 51-16 tool span. 51-16 Conventional acoustic loas, 51-19, 51-20, 51-22 to 51-25, 51-35 Conventional coring procedures, 27-9 Conventional crank-balanced pumping units, 10-l to 10-4. 10-8. IO-9 Conventional gas-lift equipment, 5-2 Conventional lay barges. 1837, 1838. 18-43 Conventional (black-orI) material balance, 37-25. 37-26 Conventional mooring system. 18-4 Conventional mud logging. 52-1, 52-16 Conventional resistivity devices, 49-12, 49-25 Conventional resistivity logs. application, 49-14 Conventional steel pipe. 18-36, 18-37 Conventional tubing mandrel, 5-12 Conventional wireline cores. 27-9 Conventionally mined caverns, 1 l-13 Convergence pressure, 23-l 1 Conversion factors. for density units, table, l-79 for permeabtlity. 26-14, 58-35 Conversion factors, Sl uniti, for vara, 58-20 general, 58-14. 58-22 memory joggers, 58-21 notation, 58-14 organization. 58-14 tables of, 58-15 to 58-21 Conversion of temperature-tolerance requirements, 58-7 Conversion of units in Darcy’s law, gases ar base pressure and average tlowmg temperature. 26-13, 26-14 linear-flow liquids. 26-13 permeabtlity conversion factors. 26-14, 26-15 radial-flow liquids. 26-13 Conversion rules. 585 to 587
ENGINEERING
HANDBOOK
Conversion, tables of, angular velocity, l-76 areas, 1-74 capacities, l-74 density, 1-79 energy, l-78 heat, l-78 heat flow, l-79 lengths, I-7 1 linear velocity, l-76 masses, 1-75 power, 1-78 pressures, l-76 relative densities, l-80 thermal conductance, l-79 thermal conductivity, l-79 volumes, 1-74 work, I-78 Conveyances, tax consequences related to, 41-15, 41-16 Convolutions, 5-16 Cook Inlet, Alaska, 18-3 Cooling, creates hydrates, 14-3 cycles, 14-11 gas to condense hydrocarbon vapor, 14-5 in condensate removal, 14-1, 14-2 in gas-to-gas heat exchangers, 14-I 1 load, 14-10 with refrigerants, 14-Y Copper electrodes, 39-21 Coquinas, 29-4, 29-8 C/O ratio, 50-l to 50-4, 50-9. 50-22, 50-24, 50-35, 50-36 Core analysis and core analysis data, 24. I, 26-l, 26-7, 26-22. 26-23. 36-3, 37-3. 39-18, 40-l. 40-3. 40-5, 40.12. 40.16, 40-19. 40-25, 41-8. 424. 446, 46-21, 50-26, 50-35 to 50.37, 51.31, 51-32, 52-26 Core analysis, average values, gravity, 27-5, 27-7, 27-l 1. 27-13, 27-15. 27-17. 27-19 interstitial water saturation. 27-3. 27-5, 27-7, 27-11, 27-13, 27-15, 27-17. 27-19, 27-20 oil saturation, 27-3, 27-5.27-7. 27-9, 27-1 I, 27-13, 27.15, 27-17. 27.19, 27-20 permeability. 27-3 to 27-6. 27-8. 27-10 to 27-17, 27-19, 27-20 permeability, 27-3 to 27-6, 27-8. 27-10 to 27-17, 27-19, 27-20 porosity, 27-3. 27-5. 27-7, 27-8, 27-l 1, 27-13, 27-15, 27-17. 27-19, 27-20 total water saturation, 27-5, 27-7. 27-I 1. 27-13, 27-15. 27-17 water saturation, reservoir. 27-20 Core analysis of different formations, data from non-U.S. areas. 27-S data from U.S. areas, 27-9 liquid saturations, 27-8 percussion sidewall core data, 27-9 permeability, 27-l porosity, 27-l Core-barrel sample, 56-7 Core barrels, rubber-sleeve, 56-3, 56-6 Core-sample resistivity cell, 26-28 CORIBAND log analysis, 49-37 Coring data, 4 l-8 Coring program, core analyses, 46-2 I during and after project. 46-20 log analyses. 46-2 I microscopic studies. 46-2 1 mineral analyses of cores, 46-2 1 photographic and visual examination. 46-2 1 tracers, 46-2 I Corner well producing cuts, 4424, 44-25
SUBJECT INDEX
Correction, of observed API gravity to API gravity at 60°F. 17-5, 17-6 of observed density to density at 15OC, 17-6 of observed relative density to relative density at 60/60°F, 17-5, 17-6 of volume to 15°C against API gravity at 60”F, 17-6 of volume to 15°C against density at WC, 17-6 of volume to 60°F against relative density at 60/60”F, 17-5, 17-6 of volume to 15°C against thermal expansion coefficients at 15”C, 17-6 of volume to 60°F against thermal expansion coefficients at 6O”F, 17-6 Correction factor, for dead-end oil IFT, 22-17 for gas flow, 33-2 for gas mixtures, 20-6 Correlation index, 21-9, 21-I 1 Correlation length, dipmeter, 53-10, 53-l 1 Correlation(s). accuracv of, 22-89, 22-9 acot& log. 5 I-30 Baker and Swerdloff, 22-17 Beal, 22-14 to 22-16 Beggs and Brill. 46-7 Beggs and Robinson, 22-15. 22-16 between AOR and WAR, 46-19 between diaphragm and dynamic capillary pressure methods, 26-25 between interstitnrl water and log of permeability, 26-23 between maximum friction pressure and maximum total flow rate, 6-19 between oil recovery and pore volume burned, 46- 17 Boberg and West, 46-11 bubblepoint pressure, 21-9. 21-10, 22-5 to 22-9 carbon/oxygen, 50-l to 50-4, 50-9, 50-22, 50-24. 50-35, 50-36 Carr-Kobayashi-Burrows, 20-9, 20-10. 20-15. 20-16 chart, 40-22 Chew and Connolly. 22-14 to 22-16, 394 Cullender and Smith. 5-37 dead-oil viscosity. 22-14 dewpoint pressure, 21-10 to 21-15 Dykstra-Parsons, 44-9 empirical, of electrical properties, 26-29 to 26-3 I empirical. ultimate recovery, 40-13 equilibrium ratios, 39-15 flow temperature gradient, 5-26, 5-27 llutd flow. 44-20, 44-21 for approximating true vapor pressure, 14-13 for liquid and gas properties, 647 formation resistivity factor, 26-29 formatton volume, 21-15 to 21-20 gamma ray log. well-to-well. 50-2 gas-plus-liquid FVF, empirical, 6-38 Gates and Ramey. 46-15 geological, 51-29, 51-30 Hall, 26-8, 26-9 Hammerlindl’s, 26-8 K-value, 39-12 Lasater, 22-5 to 22-7, 22-9, 22-10 multiphase flow, 5-22, 5-25. 5-26. 5-38, 5-40, 34-37 to 3440 Muskat’s. 39-20 of capillary pressure data, 26-26 of solubility ratios with IFT, 47-14 of steam stimulation results, 46-11 of water saturation wtth permeability, 26-27 of well logs, 49-25. 49-26
25
oil formation volume factor, 22-10 to 22-13 oil systems, 22-l to 22-21 oil viscosity, 22-13 to 22-16 Organick and Gelding. 21-I 1 to 21-15 Orkiszewski, 34-37 to 34-40 permeability with tube wave data, 51-48 petrophysical, 28-13 Poettmann and Carpenter, 34-37 porosity compressibility with depth, 26-8 predicts cavitation damage, 6-36 productivtty index-permeability, 32-4 recovery factor from statistical data, 40-16 relatmg fuel content to API gravity, 46-16 resistivity index vs. saturation, 26-3 Sage and Old. 21-1 I sand-by-sand, 36-7 Showalter. 46-16 sour water stripper, 25-17, 25-18 Standing, 22-5. 22-8 to 22-1 I, 22-13, 22-14 Thodos, 20.11. 20-16 total formation volume, 21-15 to 21-20 transit time/pressure, 5 I-40 Trube. 20-I I, 20-16 undersaturated systems, oil viscositv. 22-16 Van der Knapp,. 26-8 vapor/liquid equilibrium, GC systems. 39-1 I t0 39.i3 Vasquez and Beggs, 22-7 to 22-13 velocity/porosity. 5 l-34 vertical multiphase flowing gradient, 6-43, 6-45 viscosity of gas. 20-9 water-saturated rock conductivity vs. water conductivity, 26-30 waterflood recovery, 44-8. 4432 Correlative right. 57-2 Correlogram, dipmeter, 53-10 Corrosion, attacks, 9-l by iron sulfide deposits. 1I-IO cathodic protection, 19-3 1 caused by microbiological growth, 44-44 cell. 9-2 control procedures, 39-26 electrochemical, 3-36 in casing, tubing and cement jobs, 39-24 in dry desiccant dehydration, 14-21 in ethanolamine sweetening units, 14-22 in oil and gas separators. 12-3. 12-B. 12-40 in pipe. 14-17 in power oil plunger pumps. 6-33 in reverse flow systems, 6-5 in subsurface sucker-rod pumps, 8-9 in surface system and injection wells, 44-43 in water-injection systems, 24-2 increased with CO, increase, 44-42 minimized by internal coatings, 19-31 minimized by use of plastics, 44-47 on tank bottoms, 1 l-2 oxygen exclusion, 19-30 pits, 9-5, 9-8 to 9-10 problems. 6-55. 46-22 products, 6-48. 6-59 products carryover, 39-24 protection, 1l-l. II-3 resistant alloys, 3-36 spectal metallurgy, 19-31 Corrosion of wellhead equipment, 3-35 electrochemical. 3-36 external, 3-36 internal, 3-36 material selection, 3-36 oxygen, 3-36 weight loss, 3-36 wellhead aspects, 3-35, 3-36 Corrosion inhibitors. 3-36, 6-5, 6-55, 9-I. 9-5. 9-8, 9-10, 9-13, 19-30, 19-32, 4445. 4446, 53-18. 54-6
Corrosion rates, 4441, 4442, 58-38 Corrosive fluids in separator, 12-40 Corrosive well fluids, 4-4. 4-5 Corrugated plate interceptor (CPI), 15-24 to 15-26 Cost accounting system, 19-32 Cost and profit margin relationship, 36-2 Cost/benefit analysis, 52-30 Cost comparison, production packers, 4-6 Cost-depletion allowance. 41-5, 41-13, 41-14 Cost justification, 52-29, 52-30 Cost of emulsion treating, 19-33 Cost of engine equipment. 10-16, lo-17 Cost-plus format, 15-32 Cosurfactants, 47-5, 47-11. 47-13 Cotton Valley Bodcaw reservoir, Texas, 39-19, 39-23 Cottonwood Creek field. Wyoming, 24-18 Coulter counter. 4445
Counterbalance, 10-I to 10-3, 10-6, 10-7, IO-9 Counterflow imbibition, 28-13 Counterweight, 9-2 Counting rate, gamma ray. 50-15, 50-16, 50- 19, 50.20, 50-28 Coupling failures, 9-9 Couplings and subcouplings. sucker rods, 9-3, 94 Coverage, 40-18, 44-9 Cox chart, 20-12, 20-13. 20-17 Cracked-gas/water system, 25-26 Cracking, 46-3 Crank-balanced units, 104, IO-6 Cray-IS computer, 48-17 Creep compaction, 28-l 3 Crestal-gas injection, 40-14. 43-3 Cricondenbar, 39-3 Cricondentherm, 23-6. 39-3. 45-2. 45-4 Crnerion of reservoir performance, 32-15 Critical breakthrough pressure, 44-36 Critical constants of hydrocarbons, 20.2, 20.3 Crrtical constants of solvent gases, 45-5 Critical-flow conditions. 13-53, 34-45 to 34-49 Critical-flow prover, 13-37. 13-45, 33-6. 33-7, 33-13 Critical gas mixture, 45-4 Critical gas saturation, 28-9, 34-3 I, 37-1, 37-3, 374, 48-13 Critical hydrate formation loci, 25-3 Critical locus, 23-3. 23-4. 45-3 Critical micelle concentration (CMC), 47-10, 47-l I, 47-15 Critical point, 14-2, 20-2. 23-l. 23-2, 25-1, 39-2, 39-3, 39-15 Critical pressure, 20-2, 20-3, 20.5,40-21,443 Critical ratio for flow prover, 13-37 Critical saturation, 49-30 Critical state, detimtion, 22-20 Critical temperature. 20-2, 20-3. 20-5. 22-20, 39-1, 39-4. 40-21, 45-5 Critical thickness, 49-13 Critical volume, 20-3 Critical wells m acidizing, 54-l I, 54-12 Critique of unsteady-state k, methods, 28-7 Cross imbtbitton, 48- I3 Cross plot of photoelectric factor vs. density, 50-33 Cross rails, motor mounts, IO-19 Cross section of interactton. 50-6 Cross sections. 41-X Cross yoke, IO-2 Cross-yoke bearing, 10-3. IO-4 Crossbedding. 44-3 flow, 44-29 Crossflow, 39-19, 39-20, 447, 448, 48-10 Crossflow devices, 15-25, 15-26 Crosshead, IO-14 Crosslinked aqueous fluid. 55-6
26
Crosslinked gels, 55-5, 55-7, 55-8 Crossover flange, 3-7 10 3-9 Crossover seat, 5-16, 5-37 Crossover tool, 56-8 CRT screen display of fracturing data, 55-9 Crude-oil analysis, 2 l-7 to 21-9 Crude Oil Analysis System (COASYS), 21-9 Crude oil, API gravity loss vs. temperature, 19-9 Crude oil as semidiesel fuel, IO-16 Crude oil, definition, 12-3, 40-3 Crude oil, differences between natural gas, 362 Crude-oil disposal, 18-29, 18-30 Crude-oil emulsions, description of treatment equipment. 19-16 to 19-28 economics of treating, 19-32 general references, 19-33, 19-34 introduction, 19-I methods used in treating, 19-6 to 19-15 operational considerations for treating equipment, 19-28 to 19-32 sampling and analyzing, 19-6 theories of, 19-l to 19-6 treating equipment and systems, 19-15. 19-16 Crude oil, measuring, sampling, and testing, 17-l to 17-8 Crude-oil properties, 21-1 to 21-10 base, 21-1, 21-3 evaluation, 21-1, 21-2, 214 Crude-oil reservoirs, 39-l. 39-2 Crude oil, viscosity/temperature relationships, 19-7, 19-8 Crude oil, volume loss vs. temperature, 19-9 Crude-oil/water emulsion, 19-6 Crude oils, temperature corrections for, 17-5. 17-6 Crude price, gross, 41-9 Crude stabilization, 40-13 Crude viscosity, effect of solution gas, 6-68 Crystalline porosity, 29-8 Crystallization temperatures, 25-19 Cuba, 58-20 Cube roots of certain fractions, table, l-18 Cube roots of whole numbers, table, l-7, 1-14 to 1-18 Cubes of numbers, table, l-7 to I-10 Cubic average boiling point, 21-12, 21-15 Cubic packing of spheres, 26-1. 26-2 Cullender and Smith correlation, 5-37 Cullender and Smith method of determining BHP in gas wells, 34-24 to 34-26 Cumulative-gas/cumulative-oil curve, 40-32 Cumulative logarithmic diagram (S-plot), 56-6, 56-7 Cumulative oil production vs. GOR, 37-25 Cup-type plunger, 8-6 Current bedding, 53-12, 53-13 Current status of thermal recovery, geographical distribution of projects, 46-3 major projects, 46-3 potential for incremental recovery, 46-3 production mechanisms, 46-4 reservoirs amenable to, 46-3 U.S. oil production by EOR, 46-3 Curve shapes, 49-12, 49-13 Custody transfer, 13-48 Customary units (English), 17-7, 58-2 1, 58-26 to 58-38 Cutoffs on engine installations, lo-19 Cut-out rams, 7-12 Cut test, 52-10, 52-14, 52-16 Cuttings evaluation, 52-19 Cuttings gas, 52-17 Cuttings gas analyzer, 52-1 I Cuttings, representative sample, 52-8, 52-9, 52-11
PETROLEUM
Cuttings sample geological log, 52-l Cyberdip log analysis, 49-37 Cyberlook, pass one log, 49-37, 49-38 pass two log, 43-39 Cycle efficiency of refrigerants. 14-10 Cycle frequency, maximum, 5-40 Cycle skipping, 51-16, 51-17, 51-24, 51-45 Cycles of steam stimulation, 46-9 Cyclic load, derating factor, lO- 18 of oilwell pumping unit, lo-25 Cyclic load factor, lo-25 Cyclic steam injection, 46-21 Cyclic steam stimulation, 46-22, 48-46 Cycling operations, 39-4, 39-6, 39-15 to 39-24, 39-27 Cycling operations prediction with model studies, 39-20 to 39-22 Cycling performance, CC reservoir, areal sweep efficiency, 39-17 displacement efficiency, 39-18 effectiveness, 39-17 invasion efficiency, 39-17, 39-18 pattern (h&S-weighted) efficiency, 39-17 permeability distribution, 39-18 to 39-20 reservoir efficiency, 39- 17 Cycling to improve recovery, 40-4 Cyclohexanelwater system, 25-26 Cyclone separator (desander), 660 to 6-63, 12-20, 15-19 Cyclonic flow, 12-19 Cyclopropaneiwater system, 25-25, 25-27 Cylindrical shell equations, 12-38 Cylindrical tanks, 11-2
D Daily production rate, continuous-flow gas lift, 5-54 Daily production rates, prediction of, 5-40 Dalton’s law, 20-4, 23-11 Damage, by fluid jet, 8-7 ratio, 30-13 Damaged casing, 51-29 Damkiihler number, 47-21 Darcy head loss. 15-l Darcy’s law or equation, 26-10, 26-11, 26-13, 26-15, 26-16, 26-18, 26-19, 28-1, 28-2, 32-4, 35-10, 37-11, 39.20, 43-3, 44-9. 44-13, 44-17. 45-13, 48-2, 48-3, 56-4 Data acquisition system, 52-25, 52-27, 52-28 Data gathering and handling, 42-3 Data of varying precision, 58-6. 58-7 Data required to estimate recovery from injection operations, 42-2 Data requirements for engineering analysis of gas-injection operations, 43-17 Data requirements for GC cycling study, 39-22, 39-23 Data transmission schematic for MWD, 53-2 Date designation SI metric system, 58-22 Dead basins, 52-22 Dead-end oil IFT, 22-17 Dead-oil viscosity, 22-14, 22-15, 40-12 Dead oils, 45-5 Dead Sea, 24-19 Dead space of separator, 12-26, 12-30 Dead time of a process, 13-50 Dead-weight gauge, 33-6 Dead-weight regulator, 13-54 Dead-weight tester, 5-53, 13-37, 30-2 Dean-Stark extraction, 46-21 Debris or solids in well, ESP, 7-16, 7-17 Decay constant, exponential. 50-22 Decay times. 50-22
ENGINEERING
HANDBOOK
Decimal equivalents, table, 167 Decimal relation in SI metric system, 58-9, 58-22 Decimals of an in. to mm, table, 1-72 Deck drainage, skim pile sizing, 15-26 Decline-curve analysis, 40-27 Decline tables for constant-percentage decline, 40-28 to 40-32 Decline-trend analyses, 40-l Decreasing-injection-gas-pressure installation design method, 5-22 Deep dual laterolog (LLD), 49-19, 49-20 Deep marine sediments, 36-3 Deep Sea Drilling Project, 25-18 Deep-seated domes, 29-5, 29-6 Deepwater drilling, 18-10, 18-20, 18-21 Deerfield field, Missouri, 46-14 De-ethanizer, 14-8 Deferment-factor (weighted-average) charts, 41-23 Deferment factors, 41-5 to 41-8. 41-20, 41-21, 41-24 to 41-35 Definitions, for valuation of oil and gas reserves, 40-3, 40-4 of fluid properties, 22-l of gas/oil ratio terms, 32-14 of petroleum reserves, 40-2, 40-3 of pump parts, 8-2 of water-drive oil reservoir terms, 38-1 Defoaming plates, 12-6 Deformations of acoustic waves, 5 l-2 Degasser boot, 19-22 Degassing, 19-18 Degassing efficiency, 52-2 Degassing elements, 12-22 Degradation of an oil accumulation, 24-17 Degrees and minutes expressed in radians, table, l-42 Degrees of freedom, 25-1, 25-2 Dehydration by adsorption. 14-20, 14-2 1 Dehydration efficiency, 14- 19 Dehydration, storage tank used for. 19-18 Dehydration units, 14-17. 14-19 Dehydration with organic liquid desiccants, 14-17 to 14-20 Dehydrator, 14-10, 14-13, 14-18 Dehydrator pots, 13-53 Delaware-Childers field, Oklahoma, 463 Delaware effect, 49-11, 49-22 Delay rentals, 41-1, 41-13, 57-4, 57-5, 57-7 Deliverability of gas-lift well, 5-40 Deliverability of gas to compressor plant, 13-58 Deliverability of gas wells, 34-3, 34-9 Deliverability plot approach, 35-12 Deliverability testing, 35-10 Delta-bar sediments, 36-3 Delta-delta transformer, 10-30, 10-3 1 Delta-wye transformer, IO-30 Deltaic bar deposits, 36-4 Deltaic channel deposits, 36-4 Deltaic environment, 36-3 Demand-pressure regulator, 3-33 Demethanizer, 14-8 Demulsifiers, 17-2, 19-9 to 19-13. 56-5 Dendritic fingers. 45-7 Density, apparent liquid, definition of, 22-20 Density comparison method, 52-20 Density, definition of, l-80 Density difference (gravity separation). 12-8, 12-9, 12-19 Density equivalents, table, 1-79 Density gradient method, 52-20 Density in SI metric system, 58-24, 58-29 Density log, 44-3, 49-25, 49-26, 49-34, 49-38, 50-24, 51-14, 51-19, 51-31, 51-33, 51-43
SUBJECT INDEX
Density meters, installing and proving, 17-7 Density/neutron crossplot, 51-36 Density of crude petroleum, 17-5 Density of formation water, 24-14 Density of gaseous hydrocarbons, 20-3 Density of light hydrocarbons, 17-5 Density of liquid petroleum products, 17-5 Density of N&l solutions, 24-14 Density of natural gas, 20-14, 20-15 Density porosity, 50-31, 50-33 Density/pressure relationship, 26-12 Density, pseudoliquid, 22-2 to 224 Denton field, New Mexico, 6-24 Deoxygenating control equipment, 24-2 Dept. of Commerce, l-69 Dept. of Energy (DOE), 40-2, 46-16, 46-30, 46-31, 46-33, 46-34 Dept. of the Treasury, 41-15 Dept. of Transportation, 15-13 Departure curves, 49-7, 49-27 Depletion, 41-13, 41-16, 41-17, 47-21 to 47-24, 57-11 Depletion allowance, 41-13 to 41-15 Depletion-drive calculation, 43-13, 43-14, 43-16 Depletion-drive performance, 37-16 to 37-18 Debletion-drive process, 42-5 Depletion-drive recoveries, 37-24 Depletion equation, 37-10 Depletion mechanism, 40-8, 40-10, 40-12, ‘40-13, 40-15 Depletion performance, volatile oil reservoirs, 37-22, 37-23 Depletion-recovery factors, 40-10, 40-11 Depletion technique, dry gas reservoir, example problem, 36-3 gas reservoirs, 36-2, 36-3 oil reservoirs, 36-2 Depletion-type gas wells, 41-10 Depletion-type reservoir, 29-8, 40-8 to 40-12, 40-16, 40-32, 40-33 Depositional environment, 36-3 to 36-7 Depreciation, 41-11, 41-13, 41-21, 41-22, 57-l 1 Depression of metnstable dewpoint, 25-12, 25-14 Depth micrometer, 5-16 Depth of top gas-lift valve, 5-24 Depthoaraph, 30-7 Debating factors of motor, 10-24, 10-25, 10-31 Derivation of an orifice equation, 13-2, 13-3 Derivative response, 13-50, 13-52, 13-53 Derived units, SI metric system, l-69, l-71, 58-2. 584, 58-10, 58-11, 58-21 Derrick barges, 18-26 Desalting crude oil, 19-26, 19-27 Description needed for oilfield water sample, 24-5 Design engineering, 15-3 1 Design features, common to steamfloods and tirefloods, 46-17 pertaining to tirefloods only, 46-18, 46-19 pertaining to steamfloods only, 46-18 Design methods, intermittent gas lift, 542 Design of casing strings, oil, water, and mud-weight factors, 2-1 safety factor, 2-l to 2-3, 2-34, 2-35 single-weight and -grade casing string, 2-1, 2-2 Design of gas-lift installation, 5-32 to 5-35 Design of hydraulic fracturing treatment, 55-9, 55-10 Design operating gas-lift valve depth, 5-54 Design properties for piping, 15-l 1 Design safety factors for casing, 2-l to 2-3, 2-32, 2-34, 2-35 Design slip of motor, IO-24
Design standards of electric motors, 10-19, IO-20 Destabilization of emulsions. 19-6, 19-7 Desulfurization unit, 14-21, 14-22 Det norske Veritas, 1844 Detail engineering, 15-31 Detection efficiency, 50-12 to 50-14 Detection of nonhydrocarbon gases, 52-5 to 52-7 Detector resolution, 50-14 Deterministic analysis, 18-27, 18-28 Detrital, 29-6, 29-8 Detrital environment, 56-2 Detrital porosity, 29-8 Detrital reservoirs, 29-7, 29-8 Deuterium ion, SO-6 Development costs, tangible and intangible, 41-l 1 well spacing, 4 I - 11 Development drilling, 36-2, 36-3, 36-6, 40-l Development, historical, thermal recovery, 46-3 Development of waterflooding, 44-l Development plan for oil and gas reservoirs, characterization of the reservoir, 36-3 to 36-9 introduction, 36-1, 36-2 oil and gas differences, 36-2, 36-3 prediction of performance, 36-9, 36-10 references. 36-10, 36-11 Development wells, 41-I 1 Developments in wellbore heat losses, 46-7 Deviation angle, 53-7 Deviation, definition, 58-9 Deviation factor, 39-7, 39-8, 39-10, 39-14, 39-23 Deviation of hole, 53-2, 53-3, 53-10, 53-17 Deviation survey computations, 53-7 Deviation surveys, 49-1, 53-1, 53-7 to 53-9 Dewatering of gas wells, 6-34, 39-15, 39-16 Dewpoint boundary, 39-3 Dewpoint chart, 25-11 Dewpoint curve, 14-l. 20-2 Dewpoint cycling, above or below, 48-7 Dewpoint depression. 12-20, 14-17, 14-18, 14-20 Dewpoint of a system, definition, 22-20 Dewpoint pressure, 22-20, 22-21, 23-3, 23-12, 39-5, 39-7 to 39-11, 39-13, 39-14, 39-16, 39-18, 39-23 Dewpoint pressure correlations, 21-10 to 21-15 Dewpoint reservoirs, 23-7 Dewpoint temperature, 14-l Dewpoint water content chart, 25-12 Dextran, 47-3 Diagenesis, 24-2, 24-20, 52-21 Diagenetic alteration, 50-37 Diagenetic history, 36-3 Diagenetic water, definition, 24-18 Dia-Log caliper tools, 53-18 Diamond cores, 27-9 Diaphragm BHP element, 30-6, 30-7 Diaphragm control valve, 16-4, 16-11 Diaphragm gas-engine starters, lo-19 Diaphragm motor oil-control valves, 12-6, 12-7 Diaphragm motor valve, 1349, 13-53 Diaphragm operators, 16-3 Diaphragm pressure, 13-54, 13-56 Diaphragm pump, 15-15 Diaphragm-&weight-loaded valve, 13-55 Diatomaceous earth filters, 15-20, 15-22,4447 Diatomic gases, 13-37 Dielectric constants, 16-7 Dielectric measurements, 5 l-19 Dielectric permittivity, 49-32 Dielectric strength, 7-3 Diesel engines, 6-1. 10-15, 10-16, 1845 Diesel fuel, IO-15
Diesel index, 21-7 Diethanolamine (DEA), 14-21, 14-22 Diethylene glycol (DEG), 14-7, 14-18, 14-19, 25-19, 25-20 Differential compaction, 29-3 to 29-6 Differential gas liberation, definition, 22-20 Differential gas separation, 37-l Differential head loss, 13-3 Differential liberation, 40-6 Differential-opening pressure valve. 5-13, 5-14, 5-43 Differential-pressure control valve, 6-63 Differential-pressure gradients, 34-42 Differential-pressure taps, 13-3, 13-8 Differential-pressure transducers, 16-6, 46-21 Differential process, definition, 22-20 Differential separation (vaporization), 12-32, 37-3, 45-8 Diffuser, 6-32, 6-35, 6-36, 7-3 Diffusion baffle, 19-24 Diffusion length, 50-I 1, 50-20, 50-21 Diffusion theory, 50-17 Diffusivity. 38-9, 58-34 Diffusivity equation, 35-1, 35-2, 35.10, 36-8, 38-l Digit, definition, 58-9 D&&l age, 49-36 to 49-39 Digital computer program, 14-16 DigitaJ computer systems, 16-10 Digital computers, 40-10. 40-13 Digital signal-processing technology, 5148 Digital sonic logs comparison, 5143 Diglycolamine (DGA), 14-2 1, 14-22 Dikes, 11-l 1 Dilution caused by weighted-average Permeability profile, 39-19 Dilution plane, 23-10 Dimensionless pressure values, 38-4 Dimensionless pressures for aquifer systems, 384 to 38-6, 38-12 to 38-19 Dimensionless water-influx values, 384 Dimensions, definition, 58-9 of buttress-thread casing and coupling, 2-29, 2-59, 2-64 of casing long thread, 2-58 of casing round-thread height, 2-66 of casing short thread, 2-57 of chemical, electrical, and physical quantities, 59-2 to 59-51 of external-upset tubing coupling, 243,2-66 of extra-strong threaded line pipe, 2-50 of extreme-line casing threading and machining, 2-63 of integral-joint tubing thread, 2-65 of integral-joint tubing upset, 2-45 of line-pipe lengths, 247 of line-pipe thread, 247, 2-58, 2-62, 2-65 of line-pipe thread height, 2-62 of nonupset tubing coupling. 242, 2-66 of plain-end line pipe, 2-50 to 2-53 of round-thread casing coupling, 2-28, 2-58 of round-thread tubing coupling, 2-58 of threaded line pipe, 247, 2-58 of tubing round-thread height, 2-66 Din azimuth, 53-7. 53-9. 53-10 Dib vectors, 53-10, 53-12 Dipmeter, 49-25. 49-36, 49-37 DiPmeter logging, application of dipmeter and directional data, 53-10 to 53-16 calibration, 53-8 computed dipmeter log, 53-9, 53-10 device, 53-6 interpretation rules, 53-12 introduction, 53-1, 53-7 oil-based muds, 53-8, 53-9
28
principles of TVD, TST, and TVT plots, 53-15. 53-16 survey computattons. 53-9 tools available, 53-8 Dtpmeter patterns, 53-10, 53-12 to 53-15 Dipmeter surveys. 49-I Direct-acting spring-loaded regulator, 13-55 Direct-acting weight regulator, 13-55 Direct costs (expenses), 41-11 to 41-14 Dnect-current (DC) motor, IO-21 Direct-fired heater, 19-2 I Direct hydraulic subsea control, IS-50 Direct lifting costs, 41-3 Direct line drive, 44 13 to 4416,4422,4433 Direct phase determination, 51-25 Direction of dip, 53-7 Dtrection of hole drift, 53-10 Directional drtlling, 18-30 Directional permeability effect. 44-25 Directional permeability test, 27-1 Directional surveys, available tools, 53-3, 53-4 computation of results, 53-4 to 53-7 introduction. 53-l legal requirements, 53-4 MWD-data listing, 53-6 Directional well survey, 41-8 Directional wells, 53-l Disadvantages, of batch-type meters, 32-10. 32-11 of positive-displacement meters. 32-11, 32-12 Discharge coefficient, 13-8 Discharge (return) gradient, 6-26, 6-29 Discharge piping, 15-17 Discharge pressure, 39-24 Discounted cash flow (DCF) method, 41-3, 41-17 to 41-22 Discounted future net cash income, 41-5 Discounted present worth, 44-5 Discovery allowable, 32-2, 32-3, 32-15 Discrete-piloted hydraulic control, subsea, 18-50 to 18-52 Discrete remote control, subsea, 18-50, 18-5 I Dispersed-gas drive, 37-I Dispersed-gas injection, 43-2, 43-8 to 43.15. 43-17 Dispersed-gas units, 15-27, 15-28 Dispersion. 15-22. 19-1, 45-6, 45-7 Dispersion curves. 51-13. 51-14 Dispersion of clay particles, 56-5 Displacement calculation procedures, Dykstra-Parsons. 448, 449 frontal advance, 44-9 to 44-l I Stiles. 447. 448 Welge, 44-11. 44-12 Displacement efficiency, 39-9, 39- 15, 39-17. 39.18, 39-22, 39-23, 40.34, 43-3, 43-5. 43-6, 43-9, 4439. 45-6 to 45.10, 47-1. 41-2, 47-17 Displacement equations, 43-4 to 43-6, 43-8 to 43-10 Displacement fronts for different mobility ratios. 45-7 Displacement mechanisms, 36-10, 47-19, 47-20 Displacement meter systems, 17-4 Displacement of downhole pumps, 6-21, 6-24 Displacement process, 28-6, 28-7 Displacement-type controller, 13-5 I. 13-53 Displacement-type liquid-level controls, 13-53 Displacement volumes, 4423, 4424, 4428 Displacement volumes injected, 43-3, 43-7. 43-8 Disposal water. 24-5 Dissociation of water, 47- I8 Dissolved acid gases, 4447
PETROLEUM
Dissolved gas(es). 22-l. 22-20, 24-17, 40-3. 44-43 Dissolved-gas drive, 22-20. 442, 44-4 Dissolved-gas effect on oil viscosity, 22-14. 22-15 Dissolved-gas removal, 15-28, 15-29 Dissolved-gas systems, 2 l-18 Dissolved-gas units, 15-27 Dissolved salt, 24-7, 24-8 Dissolved solids, 19-1, 24-3, 24-15, 24-16, 24-18 to 24-20, 44-45 Dissolved-solids removal, 15-29 Distillates, I l-12, 12-32, 57-5 Distillation method, for water in crude oil, 17.5 Distillation, removing water from crude oil emulsions, 19-15 Distributary channel sediments, 36-3 Distributary channels, 36-4, 36.6 Distributing piping specs., 15-12 Distribution of fluids in permeable formations Invaded by mud filtrate, 49-5 to 49-7 Distribution system. 12-10, 12-l I Distribution transformers. types of, 10.30, IO-31 Divalent cations. 47-13. 47-15, 47-21 Divalentihydroxide compounds, 47-20 Diverging vortex separator, 12-14, 12-20 Diverless subsea tree and running tools, 18-32 Diverting agents, 54-S. 54-10, 56-2, 56-3, 56-5 Division-order interest, 4 l-2 Dixon plates, 12-25 Dog-and-groove riser coupling, 18-15 Dogleg, 7-1, 7-9, 10-3. 10-6, 53-6 Dolomite, acid reaction rate. pressure effect, 54-4 clays and silts in, 54-7 effect of corrosion inhibitor on acid reaction rate. 54-6 laboratory tests for acidizing, 54-9 silica in crystal structure of, 54-4 treated with HCL, 54-2 Doiomitization, 24-18. 24-20. 26-2 Dosage, units and conversions, 58-30 Dose eqmvalent, unit and definition, 58-10 Double-acting downhole unit, 6-9, 6-20 Double-acting pump, 6-8, 6-9, 6-16, 6-18 Double-deck shaker, 52-8 Double-flanged head, 3-8 Double-port diaphragm motor valve, 13-57 Double-ported valves, 13-55, 13-58 Double-studded adapter, 3-9 Double-studded crossover flange, 3-9 Double-valve arrangements, 8-7 Double-welded butt joints. 12-40 Doughnut tubmg hanger. 3-39 Douleb oil held, Tunisia, 24-18 Dow Chemtcal Co., 54-l Downcomer pipes, 1 l-13 Downcomer/spreader, 19-19 Downdip gas flow, 43-I I Downflow filters, 15-20 Downhole assembly, MWD, 53-2 Downhole dtgitizer, 5 l-27 Downhole jet pump accessories, dummy pumps, 6-48 pressure recorders, 6-48 safety valves, 6-48, 6-49 screens and filters. 6-48 standing valves, 6-48 swab cups (noses), 6-47. 6-48 Downhole pumps, closed power-fluid systems, 64, 6-5 displacement of, 6-21, 6-24. 6-25 handling of formation-fluid volumes, 6-67 installation. 6-2 jet free completions, 6-34
ENGINEERING
HANDBOOK
PIE ratto. 6-27 pressure recorders, 6-48 pressures and force balance in. 6-16 to 6-19 reciprocating, 6-5 I, 6-55 reverse-flow systems. 6-5 TFL installations. 6-6 types of installations, 6-2 to 6-4 with wireline-retrievable safety valve, 6-49 Downhole sensor. 53-4 Downhole sensor sub, 53. I Downhole steam generators, 46-4, 46-19 Downhole temperature profiles, 46-21 Downkickmg, 6-31 Downstream taps. 13-30 to 13-34, 13-37 Downtime analysis, 18-7, 18-8 Downtime gas. 52-17 Drag-body flowmeter, 32. I3 Drain cylinders, 12-12 Drainage area. 35-l, 35-5, 35-6, 35-13, 35-16 to 35-18, 36-8, 55-4, 56-l Drainage-area shape, 37-2 1 Drainage channels for tanks. 1 I-I I Drainage channels. mist extractor, 12-l 1, 12-12 Dramage curve, 28-5, 28.9. 28-l I, 2X-12 Drainage relative-permeability data. 28. I4 Drainage shapes. 35-4, 35-5. 35-16 Drainage tests. 26-24 Drawdown effects 39-25 Drawdown pressure. 30-10 to 30-13 Drawdown tests. 35-3, 35-4. 35-14, 35-15, 44-4 I Dresser Atlas, 49-2. 49-36, 49-37. 51-18 Drift, 13-50 Drift diameter, 3-12 to 3-14 Drill-time log, 52-l Drilling clause, 57-4. 57-5 Drilling contractor, I8- 16 Drilling data analysis. 52-28 Drilling efficiency, 52-28 Drilling engineer. 18-4 Drilling engineering services, 52-2, 52-27, 52-28 Drilling-equipment considerations offshore, backup control systems, 18-15, IS-16 BOP. 18-11, 18-12 control systems, 18.15 extended water-depth capability. 18-16 flex joints, 18-12, 18-13 K&C systems, 18-15 marine riser. 18-14, 18-15 motion compensator, 1X-13. 18-14 reentry systems, 18-14 riser tensioner. 18-13 slip joints. 18-13 Drilling fluid, offshore, 18-12 to 18.14, 18-18, 18-41 Drilling funds, 57-l 1 Drilling, high-current, 18-21. 1X-22 Drilling models, 52.24 to 52.26 Drilling motion compensator, 18-14 Drilling mud, acoustic velocity in, 51-31 Drilling offshore, mooring and riser analyses, 18-16, 18-17 operating manual and emergency procedures, 18-16 planning and preparations, 18-3 to 18-5 rig selection, 18-5 to 18-16 Drilling operations, 18-28, 18-29. 18-31, 18-32. 18-39. 18-40 Drilling optimization. 52-29, 52-30 Drilling porosity, 52-26 Drilling riser, 18-16. 18-18, IX-34 Drilling vessels: see specific type Drilling wells, estimation of BHT, 31-6 Drillships, 18-3, 18-4. 18-7, 18.14. 18-15, 18-20
SUBJECT INDEX
Drillstem test or testing, 6-34. 18-20. 18-34, 24-3, 27-8, 30-S. 30-l 1, 30-13, 30-15. 41-8, 42-4. 48-8, 49-31 Drillstem tests, openhole, 53-17 Drillstring motion compensators, 18-13 Drip pots, 13-37, 13-53 Drip-proof motor, IO-26 Drips, 39-26 Drive mechanism, effects on recovery, 36-3 Drop method, surface-tension measurement, 24-16 Droplet size distribution. 15-23 Drowned gas wells, 39-16 Dry chambers for subsea completions, 18-31 Dry-desiccant dehydration, 14-20, 14-21 Dry-desiccant dehydrators, 13-56. 14-10, 16-15 Dry forward combustion, 46-l to 46-3, 46-14. 46-18, 46-19 Drv eas. 10.16. 39-l. 39-16. 39-18 to -3;.20. 39-23, 39-24 Dry-gas breakthrough, 39. I7 to 39-20, 39-22 Dry-gas front, 39-17, 39-18, 39-21 to 39-23 Dry-gas injection, 39-16. 39-21 1 39-25, .3%26 Dry-gas reservoir, 35.3, 36-3. 39-l. 40-24, 40-25 Dry-gas/wet-gas cycling operation, 39-23 Dry-gas/wet-gas interfaces, 39-2 1, 39-22 Dry reverse combustion, 46-2 Dry vs. wet combustion, 46-18. 46-19 Dual-detector compensated-neutron device, 50-20 Dual-detector thermal device, 50-30, 50-32 Dual-element fuses, lo-28 Dual-fuel engines, IO-16 Dual induction-laterolog 8 (DIL), 49-15 to 49-20. 49-28 Dual induction-laterolog log, 46-2 1 Dual intermittent gas-lift installations, 540, 545 Dual laterolog, 49-l I, 49-20. 49-23, 49-24, 49-28 Dual laterologigamma ray tools, 49-20 Dual-parallel-string installations, 3-l 1, 3-13 Dual-tube separator, 12-9, 12-10. 12-16. 12-18 Dual-vessel system, 6-63 Dual-water model, 49-38 Dual wells or zones, 6-7, 6-8 Dual-wing well manifold, 16-l I, 16-12 Dummy pumps, 6-48 Dummy valve, 3-35 Dump cycles, 19-30 Dump valves, 18-50, 19-20, 19-22. 19-23 Dun and Ros method, 34-37, 3440 Duplex pumps, 15-14 Dura Rod, 9-13 Duri field, Indonesia. 46-4 Dykstra-Parsons calculation. 44-8. 44-9 DykstraParsons coefficient, 47-17 Dykstra-Parsons method, 40-19, 44-7, 44-9 Dynamic amplification factor, 18-26, 18-27 Dynamic-capillary-pressure method, 26-24, 26-25 Dynamic elastic constants, 51-4 Dynamic lag, 13-51 Dynamic miscibility. 45-l. 45-2, 45-4. 45-5, 48-5 Dynamic positioning, 18-2, 18-10, 18-14, 18.20, 18-21 Dynamic stresses, 18-17 Dynamic viscosity, 24-16, 58-35 Dynamite, 56-l Dynamometer card analysis, 10-5, IO-6 Dynamometer cards, 10-6 Dynamometer test, 40-27
29
E E-core transformer, 30-6 Early-time region (ETR). 35-3, 35-4, 35-6, 35-8. 35mI5 Earth resistivities, 49-l East Coalinga field, California, 46-18 East Texas area, 27-2. 27-3 East Texas field, 29-5. 29-6.40-2. 40.34,41-5 East Venezuela field, 46-16 Eccentric orifices, 13-45. 1348 Eccentricity. 6-69, 6-72 Echometer, 30-7, 32-6 Economic analyses, 39-10, 39-15, 44-32 Economic balance. 19-15 Economic considerations of stage separation, 12-33 Economic evaluation, 24-21, 44-7, 45-10 Economic justification of automation, 16-2 Economic limit, 40-12. 40-19, 40-20, 40-27. 40-32, 41-10. 41-11 Economic-limit rate. 40-25, 40-27 Economics. Impact of offshore leasing, 57-12 Economics, letter and computer symbols, 59-2 to 59-51 Economics of CC reservoir operations, 39-26 Economics of injection operations, 42-6 Economics of treating crude-oil emulsions, 19.32, 19-33 Eddy currents. 13-2. 13-36, 13-48, 19-12, 53-20, 53-22, 53-26 Edge water, 24-2 Edgewater drive, 40. I5 Edgewater encroachment, 28-4 EDTA, sequestering agent. 547 Effective annual interest rate, 41-25, 41-26 Effective decline rates, 40-27. 41-27 Effective formation permeability, 55-4 Effective gas permeability, 39-25 Effective grain volume, 26-4, 26-6 Effective hydrocarbon porosity, 40-25 Effective interest rate, 41-17. 41-20, 41-21, 41-26, 41-27 Effective isopermeability map, 39-22 Effective mobility ratto, 47-18 Effective molecular weight, 22-7 Effective permeability. 26-15, 28-l to 284, 28-6, 28-8, 28-13, 39-17, 4432, 44-33, 46-2 I Effective porosity, 26-2 to 26-6, 28-2, 40-5, 55-4 Effective salmity. 47-13 Effective shear rate. 47-5 Effective stress, 51-30, 51-31, 51-35, 51-43 Effectiveness of cycling. 39-17 Efficiency factor in orifice equation, 13-3 Efficiency of cycling, 39-17 Efficiency of ESP system, 7-l Efficiency of gas lift, 30-14, 30-15 Efficiency of motor, IO-25 Effictency of permeability variation, 448 Effictency of separation, 12-21 Effluent fluids quality, 12-16 Effluent oil from separator, 12-15 Effluent water from’separator, 12-15 El Dorado field, Kansas, 46-14 Elastic collapse-pressure equatton. 2-55 Elasttc limit, 51-I. 51-2 Elastic limit of material, 2-46 Elastic moduli, 51-I to 51-3. 51-12, 51-30, 51-31, 51-43. 51-44, 58-34 Elasttc parameters. relationships among, 51-2 Elastic properties. 51-44 Elastic scattermg, 50-9, 50-10 Elastic transition zone, 2-55 Elastic wave propagation, 51-6, 51-8, 51-12. 51-14, 51-29. 51-49
Elastic wave velocities. 51-7 Elastictty. characteristics of acoustic waves, 5 l-2, 5 l-3 introduction, 51-1, 51-2 Elastomeric hoses, 18-49 Elastomeric jomts, 18-13 Electric charge, unit and definition. 58-l I 58-23 Electric conductance, umt and definition, 58-l I, 58-23, 58-35 Electric dipole moment, 49-32 Electric generating systems, IO-2 I Electric inductance, unit and definition. 58-l I, 58-23 Electric-log analysis, 26-22, 26-25 Electric-motor valve operators. 16-3 Electric motors for oilwell pumping, design standards. 10-19, IO-20 direct current (DC), IO-21 generating systems, IO-2 1 horsepower ratings of. IO-20 multiple-horsepower rated, IO-20 multiple-size rated. IO-2 1 performance factors of, IO-23 selecting size of, lo-21 single-phase type. IO-2 I ultrahigh-slip, lo-22 voltage frequency of, 10-21. IO-23 Electric porosimeter, 26-4 Electric potential difference. unit and definition, 58-l I Electric power supply, ESP, 7-9 to 7-12 Electric pressure control, 12-39 Electric resistance, umt and definition. 58-l I, 58-23, 58-36 Electric-solenoid valves, 16-3 Electric-starter motors. lo-19 Electric submersible pumps (ESP). application, 7-l. 7-2 general references, 7-17 handling. installation, and operation, 7-12 to 7-14 installation, 7-l. 7-2 performance curves, 6-35 references, 7- I7 selection data and methods, 7-9 to 7-12 system, 7-1. 7-2 system components. 7-3 to 7-9 troubleshooting, 7-14 to 7-17 Electric submersibles, 18-44 Electrical capacitance in electronic interface controllers, 19-3 1 Electrtcal capacitance, unit and definition, 58-10, 58-23, 58-35 Electrtcal conductiwty in electromc interface controllers, 19-31 Electrrcal conducttvity of flmd-saturated rocks, fundamental concepts, 26-28, 26-29 introduction. 26-27. 26-28 resistivity measurement of rocks, 26-29 Electrical conductiwty, units and conversions, 58-35 Electrical distribution system, grounding of, 10-31, lo-32 open delta transformer, 10-30, IO-3 1 phase converters, types of, 10.35, IO-36 power factor and use of capacitors, IO-33 to IO-35 primary system and voltage, IO-29 secondary system, 10-29. IO-30 transformers, lo-30 voltage drop in, lo-32 Electrical logging, electromagnetic propagation tool, 49-32 to 49-36 focused-electrode logs, 49-18 to 49-22 fundamentals. 49-l to 49-7
30
general references, 49-41, 49-42 induction logging, 49-14 to 49-18 microresistivity devices, 49-22 to 49-25 nomenclature, 49-39 to 49-41 references. 49-41 resistivity logging devices, 49-l 1 to 49-14 SP log, 49-l& 49-l 1 the digital age, 49-36 to 49-39 typical log. 49-3 uses and interpretation of well logs, 49-25 to 49-32 Electrical one-line diagram, IS-45 Electrical parameters used in characterizing porous media, 26-31 Electrical potential logs, 53-17. 53-19 Electrical properties of reservoir rocks, empirical correlations, conductive-solids effect, 26-30, 26-31 introduction, 26-29 parameters used in characterizing, 26-31, 2632 resistivity of partially water-saturated rocks, 26-31 Electrical resistivity measurement of rocks, 26-29 Electrical survey (ES), 49-l 1, 49-19 Electrical systems offshore, code and regulatory authorities, 1844 distribution system, 18-4.5, IS-46 equipment enclosures, 1846 hazardous areas, 1846 introduction, 18-43, 1844 layout of facilities, 18-44 platform loads, IS-44 primary electric power, 18-44, 1845 secondary/back-up power, 18-45 wiring methods, 18-46 Electrically controlled valves, 16-3 Electrically equivalent diameter of invasion, 49-6 Electricity, units and conversions, 58-35, 58-36 Electrochemical corrosion, 3-36 Electrochemical potential, 49-8 to 49-10 Electrode array, 53-7 Electrofiltration potential, 49-10 Electrohydraulic control system, 18-l 1 Electrohydraulic subsea controls, 18-49 Electrohydraulic systems, 3-31 Electrokinetic effects, 28-1 Electrolvtic conduction. 26-28 ElectroGtic corrosion, ‘12-40 Electrolytic model, 39-20, 39-21, 44-17, 44-18, 4420, 44-21 Electromagnetic e-mode telemetry, 53-l Electromagnetic force (EMF), 53-16 Electromagnetic inspection devices, 53-17, 53-19 . Electromagnetic propagation log, 49- 1, 49-2 Electromagnetic propagation tool (EPT)‘“, 49-32 to 49-36 Electromagnetic radiation, 50-3 Electromagnetic thickness log, 53-21 Electromagnetic thickness tools, 53-19 to 53-2 1, 53-23 Electra-mechanical timers, 164 Electromotive force, 58-11, 58-23, 58-35 Electron density, 50-16, 50-17 Electron-density index, 50-7, 50-26 to 50-28 Electron microscopy, 27-1 Electronic-casing caliper log, 53-19 Electronic chart scanners, 30-2 Electronic computers, 40-9 Electronic (solid-state) controller, 16-4 Electronic interface controllers, 19-31 Electronic model, 39-20 Electronic timers, 5-55
PETROLEUM
Electropneumatic operators, 16-3 Electrostatic coalescing, 19-13 Electrostatic coalescing treaters, 19-25, 19-26 Electrostatic emulsion treaters, 19-2, 19-10, 19-13. 19-25 to 19-27, 19-31 Elemental models, 46-1 I to 46-13 Elevated separator. 12-17 to 12-19 Elf Aquitaine, 46-27, 51-25 Elk Basin field, Wyommg, 26-23, 39-16 Ellipsoidal head equations, 12-38 Elongation, of API body and bonnet members, 3-2, 3-3 of API casing and liner casing, 2-2 of API tubing, 2-37 of line pipe, 246 of sucker-rod types, 9-5 Embayments, 29-7 Embedment, 55-S Emergency disconnect conditions, 18-21 Emergency power, 1845 Emergency procedures offshore, 18-16 Emergency shutdown system (ESD), 3-33, 3-34, 18-47, 18-48 Emergency venting of storage tanks, 11-7 to 1 l-9 Empirical correlation factor, 27-8 Empirical equations, ice movement rate and shape, 18-39 Emulsification of oil, IO-13 Emulsified water, 19-3 Emulsifying agent, 19-2 to 19-5, 19-9, 19-14 Emulsion breakers, 19-10, 46-22 Emulsion-breaking agents, 56-2 Emulsion conditions, ESP chart, 7-16 Emulsion, definition of, 19-l Emulsion, effect on oil viscosity, 6-27 Emulsion flood, 47-2 1 Emulsion formation, 47-19 Emulsion plugging, 6-56 Emulsion treater, I l-12, 12-3, 124, 12-13 Emulsion-treating equipment, 19-15, 19-16, 19-21. 19-27 to 19-32 Emulsion treating, overall system performance, 19-33 Emulsion-treating system, 19-6, 19-7, 19-9, 19-11, 19-13, 19-15, 19-16, 19-30, 19-32 Emulsion viscosity, 6-67 Emulsions, as mixed-base fracturing fluids, 55-5, 55-7 chances of forming, 8-6 decreases injection cycles/day, 5-40 effect of silicate control agents, 54-7 effect of surfactants, 54-7 gas lift can intensify, 5-2 in lirefloods and steamfloods, 46-2 1, 46-22 prevents application of gradient curves, 5-25 Emulsions, methods used in treating. agitation, 19-12, 19-13 centrifugation, l9- I5 chemical demulsitier, 19-9 to 19-12 distillation, 19-15 electrostatic coalescing, 19- I3 fibrous packing, 19-14 filtering, 19-14 gravity settling. 19-14, 19-15 heating, 19-7 to 19-9 water washing, 19-13 Emulsions theories: See Theories of emulsions Enclosed motor, totally. lo-26 Enclosures for motors; 10-26, IO-27 End effects, 28-3, 28-5. 28-7 End-to-end flowline valves, 3-12 to 3-14 Endicott development, 18-3 Endogenetic subsurface water, definition, 24-19 Endpoint displacement data, 28-8 Endpoint mobility ratio, 47-l
ENGINEERING
HANDBOOK
Endurance limit, 9-l I Energy balance, 13-I. 34-36, 46-12 Energy-balance equation, 34-I) 34-2. 34-9 Energy, definition, 22-2 1 Energy equivalents, table, 1-77 Energy loss, 13-2, 13-3 Energy relationships for flowing fluid. 34-1, 34-2 Energy, SI unit for. 58-5. 58-l 1, 58-23, 58-24, 58-32 Engine displacement, 6-30 Engine efficiency, 6-3 1 Engine selection, calculations for, IO-17 to lo-19 equipment life and cost, 10-16, IO-17 fuel availability, lo- 16 horsepower, IO-17 installation, lo-19 safety controls, lo-17 Engineering, analysis, 42-3 appraisal method, 41-2. 41-3 computer simulation methods, 36-7 in developing oil and gas reservoirs, 36. I, 36-6 to 36-8 interference testirg, 36-7, 36-8 material-balancp studies, 36-7 net-pay/net-connected-pay ratio, 36-7 England, 18-25 Enhanced oil recovery (EOR), 23-l. 23-7. 24-16, 25-1, 25-14, 46-3, 47-1, 47-2, 47-6, 47-7, 47-18, 47-22, 48-2, 48-4, 48-6, 48-8 Enhanced-oil-recovery (EOR) projects, 19-28 Enhanced-recovery methods, 404 Enhanced-recovery operation, 5 l-42 Enos Creek field. Wyoming, 24-18 Enriched-gas drive, 45-2, 45-3, 45-5 Environment, 11-4, 13-1 Environmental conditions (forces), 1 l-6, 18-1, 18-3, 18-4, 18-7 to 18-10, 18.17, 18-21, 18-25, 18-31, 18-36, 18-44, 1847 Environmental conditions, ice characteristics, 18-38, 18-39 ice loading, 18-39 permafrost, 18-39 waves, 18-39 Environmental corrections, gas effect, 50-30, 50-31 matrix effect, 50-28 to 50-30 shale effect, 50-31 to 50-33 Environmental criteria, 18-26 Environmental factor, 1 l-8 Environmental impact, 24-9 Environmental load predictions, 18-22 Environmental regulations, 44-41 Environments, wellhead equipment, 3-36 to 3-39 Epigenetic interstitial water, definition, 24-18 EPILOG log analysis, 49-37 Epipressure contours, 44-15, 44-16 Epithermal counting rate, 50-20, 50-29 Epithermal detector, 50-19, 50-20, 50-2 1 Epithermal diffusion coefficient, 50- 19 Epithermal matrix effect, 50-30 Epithermal neutron flux, 50-15, 50-20 Epithermal neutrons. 50-S. 50-9. 50-14, 50-17, 50-19, 50-30 Epithermal porosity device, 50-28, 50-32 Epoxy resin coating, 11-6 Epoxy thermoset resin, 9-12 Equal-payment-series present-worth factor, 41-25 Equalizer for tank battery, I l-9 Equalizing valves, 3-29 Equation factors for collapse pressure equations, 2-54 to 2-56
SUBJECT INDEX
Equation, general for critical-flow prover, 13-45 Equations for computing subsurface pressures, 33-15 Equations for jet pumps, 6-36, 6-37 Equations for oil and gas separator, gas capacity, 12-23 sizing for &IS capacity, 12-23 to 12-25 Equations for valuation methods, 41-18.41-19 Equations for water-drive reservoirs, 38-I to 38-4 Equations in Sl metric system, 58-13 Equations of state (EOS), 14-16, 20-4, 20-6 to 20-8, 23-10, 23-12, 23-13, 25-8, 25-16, 39-16, 48-4, 48-5, 48-9 Equilibrium behavior, GC systems, 39-2 to 39-4 Equilibrium constants, 14-16, 23-l I, 37-23 Equilibrium data sources, 25-l to 25-4 Equilibrium dewpoint, 14-18 Equilibrium dewpoint locus, 25-1, 25-2 Equilibrium dewpoint water content, 25-2 Equilibrium flash calculations, 12-33, 12-34, 14-16 Equilibrium flash separation, 14-16 Equilibrium gas. 39-7, 39-8, 39-14 E&libriumg&saturation,40-11,40-12,43-11 Equilibrium phase diagrams, 23-1, 45-2 Equilibrium ratios, 21-11, 21-16, 23-1 I, 25-5, 39-6, 39-9, 39-11 to 39-13, 39-15 Equilibrium vaporization constants, 46-12, 46-37, 46-39 Equilibrium vaporization ratios. 37-23 Equilibrium water dewpoint, 14-18 Equipment coordination, surface/downhole, 4-1 Equipment enclosures offshore, 18-46 Equipment for control of oiltield motors, handoff-auto switch, lo-27 line disconnect switch, lo-27 local remote switch, lo-27 motor starter contactor, IO-28 programmer, 10-27, IO-28 sequence-restart timer, IO-27 Equipment selection, reciprocating pumps, 628 Equipment used in emulsion treating, clarification of water produced, 19-28 desalting crude oil. 19-26, 19-27 electrostatic coalescing treaters, 19-25, 19-26 EOR projects, 19-28 free-water knockouts, 19-17, 19-18 horizontal treaters, 19-23 to 19-25 reverse emulsions, 19-27 settling tanks, 19-18 to 19-22 storage tanks, 19- 18 vertical treaters, 19-22, 19-23 Equivalent circular pipe, 34-27 Equivalent conductivity, 49-34 Equivalent formation-water resistivity, 49-l 1 Equivalent hydraulic gradient. 26-l 1 Equivalent length of &es and fittings, 15-4 Equivalent limestone porosity, 50-28, 50-30 Equivalent linear permeability. 26-18 Equivalent liquid permeability, 26-18, 27-1, 27-8 Equivalent methane in air (EMA), 52-3 to 52-5 Equivalent molecular weights. modified weight average. 21-12 to 21-15 Equivalent mud density (EMD), 52-25 Equivalent proton masses (EPM). 24- 19 Equivalent slowing-down length, 50-29 Equivalent water conductivity. 49-39 Equivalent wellbore radius, 35-4 Equivalents, tables, areas, 1-73 capacity, 1-73
31
density, 1-79 energy, 1-11 length, l-7 1 mass, 1-75 power. 1-78 pressure, 1-77 velocity, 1-76 volum& l-73 work, 1-77 Erection of pumping units, 10-7, 10-12 Erosion, pump cavitation damage, 6-36 Error anaiysis, 50-28 Errors in basic data, 38-7, 38-8 Erythorbic acid, reducing agent, 54-7 Escalation clauses, 41-3, 41-9 Esso. 46-4, 46-14 Estimating reserves. 40-l Ethanelwater system, 25-17, 25-18, 25-24, 25-27 Ethanolamine, 14-21 Ethylene density, 17-6 Ethylene glycol (EG), 14-7, 14-18, 14-19 Ethylene glycol, hydrate inhibition, 25-19, 25-20 Ethylene glycol monobutyl ether, 54-7, 56-5 Ethylene/water system, 25-24, 25-27 Ethylenediaminet&raacetic acid (EDTA), 56-2 European countries, concrete gravity structures, 18-23 Evaluation of fracturing prospects, 5 l-45 Evaporation method of capillary-pressure measurement, 26-24 Evaporation, preventing, 11-12, 11-13 Evaporites. 49-25 Evinper-Muskat equation, 34-3 I Example problems: casing, tubing, and line pipe. . . 2-36. 2-37. 2-55, 2-56 cmde-oil properties and condensate properties and correlations, 21-15 to 21-20 electric submersible pumps, 7-17 estimation of oil and’gas’reserves, 40-8, 40-9, 40-12 to 40-14, 40-16, 40-17, 40-3 1 gas-condensate reservoirs, 39-10, 39-11, 39-23, 39-24 gas lift, 5-4 to 5-8, 5-10 to 5-12, 5-15, 5-20, 5-25, 5-26, 5-29 to 5-37. 546. 5-47, S-49, 5-50, 5-52 gas measurement and regulation, 13-8 gas properties and correlations, 20-13 to 20-17 hydraulic pumping, 6-20, 6-21, 6-24, 6-29. 6-30, 6-44 to 6-46 miscible displacement. 45-10 to 45-13 mud logging, 52-29 phase behavior of water/hydrocarbon systems, 25-13. 25-14 properties of reservoir rocks, 26-3, 26-5, 26-6, 26-14, 26-15, 26-17, 26-26, 26-27 pumping units and prime movers for pumping unit, IO-8 to 10-11, 10-18, io-14. io-21 to 10-24, IO-31 solution-gas-drive oil reservoirs, 37-24, 37-25 subsurface sucker-rod pumps, 8-5 sucker rods, 9-4 water-drive oil reservoirs, 38-5 to 38-7 well-performance equations. 35-7 to 35-9, 35-13. 35-14, 35-19, 35-20 wellbore hydraulics. 34-8, 34-9, 34-23 to 34-26. 34-30, 34-32 to 34-35, 34-41 to 3445 Excelsior packs, 19-23, 19-31, 19-32 Excess-flow valves, 3-29 Excitation, BHP gauges, 30-5, 30-6 Executor, definition. 57-3
Exhaust-gas turbocharger, 15-16 Exhaust power fluid, 6-25 Exogenehc subsurface water, definition, 24-19 Exothermic reaction, 31-6 Exotic metals for pipe, 15-l 1 Expander, 14-8 Expansion-drive gas reservoirs, 40-26 Expansion factor, 13-2, 13-8, 13-26 to 13-34 Expansion separator or vessel, 12-1 Expansivity, 24- I5 Experimental procedure, steady-state k, methods, 28-3 to 28-7 unsteady-state k, methods, 28-7 Exploration geologists, 18-3 Exploration hazards, 46-22 Exploratory well, 4 I-I 1 Explosion proof, 3-34 Explosion-proof motors, 10-27, 1@36, IS-46 Exponent of backpressure curve, 33-5 to 33-13 Exponential-integral solution, 35-3, 35-4 Exponentials, table, l-55 Extended flanged outlets, 3-3 Extended flanges, 3-8 Extended water-depth capability, 18-16 Extension nipple, 8-1, 8-4 Extensive properties. definition, 22-21 External boundary conditions, definitions, 38-I External coatings, Il.6 External corrosion, 3-36, 18-33 External gas-injection pressure maintenance, 43-16 External-upset tubing, 2-38 to 245,2-64. 2-66 Externally adjustable secondary seal, 3-6 Extra-strong threaded line pipe, Z-46, 2-50 Extracting-liquid drive, 45-5, 45-6 Extraction method for determining sediment in oil, 17-5 Extraction methods for determining water saturation, 26-22 Extraction of minerals, 24-20 Extraneous materials in well fluids. 12-3 Extreme-line casing, 2-1, 2-4, 2-6, 2-8, 2-10, 2-12, 2-14, 2-16, 2-18, 2-29 to 2-31, 2-62 to 2-64, 2-67, 2-68 Extreme-line casing joint, 2-5, 2-7, 2-9, 2-11, 2-13, 2-15, 2-17, 2-19, 2-60, 2-63, 2-67 to 2-72 Extruded-plastic system, 15-10 Exxon Co. U.S.A., 16-13, 47-22 Exxon Corp., 20-S F “F” Pairs log analysis Facies, 29-5, 29-8 Facilities, for fireflood, 46-20 for steamflood, 46-19, 46-20 Facility throughput, 58-25, 58-30, 58-31 Factor analysis, 24-20 Factor, gas-pressure-at-depth, 5-5, 5-6 Factors affecting oil viscosity, 22-14 Factors affecting permeability measurements, gas slippage. 26-18 overburden pressure, 26-19 reactive fluids, 26-18, 26-19 Factors contributing to vapor and gravity losses in tanks, agitation, 1l- 12 breathing, 11-12 filling, 11-12 storage size, 1 l-12 surface area, 11-12 tank pressures, 11-12
PI:1 IN,1 I:lIM I:N(;INI:I.HINf,
37
temperature. I I- I2 vapor prewlre, I I I2 Factors for test-preshurc cquationh. 2-63 Factors in design of injection opcratlons. 42-2 Factor> in evaluation oI permeability l’rom other parameter.\. 26-19. 26-20 Factory-baked coatmgh. I I-I Fail-safe hydraulic actuatow 18-3 Fail-safe valves. 3. IX Failure diagram. 9-4 Failure5 of sucker rods, 9-8. 9-9. 9- I3 Faw market value. 40-I Fair-market-value determination, 41-2. 4 l-3. 41-S. 41-S Fanning friction factor, 34-24 Fanning‘s equation. 26-10 Farmouts. 57-9. 57-10 Fathometer. 18-5 Fatigue analysis, IX-27 Fatigue cracks or cracking. 9-l. IS-16 Fatigue damage, 18-27 Fatigue failure. 9-9. IS-21 Fatigue life. 9-l I Fatty amine compounds. 44-45 Fault traps. 29-3 Feasibility analysis, 39. I7 FED DDL wellsite analysis. 49-37 Federal excise taxes. 41-l. 41-3, 41-4, 41-9. 41-12 Federal income taxeb. 41-5. 41-6. 41-S. 41-12 Federal Power Commission (FPC) approval certificates. 4 l-9 Federal Register, 57-12 Federal taxes. 41-5. 41-7, 41-12 to 41-16, 44-5 Fee ownership, control, 57-2 definition, 57-l Fee simple interest, 41-I Fence diagram, 45-8, 45-9 Ferric hydroxide, 56-3 Ferrous sulfide precipitation, 54-7 6FF28 IES tool. 49-15 6FF40 IES logs and tool, 49-15.49-17, 49-18 Fiber-reinforced plastic pipe, 15-10 Fiberglass casing and tubing, 4446 Fiberglass filaments, 12-12 Fiberglass-lined steel tanks, 19-31 Fiberglass-reinforced polyesters (FRP’s), 11-9 Fiberglass/steel rod string, 9-12 Fiberglass sucker rods, application, 9-12, 9-13 body. 9-12 care, handling. and storage, 9-13, 9-14 chemical and mechanical properties, 9-l I end-fitting grades, 9-12 expected life, 9- I3 failures, 9-13 general dimensions, 9-l 1 introduction, 9-10 manufacture of. 9-12 physical dimensions, 9-l 1 rod-body-to-steel connector-joint design, 9-12 stress-range diagram, 9- 13 Fibrous filters. 39-26 Fibrous packing, 19-14 Fibrous-type nust extractors, 12-12 Field behavior vs. predicted performance, waterfloodmg, 44-31 Field capillary number, 47-17 Field compressors, control of, 13-57 Field development, 36-1, 46-l 1 Field development plan offshore, I S-25, IS-26 Field engineers, 39-l Field examples, deviation survey, 53-7, 53-8 Field facilities. tireflood.
pencratlon and inlcclion. 4h-IY water trcatnacnt. 40-20 Field-fil~crcd hampIe. 24-4 Field flltcring cqulpmcnt, 24-4 Field instrumentation l’or SCADA. 16-9 Field operations ol’fshorc. drillstem testing, IX-20 introduction. 18-17 locatwn, establishing. I& I8 plug and abandonment, IS-20 running BOP, IS-18 to IS-20 running ZO-in. casing. IX-18 running 30.in. casing. IS-18 spudding the well, IS-18 Fieid performance, 48-6. 48-7 Field-performance data. 37-7 Field &lot tests, 48-13 Field pilots, 46-I I Field projects. thermal recovery, dry vs. wet combustion, 46-18, 46-19 reservw performance, 46-14 to 46-17 screening guides, 46-13 Field response, MP ilooding, 47-16 Field results, chemical flooding, 47-21, 47-22 foam injection, 47-9 high-pH processes, 47-21. 47-22 polymer floods, 47-6 Field sampling. CC reservoir, 39-5 Field separation conditions, optimum, 39-5 Field titration kit, 54-3 Field-welded tanks, 11-2. 1 l-9 Filing losses, storage tanks, I I-I 1 to 1 l-13 Fill-up, 44-9. 44-34, 44-39. 4441, 44-46 Film thickness of coatings, II-4 Filter/separator. 12-l. 12-2 Filter-type mist extractor, 12-l I Filtering, 12-8, 12-11. 19-7, 19-14, 19-28 Filters, 15-20, 15-21 Filtration, 15-20 Finger in gas displacement, 43-7 Fingering of miscible slug, 45-6 Finite-closed aquifer, 38-5, 38-6, 38-8, 38-13. 38-18 Finite-closed boundary, 38-1 Finite-difference equations, 48-l, 48-2, 48-13 Finite-difference method, 43-13 to 43-15 Finite-difference simulator, 45-10 Finite-element simulator, 45-10 Finite linear aquifers, 38-2 Finite-outcropping aquifer, 38-5, 38-8, 38-10, 38-11. 38-14 to 38-19 Finite-outcropping boundary, definition, 38-l Fire detectors and detection systems, 18-47 Fire hazard. IS-46 Fire tests for valves, 3-38 Fire tubes. 19-28 Fireflood, 46-1, 46-3. 46-4, 46-13 to 46-28 Fireflood pots, 46-13 Firewall, 11-9, 11-11 First-contact miscible flooding, 45-1, 45-2, 45-5 First law of thermodynamics, 34-I First-stage separator gas, 39-6, 39-10 Fishing characteristics of packers, 4-6 Fissility, 52-20 Fitting factor, 38-7 Five-point difference scheme. 48- 1I Five-spot pattern, 43-2, 43-8, 44-1, 448, 4413 to 44-20, 44-22. 4423, 4425, 44-26 to 4429, 4433. 44-34, 44-37, 44-38. 4440, 45-7, 46-13, 46-17, 46.18, 46-23. 46-25. 46-26, 46-28. 46-30. 47-10
IIASl,l!r,~,K
l,lVC V‘IIYL. milnlll~ltl, 11 17 l,~xctl choke, 5 S4 Fixed drilling platlorrn\, l&2, IX-24 Fixed-pad Kingsbury Ihrwt bcarmg, 7-3 Fixed platli)rm drilling, ?-3X, 3.3Y Fixed pump mstallation. 6-2. h-3 Fixed-roof tanks. I l-2 Flagging the bottom valve, gas IlIt, 5-44 Flame arrcstcrs, I l-6, I I-X to I l-10. 19-2X Flame ionization detector (FID). 52-4. 52-5. 52. IO, 52. I I Flammable gases, IO-36 Flammable liquids, IO-36 Flange data, 3-16 to 3-25, 3-27 Flange taps, 13-3 to 13-8, 13-14 to 13.19, 13-26, 13-27. 13-30, 13-31, 13-33, 13-34 Flank waterflood, 4% I3 Flare boom, IS-20 Flash calculations for separators, 12-33. 12-36, 12-37 Flash calculations. multlcomponent. 40. I3 Flash chamber. trap or vessel, 12-l Flash distillation system. 19-15, 19. I6 Flash gas liberation. definition, 22-20 Flash gas separation. 37-l Flash liberation process. 32-7 Flash point, I l-7 to I l-9 Flash process, definition. 22-20 Flash separation (vaporization), 12-32. 21-4, 37-3. 45-8 Flat-bottom tanks, I l-2 Flat-plate orifice, 13-2 Flat-sided tanks (non-API), 1 l-2 Flex joints. 18-12. 18-13. 18-19, 18-25 Flexible pipe. 18-36, 18-37 Flexural failure, 18-39 Float-actuated pilot-operated valve. 13.53 Float-and-sink (density) method, 52-20 Float cages, 13-54 Float-operated controller, 13-54 Float-operated controls, 12-18 Float-operated mechanical oil valves. 13-53 Float-operated pilot, 12-5, 12-39 Float-operated trap, 13-58 Float traps. 13-53. 13-54 Floating barges, IS-34 Floating drilling operation or system. 18-3, 18-11, 18-14, IS-16 Floating drilling rigs or vessels, 18-2, 18-6. 18-10, 18-13, 18-17. 18-20, 18-31, 18-34 Floating drilling, subsea systems. IS-19 Floating platforms. 3-38 Floating drilling vessels, 3-39 Floating production facilities (FPF). applications, 18-34, IS-35 disposal of oil, gas, and water, 18-36 semisubmersibles vs. tankers, 18.35, 18-36 under Coast Guard jurisdiction, 18-44 Floating-roof tanks, 11-2. I l-6 Floatless level controller, 13-53 Floatless level controls, 13-54 Flocculation, 19-9, 19-10, 19-28. 44-46 Flood coverage, 39-18, 44-18 Flood efficiency. 39-18, 44-46 Flood fronts, 4416 Flood pot tests, 40-16. 40-17 Florida, 24-20. 24-21, 29-7, 29-8, 44-36 Flotation, 15-20, 19-28 Flow-after-flow, 33-4 Flow channels, 26-10. 55-l Flow coefficient, 34-3 I Flow computer. 5-53 Flow conductivity. 28-2 Flow-control devices, safety shut-in systems. control systems, 3-31. 3-33. 3-34 introduction. 3- I8 production platform, 3- I9
33
SUBJECT INDEX
regulations, 3-34 sensors, 3-34 subsurface safety valves, 3-26, 3-27, 3-29, 3-31 surface safety valves. 3-21 with hydra&c and pneumatic valves, 3-20 Flow-control valve, 16-l 1 Flow-direction change to remove oil from gas, 12-9 Flow m annulus. 41-42 Flow in tubing. gas, 34-9 to 34-27 Flow-measurement pulsed-data transmission systems, 174 Flow nozzle flowmeter, 32-13 Flow provers. 32-14 Flow rate, eqmvalent total, 35-2 Flow rate. units and conversions, 58-31 Flow regimes. 34-36 to 34-38, 34-40 Flow-strmg sizes, table, 34-23 Flow-string weights, table. 34-23 Flow surges, 12-20 Flow systems of combinations of beds, 26.14, 26-15 Flow systems of simple geometry, horizontal flow. 26. I I, 26-12 radial flow, 26-13 vertical flow, 26-12. 26-13 Flow-temperature gradient correlation, 5-26, 5-21 Flow-test data on a well, 30-l I 10 30-13 Flow through chokes. 34-45. 3446 Flow through pores of various sizes. 54-10 Flow velocities for pumps, 15-17 Flow velocity change to remove oil from gas, 12-9 Flow velocity. effect on acid reaction rate, 54-5 Flowing BHP. gas, calculation of, 34-9 to 34-27 Flowmg gas column, 34-9 Flowing gas wells, 34-23, 34-29 Flowing-pressure-at-depth traverse. 5-23, 5-26 Flowing pressure gradient, 5-l. 5-32, 5-43. 44-33 Flowing pressure gradient curves, 5-25, S-26, 5-30, 5-43 Flowing pressure surveys, 5-43 Flowing pressure traverses, 5-21, 5-23 Flowing production pressure at depth, 5-45 Flowing production pressure. gas-lifl valve. 5-17 to 5-19, 5-21, 5-23, S-24, 5-26 to 5-28, 5-30 to 5-33. 5-35. 5-36. 5-41 to 543, 545, 546, 5-48 Flowing production transfer pressure, 5-33, 5-34, 5-36 Flowing temperature adjustment factor. 33-15 Flowing temperature factor, 13-3. 13-13 Flowing wellhead backpressure, 5-54 Flowing wellhead production pressure, 5-53 Flowlme backpressure, 6-25 Flowline breaks. I6- 11 Flowlme choke. 5-53, 5-54 Flowline headers, 3-21 Flowlme pressure, 6-25, 6-43 Flowline-pressure term, 6-28 Flowline sampling. 24-3, 24-4 Flowline temperature, 52-22 lo 52-24 Flowlines m subsea completions, 18-33. 18.34, 18-36 to 18.38 Flowmeters, 32-6. 32-10, 32-13 Flue gas, 45-1, 45-4, 45-6, 46-21 Fluid channel gradient, 3 l-5 Fluid coefficient, 55-2 to 55-4 Fluid columns, specific gravities and unit pressure of, 6-22, 6-23 Fluid composition. 51-7. 51-8 Fluid conductivity. 26-10. 26-28 Fluid-content investigation, 49-26, 49-27
Fluid-controlled valves, 16-3. 16-4 Fluid controls, 6-51 Fluid data, ESP, 7-9 Fluid distributions. 442 to 44-4, 44-l 1 Fluid-electric-controlled valves, 16-3 Fluid-flow effects on waterflooding. 44-29 Fluid-flow model, 4420, 4421 Fluid/fluid interstitial configurations. 28-3 Fluid friction in hydraulic pumps, 6-19, 6-20 Fluid friction in sandstone reservoirs, 56-2 Fluid friction in tubular and annular flow passages, 6-26 Fluid-friction losses, 6-5, 6-25, 6-47, 6-49 to 6-5 I, 6-67. 6-69 Fluid-gradient calculations, 6-26 Fluid identification. 50-2, 50-3 Fluid incompressibility, 51-49 Fluid-inventory equations, 43-9 Fluid jet, 8-7 Fluid level in well, 30-7, 30-8, 30-15 Fluid-loss additives, 55-4 Fluid-loss agents, 54-8 Fluid-loss characteristics of fracturing fluids, 55-2, 55-7, 55-8 Fluid-loss-controlled fluids, 55-4 Fluid mapper, 44-20 Fluid mobility. 39-20. 44-7, 51-47, 52-14 Fluid pound, 10-5, IO-6 Fluid power, 6-15 Fluid pressure differences, 56-2 Fluid pressure regulator, 13-54 Fluid properties, data, 37-16 gas and liquid FVF, 6-67 to 6-69 gravity, 6-67 introduction. 6-66 oil systems. 22-l viscosity, 6-67 Fluid pumpoff chart, ESP, 7-15 Fluid sample analysis, 41-8 Fluid saturation configurations. 28-2 Fluid saturation distributions. 28-2, 46-2 Fluid saturations, comparison of methods of measurement, 26-24 to 26-27 determination from rock samples. 26-2 I, 26-22 interstitial water, 26-22 to 26-24 laboratory measurement of capillary pressure, 26-24 of cores, factors affectmg, 26-20, 26-21 of reservoir for waterflooding, 46-3, 46-4 Fluid viscosrty, 6-27 Fluids in motion, energy relatlonships, 34-1, 34-2 irreversibility losses, 34-2, 34-3 Flume pope. 19-21 Fluoboric acid system, 54-4, 54-l 1 Fluorescence X-ray, 50-7 Fluoride, 19-10, 56-I Fluoride mtensitier, 54-4 Fluosilicates, 54-4, 56-4 Flushing agent, lo- 13 Flushing efficiency. 39-18 Flux-gate magnetometer, 5 l-28 Flux leakage. 53-20 to 53-23, 53-26 Flywheel, 10-15. IO-19 Foam, 18-47. 19-23. 32-7. 45-8 Foam flooding, 47. I, 47-6 to 47-9 Foam quality. 55-6 Foam separator, 12-18 Foam stability. 47-7 Foaming agents. 39-16. 55-6 Foaming in desulfurizer. 14-22 Foaming oil, 12-3. 12-6, 12-7, 12-13, 12.17. 12-19 to 12.22, 12.32, 12-35 Foams as fracturing fluids, 55-6. 55-7, 55-9
Focused electrical-resistivity devices, 26-31 Focused-electrode devices, 49-l I. 49-18 Focused-electrode logs, 49-18 to 49-22 Folded structure, 53-12 Force balance equations, 5-13 Force balance m downhole pumps, 6-16 to 6- 19 Force of gravity, 58-3 Force summing devices, 30-1, 30-2, 30-6 Force, unit and definition, 58- 1I, 58-23, 58-24, 58-34 Forced-circulation heating. 19-22 Forced-draft burners, 19-28 Forchheimer equation, 35. I I Fordoche field, Louisiana, 39-16 Forecast of future rate of production, constant percentage decline, 41-9, 41-10 declining production, 41-9 harmonic decline, 41-10 hyperbolic decline, 41-10 part constant rate-part declining production, 41-10, 41-11 produced product prices, 41-I 1 proration of market curtailment. 41-I I Foreign objects in flow string, 33-20, 33-22 Forest Hill field, Texas, 46-3 1, 46-34 Formation. analysis, in sand control, 56-3 damage, 56-4, 56-8 properties, in sand control, 56-2 sampling, in sand control. 56-3 Formation alteration, effect on log measurements, 51-20 to 5 l-23 Formation balance gradient, 52-25, 52.26 Formation compaction, 26-8 Formation composition, effect on acid reaction rate, 54-6 Formation compressibility, 40-34 Formation compressibihty vs. depth, 26-7 Formation conductivity. 54-8, 54-9 Formation damage, 4-9. 30-8, 35-4, 39-25, 51-21, 54-8 to 54-10 Formation density log. 52-20 Formation drillability exponent, 52-24 Formation evaluation, 5 l-l, 5148 Formation evaluation letter and computer symbols, 59-2 to 59-51 Formation evaluation services, 52-2 to 52-l 1 Formation factor, dependence on porosity and lithology, 49-4 evaluation, 49-14, 49-26, 49-30 Formation fluid pressure, 51-39 Formation fracturing, fluid-loss-controlled fluids, 55-4 formations fractured, 55-2 fracture area, 55-2, 55-3 fracture planes, 55-2 fracturing equipment. 55-9 fracturing materials. 55-5 to 55-8 fracturing techniques, 55-8, 55-9 general references, 55-10 to 55-12 hydraulic fracturmg theory, 55-l. 55-2 introduction, 55-l multiple-zone fracturing, 55-9 operations. 8-8 references. 55-10 reservoir-controlled fluids, 55-2, 55-4 , stimulation results, 55-4. 55-5 treatment planning, 55-9. 55-10 viscosity-controlled tluids, 55-4 Formation of an emulsion, 19-2. 19.3 Formation permeability. 50-2 Formation pore pressure, 52-17 Formation pressure gradient, 5 l-39 Formation resistivity factor, 26-28 to 26-31, 49-4 Formation shear-wave velocity, 51.25 Formation tests. 40-3
PETROLEUM
Formation transit time, 51-19, 51-20 Formation volume, of gas plus liquid phases, 21-19 of well production at reservoir conditions, 21-20 total. gas-condensate system, 21-16, 21-18 total by Standing’s correlation, 21-19 Formation volume correlations, 21-15 to 21-20 Formation volume factor (FVF) of gas, 6-67, 20-11, 20-16. 22-13, 22-20. 37-16, 39-14, 39-23, 40-5, 40-7, 40-9, 40-22 to 40-24 FVF of gas plus liquid phase, 6-47 FVF of oil, 6-67. 22-l. 22-10 to 22-13, 22-20, 37-16, 40-6, 40-8, 40-9, 40-l 1, 40-16 FVF of water, 24-15, 24-16 FVF, total (two-phase), 6-47, 6-68, 22-l. 22-13, 22-14; 22-20 FVF’s vs. pressure, 37-16 Formation water, definition, 24-18 Formation water density, 24-14 Formation water resistivity, 24-14, 24.16,494 Formation water sample, 24-3 Formation water viscosity. 24-16, 24-17 Formations fractured, 55-2 Formazin polymer, 44-44 Formazin turbidity units (FTU), 44-44 Formic acid (HCOOH) in acidizing, 54-3, 54-8, 54-10 Forms of meter, 13-2 Formulation sequential. 48-14 FORTRAN IV, 17-6, 17-7 FORTRAN card deck, 17-5 FORTRAN source code listing, 9-3 Fossil water. 24-2 Foster field, Texas. 44-30 Foundations for pump and prime mover, 15-18 Foundations of pumping units, IO-7 Four-arm caliper, 53- I7 Four-arm dipmeter tools, 53-8, 53-10 Four-cycle engine, IO-14 to 10-16, IO-19 Four-stage separation, 12-34 Four-way engine valves, 6-9 Fourier heat equation, 26-16 F, values for various annuli, 33-17 F, values for various flow strings, 33-16 Fractional analyses, 39-2 Fractional-flow curve, 40-14, 43-10, 43-l I, 44-12 Fractional-flow equation, 40-17, 43-3, 43-5, 43-10, 44-4, 44-9, ‘M-10 Fractional flow of gas. 40-14, 43-6, 43-8 Fractional horsepower motors, 18-46 Fractional oil recovery, 44-9 Fractional water cut, 44-8 Fractionation, 39-27 Fractionation equipment, 39-5 Fracture acid&g: 54-9, 54-l 1 Fracture area, 55-2, 55-3 Fracture-assisted steamflood, 46-26 Fracture conductivity, 54-8, 54-9. 55-4, 55-8. 55-9 Fracture conductivity ratio, 55-4 Fracture evaluation, 5145 to 51-47 Fracture flow capacity, 55-8 Fracture-fluid efficiency, 55-4 Fracture geometry, 55-5, 55-9 Fracture gradient, 55-2 Fracture of pipe, 2-60 Fracture penetration, 55-4, 55-9 Fracture planes. 55-2 Fracture porosity. 44-2 Fracture pressures, 44-3, 44-46, 5 1-44 Fracture strength of casing, 2-61 Fractured-matrix imbibition. 48-9 Fractured matrix model. 48-5
Fractured porosity, 29-8 Fractures, ‘perme&ility of, 26- I6 Fracturing: See Formation fracturing Fracturing, 26-2. 40-23, 40-24. 51-44, 56-l Fracturing efficiency, 55-9 Fracturing equipment, 55-9 Fracturing fluids, comparative efficiency, 55-9 early treatments with, 55-l effective volume of, 55-2 foams, 55-6. 55-7 gelled-oil, 55-7 heavy oil-in-water emulsions, 55-7 high-viscosity, 55-8 leakoff, 55-4 mixed-base, 55-7 oil-base, 55-5 oil-in-water dispersion, 55-7 rate of leakoff controlled by viscosity, 55-4 viscosity of, 55-2 viscous emulsion, 55-8 volume of, 55-3 water-base, 55-5 to 55-7 Fracturing materials, fluids, 55-5 to 55-8 propping agents, 55-8 selection, 55-9 Fracturing pressure, 54-10, 54-l 1, 56-5 Fracturing pressure gradients, 55-2 Fracturing techniques, 55-8, 55-9 France, l-68, 12-39, 46-3, 46-27 to 46-29 Frangible-roof tanks, I l-2 Frax log analysis, 49-37 Free condensate, 14-5 Free gas, 6-2, 6-38, 6-39, 6-47, 6-50, 6-57, 6-62, 8-10. 12-3, 22-1, 22-9, 37-1, 37-2, 37-5, 40-5, 40-8, 40-13, 40-22 to 40-24, 40-33, 44-4 Free-gas cap, 40-6 to 40-8, 40-10 Free-gas production, 37-2 Free-gas production rate, 37-11 Free-gas saturation, 37-22, 40-19, 44-4, 44-5 Free pump cycle, 6-3, 6-6 Free pump installations, 6-3, 6-4 Free-standing risers, 18-15 Free-stretch factor of casing, 2-35 Free water. 14-3, 14-5, 14-6, 14-17, 14-20, 19-9, 19-17, 19-24. 19-25 Free water knockout (FWKO), 12-3, 12-4, 12-13, 15-21, 18-28, 19-9, 19-17 to 19-19, 19-22, 19-32 Freezing point, 14-2, 14-6. 14-10, 14-19, 21-19, 25-19 Freezing problem, 13-53 French design, concrete structures, 18-23 French Nat]. Assembly, l-68 Freon 12. 14-9 Frequency of wave, 51-14 Frequent; response. 30-5, 30-6 Frequency, unit and definition, 58-11. J8-23; 58-36 Fresh core techniques, 44-5 Fresh mud, 49-20, 49-25, 49-27 Fresh water, 44-41, 44-42 Freshwater buffer, MP flooding, 47-10 Freshwater recharge, 24-20 Friction coefficient, 9-9 Friction factor, 15-l to 15-3. 15-5 to 15-7, 15-10, 34-2, 34-3, 34-24, 34-38, 34-39, 39-25 Friction in downhole pumps, 6-21 Friction loss, 13-2 Friction loss curves, 55-6, 55-7 Friction loss gradient, 34-36, 34-38 to 34-40 Friction losses, 46-29 Friction pressure, 55-5, 55-6
ENGINEERING
HANDBOOK
Friction pressure-drop curves, 6-26, 6-70,6-7 1 Friction relationships, annular sections-flow between tubing and casing, 6-69 to 6-72 circular sections-tubing, 6-69 pressure drop in tubing annular flow, 6-70, 6-71 Friction wheel engine starters, IO-19 Frictional horsepower, 10-18, lo-19 Frictional press&e drop or loss, 6-1, 6-18 to 6-20, 6-25, 6-35, 46-7 Fritted glass, 26-6, 26-24 Front displacement models, Mandl-Volek’s refinement of MarxLangenheim method, 46-8 Marx-Langenheim method, 46-7, 46-8 Ramey’s generalization of MarxLangenheim method, 46-8 Frontal-advance applications, 43-16 Frontal-advance calculation, 43-12, 44-9 to 44-11 Frontal-advance equation, 40- 14, 40- 17, 40-18, 4410 Frontal-advance performance, 43-12 Frontal advance theory, 44-7 Frontal-drive method, for oil reservoir with gas-cap drive, 40-13, 40-14 for oil reservoir with water drive, 40-17, 40-18 Frost heaving, 18-41 Frost point, 25-5 Fry pool, Texas, 44-1 Fuel availability for engines, lo-16 Fuel consumption, 10-17, 58-33 Fuel content as performance indicator, tirefloods, 46-16 Fuel-gas scrubbers, 19-28 Fugacity coefficient, 25- 11 Fugacity of hydrate, 25-l 1 Full-bore flowline valves, 3-12 to 3-14 Full-capacitv relief valves, 12-40 Full-dime&r core analysis, 27-1, 27-8 Full-diameter core method, 26-17 Full diesels, lo-15 Full-interest wells, 57-9 Full-line injection-gas pressure, 5-53 Full-load rating of motor, 10-26, 10-28, IO-30 Full-load slip, lo-24 Fullerton-Clearfolk unit, California. 36-7 Fully implicit formulation. 48-14 Fungi, 44-43, 44-44 Funicular distribution, 26-24 Fuses for motors, lo-28 Fusible plugs for fire detection, 18-47 Future inflow performance, 34-34, 34-35 Future net cash income, 41-5, 41-6 Future performance calculations, 43-10 to 43-16 Future performance, water-drive reservoirs, pressure gradient between new and original front positions, 38-13, 38-14 reservoir above bubblepoint pressure, 38-14 reservoir below bubblepoint pressure, 38-14 to 38-16 reservoir simulation models, 38-16 G Galling, 6-50 Galvanic anodes, 19-3 1 Galvanic corrosion, 3-36 Galvanized coating, 1l-6 Galvanized wire armor, 18-49 Gamma-gamma density devices, 50-7, 50-15 to 50-17, 50-26 to 50-28, 50-37 Gamma probability function, 39-l 1 Gamma radiation, 50-3
SUBJECT INDEX
Gamma ray absorption, 50-2, 50-13 Gamma ray attenuation, 50-2, 504 Gamma ray curve and log, 364, 46-27, 49-15, 49-19, 49-20, 49-25, 49-38, 49-39, 50-15, 50-24 to 50-27, 51-16, 51-17, 51-19, 51-23, 51-26, 51-27, 51-33, 51-38, 5145, 53-2, 534, 53-26 Gamma ray detection, 50-14, 50-23 Gamma ray devices, 50-15, 50-16 Gamma ray emission spectra, 50-15, 50-17 Gamma ray energy, 50-7, 50-13, SO-15 Gamma ray flux, geometry for, 50-16 Gamma ray index, 50-24 Gamma ray interactions, 50-6 to 50-8, 50-12, 50-14 Gamma ray measurements, 50-24 to 50-26 Gamma ray spectroscopy, 50-2, 50-3, 50-12, 50-13, 50-22, 50-24, 50-35 Garden Banks platform, 18-2 Gas analysis, 52-17, 52-18 Gas analysis system, 52-3 Gas anchors, 8-9, S-10 Gas and oil differences, 36-2 Gas backpressure valve, 124, 12-5, 12-9 Gas boot, 6-33, 6-57 to 6-59, 19-13, 19-18, 19-21 Gas break-out, 16-14 Gas breakthrough, 43-3, 43-5, 43-8, 43-9 Gas cap, 37-2, 37-3, 37-5 to 37-8, 37-13 to 37-17, 39-5, 40-5 Gas-cap drive, 36-2, 37-1,40-g, 40-13, 40-14 Gas-cap-drive reservoirs, 43-9, 42-5 Gas-cap encroachment, 36-2 Gas-cap expansion, 43-12, 43-15, 43-16 Gas-cap gas expansion. 37-5 Gas-cap gas production, 37-5 Gas cap in vessel, 6-62 Gas-cap injection, 43-3 Gas cap/oil production, 37-10 Gas-cap reservoir, 46-24 to 46-26 Gas capacity chart, 5-8 Gas capacity of separators, 12-23 to 12-25, 12-27 to 12-29, 12-31, 12-32 Gas chromatography, 27-1, 52-5 Gas compressibility, 36-2 Gas compressibility factor, 5-8, 5-l 1, 12-22, 12-23, 12-25, 12-26, 12-29, 12-30, 20-4, 20-7, 20-8, 20-10, 20-11, 20-14, 22-13, 4645 Gas/condensate ratio, 39-5 Gas-condensate recovery, 39-13 Gas-condensate reservoirs, economics of operation, 39-26, 39-27 formation and fluid data for, 39- 11 general operating problems, 39-24 to 39-26 introduction, 39-1 nomenclature, 39-27 operation by pressure depletion, 39-10 to 39-15 operation by pressure maintenance or cycling, 39-15 to 39-24 properties and behavior, 39-l to 394 references, 39-27, 39-28 sample collection and evaluation, 39-6 to 39-10 well tests and sampling, 394 to 39-6 Gas condensate systems. 20-4. 21-16 to 21-20, 22-l Gas-condensate wells, 3-36, 3-37, 334. 34-37, 34-28, 34-36 Gas condensates, 20- 11, 40- 13, 40-24 Gas coning, 32-3, 37-2, 37-13, 48-6 Gas cushion, 19-17, 19-18 Gas cutting, 1847 Gas cycling, 34-28, 45-13, 45-14 Gas cyclone, 12-20
3.5
Gas deliverability approach, 35-12 Gas-depletion drive, 29-7 Gas de&ion factor, definition, 22-20 Gas-discharge counters, 50-12 Gas discharge radiation detector, 50-12 Gas displacement, 43-3 to 43-6, 43-8, 43-16 Gas disposal, 18-30 Gas distribution system, 12-38 Gas drive, 46-3, 46-5 Gas effect, on acoustic log, 51-37 on velocity ratio, 51-38 Gas effect on neutron porosity, 50-30, 50-31 Gas eliminators, 15-14 Gas evolution, 37-22, 37-23 Gas expansion, 37-6 Gas expansion factor, 39-l 1, 40-7 Gas-expansion method of determining porosity, 26-6 Gas-expansion porosimeter, 26-6 Gas exsolution, 52-14 Gas extraction methods. 52-2 Gas filter, 12-1, 12-2 Gas-tired crude oil heating unit, 19-28 Gas flaring, 18-30 Gas flotation units, 15-27 Gas-flow computers, 16-6, 16-12 Gas flow, Weymouth formula, chart, 15-8, 15-9 Gas formation volume factor (FVF), 6-67, 20-l 1, 20-16, 22-13, 22-20, 37-16, 39-14, 39-23, 40-5, 40-7, 40-9, 40-22 to 40-24 Gas-free hydraulic loop, 18-34 Gas-free viscosity, 22-14. 22-15 Gas fuel consumption, 39-24 Gas fundamentals as applied to gas lift, gas pressure at depth, 5-3 to 5-6 gas volume stored in conduit, 5-11, 5-12 introduction. 5-3 temperature effect on confined bellowscharged dome pressure, 5-6 to 5-8 volumetric gas throughput of a choke or gas lift valve port, 5-8 to 5-10 Gas/gas interface, 39-21 Gas-gathering facilities, 5-53 Gas-gathering system, 12-10, 12-11, 12-33 Gas gravities of natural gases, table, 25-6 Gas-gravity/condensate-gas ratio, 34-28 Gas gravity, definition, 22-20 Gas handling, approximation for, 6-38, 6-39 Gas-hydrate equilibrium locus, 25-2 Gas hydrate region, oil and gas reservoirs that exist in, 25-18, 25-19 Gas in effluent oil, 12-15, 12-16 Gas in place, by material balance, 40-6, 40-7 by volumetric method, 40-5, 40-6 in reservoir containing nonassociated gas and interstitial water but no residual oil, 40-23 Gas injection, 42-5, 43-16 Gas injection, BHP calculation, 34-28 to 34-30 Gas injection data, 39-23 Gas-injection operations, 43-2, 43-3, 43-7, 43-9, 43-17 Gas-injection performation, 43-5, 43-16 Gas injection pressure maintenance in oil reservoirs, calculation of performance. 43-8 to 43-10 efficiencies of oil recovery by gas displacement, 43-3 example calculations of future performance, 43-10 to 43-16 introduction, 43-I. 43-2
methods of evaluating areal sweep efficiency, 43-7, 43-8 methods of evaluating conformance efficiency. 43-6, 43-7 methods of evaluating displacement efficiency, 43-3 to 43-6 nomenclature, 43- 18 optimal time to initiate, 43-3 references, 43-16, 43-17, 43-19 types of gas-injection operations, 43-2,43-3 Gas interference, 6-21, 6-22, 6-24 Gas law constants, 20-2 Gas liberation, 37-3 Gas lift, charts, 643 continuous flow, 5-21 to 5-38, 3440 to 3445 design procedures, 3440. 34-41 designing installations, 34-28 gas fundamentals as applied to, 5-3 to 5-12 intermittent flow, 5-38 to 5-53 introduction, 5-l to 5-3 nomenclature, 5-55 operations, description of. 5-I performance, 34-44 references, 5-57 unloading procedures and proper adjustment of injection gas, 5-53 to 5-55 valve mechanics, 5-12 to 5-21 valves, 6-2, 6-6, 18-28, 18-34 well control, 16-11 wells, energy losses, 34-37 wells, tubing profile caliper, 53-17 Gas-lifting methods, 44-42 Gas/liquid/hydrate equilibrium, 25-5 Gas/liquid ratio (GLR), 5-23, 5-25, 5-26, 5-34, 5-36, 5-38, 543, 6-27, 6-29, 6-30, 6-35, 641, 642, 644, 12-21, 12-22, 39-2 to 39-6, 39-10 Gas/liquid relative permeability data, 39-7 Gas lock, 7-4, 7-6, 7-10, 7-15, 7-16 Gas lock breakers, 6-21 Gas lock chart, ESP, 7-15 Gas locking, 6-10, 6-21, 8-9 Gas measurement, automatic. of lease equipment, 16-6, 16-7 flow nipple and pitot tube for, 33-2 general references, 13-59 instruments, 33-13 introduction, 13-l metering systems, 13-37 orifice constants, 13-3 to 13-35 physical setup of system for, 13-36, 13-37 references, 13-59 velocity meters, 13-l to 13-3 Gas mobility, 37-3, 39-25, 43-7 Gas motor engine starters, IO-19 Gas/oil contact, 26-25, 404, 40-14, 40-15. 41-9, 46-26 Gas/oil flow through chokes, 34-47 to 3449 Gas/oil interface, 1847, 50-36 Gas/oil interfacial tension (IFT), 22-16, 22-17 Gas/oil ratio (GOR). 5-25, 5-26, 6-24, 6-25, 6-29, 6-30, 6-38, 6-39, 6-44, 6-47, 12-35, 22-20, 34-41 to 3443, 3447 to 3449, 38-16, 39-1, 39-2, 40-33, 41-8, 44-39, 58-38 Gas/oil relative permeability, 28-9 Gas/oil relative permeability ratio, 37-1, 37-2, 39-13 Gas/oil separator, 22-20 Gas override, 48-12 Gas passage charts, 5-8 to 5-10 Gas payment, definition. 41-l Gas permeability, 39-13, 39-25, 47-9 Gas-plus-liquid FVF, 6-38 Gas pressure at depth, charts, 5-3, 5-6 factors for approximating, 5-5, 5-6, 5-l I
36
injectton curves. 5-S static injection calculations, 5-3 to 5-6 Gas-pressure-at-depth factor, 5-5, 5-6, 5-49 Gas pressure function. 37-8 to 37-10 Gas pressuremaintenance performance. 43-8 to 43- 10 Gas price. gross, 41-9 Gas processing plants. 40-3 Gas Processors Assn. (CPA), 20-8, 25-9 Gas Processors Suppliers Assn. (GPSA), 20-S Gas-producing intervals, location of, 31-4, 31-6 Gas properties and correlations, Amagat’s law, 20-4 Calingeart and Davis equation, 20-13 coeffictent of isothermal compressibility. 20-11 Cox chart, 20-12, 20-13 critical temperature and pressure, 20-2. 20-3 Dalton’s law, 20-4 equations of state, 20-6, 20-7 example problems, 20-13 to 20-17 formation volume factor, 20. I 1 ideal gas, 20-l. 20-2 Lee-Kessler equation, 20- 13 mole fraction and apparent MW of gas mixtures. 20-4 molecular weight, 20-I. 20-3 natural gasoline content of gas, 20-10, 20-11 principles of corresponding states, 20-4 real gases. 20-4 IO 20-6 references. 20-18 van der Waals’ equation, 20-7 to 20-9 specific gravity (relative density), 20-4 specific gravity of gas mixtures, 20-4 vapor pressure, 20-3, 20-l I . 20- I2 viscosity, 20-9 viscosity correlations, 20-9, 20-10 Gas properties, effect on gas well performance. 35-10 Gas property ownershtp, 41-1, 41-2 Gas-purchase contracts, 41-3, 41-9 Gas quality from scrubbers, 12-15 Gas recoveries by natural water drive or gas Injection, 39-16 Gas regulation, definitions, 1349. 13-50 field compressors, control of, 13-57 to 13-59 high-pressure service, 13-55, 13-56 liquid-level control, 13-53, 13-54 lowpressure service, 13-55 principles of control. I349 process characteristics, 13-50 to 13-53 references, 13-59 regulators. types of, 13-54 to 13-57 Gas regulator, IO-19 Gas relative permeability, 28-8 to 28-12, 40-25, 40-26 Gas relative permeability vs. total wettingthud saturation, 28-8 Gas reserves: See also Reserves Gas reservoir, development plan for, 36-l to 36-l 1 infinite acting, 35-l 1, 35-12 Gas reservoirs, depletion technique, 36-2, 36-3 free gas in, 40-5 in gas hydrate region. 25-18, 25-19 nonassociated, material balance recovery estimates. 40-33, 40-34 nonassociated, volumetric recovery estimates, 40-2 1 to 40-26 with water drive, 40-7, 40-26 without water drive, 40-24, 40-25, 40-33 Gas richness indicator, 524
PETROLEUM
Gas sales contract, 12-33, 14-l Gas sales Ime. 3-19 Gas-saturated crude oil. 22-15 Gas scrubbers, 12-l. 12-10. 12-I 1, 12-20 to 12-22, 12-35. 12-38. 1828 Gas separator to remedy gas locking. 7-16 Gas shows. total, 52-13 to 52-16, 52-18 Gas sizing of separator. 12-30 Gas slippage. effect on permeability measurements. 26-18, 26-19 Gas-slippage effects, study required, 28-13 Gas solubility. 40-9 Gas solubility in oil, 22-21 Gas stripping, 15-29 Gas sweeteners. 12-35 Gas throughput performance, 5-22 Gas-to-gas heat exchanger, 14-5 to 14-8, 14.il.
14-14,
14-15, 14-20
Gas-transmission-line pressure, 14- 15 Gas transmission lines, 12-38 Gas transmission piping specs., 15-12 Gas trap, 52-2 Gas-treating systems, 14-17 IO 14-22 Gas turbine meters, 16-6 Gas turbines. 15-16, 15-17, 46-19 Gas-vent string, 6-4 Gas venting passage, 6-2. 6-5 Gas viscosity. 40-9, 44-6 Gas volume stored. in casing annulus. within a conduit. 5-l I. 5-12, Gas/water contact, 39-2 I Gas/water flow. 34-27 Gas/water interface. 39-21. 39-22 Gas well inflow equation, 33-5 to 33-7 Gas well performance, deterioration causes. 33-20 to 33-22 gas properties, effect of, 35-10 Infinite-acting gas reservoir, 35-l 1. 35-12 long-term forecast, 35-12 non-Darcy flow. 35-10. 35-l I pseudosteady-state solutions. 35-12 Gas wells. Bow through tubing-casing annulus, 34-27 flowing BHP calculation, 34-9 to 34-27 not suitable for TFL servtce, IS-34 openflow, 33-l to 33-23 static BHP calculation, 34-3 to 34-9 Gasoline as four-cycle engine fuel, lo-15 Gasoline content, 39-1, 39-5 Gasoline-driven engine starters, IO-19 Gasoline-plant recovery effictency, 45- 12 to 45-15 Gasoline plants, 11-13, 40-13, 41-3, 57-5 Gasoline/water system, 25-27 Gassmann-Blot theory, 5 l-36 Gassmann’s theory, 51-8 Gassy conditions. ESP chart. 7-16 Gassy fluid, 6-21 Gassy wells, 6-28. 6-34 Gate valves, 3-l 1 to 3-13, 3-21 Gathering systems, I I-13. 40-l Gauge cocks. 12-42 Gauge glasses, 12-42 Gauge location factor, 13-8. 13-35 Gauge tables, correcting for incrustation, 17-3 Gauging petroleum and petroleum products, 17-3 Gaussian elimination. 48-16 Gear pump, 19-5 Gear reducer, IO-2 to 10-6, 10.12, lo-13 Gear reduction units, 6-50 Gearhart, 49-2. 49-36. 49-37 Geiger-Mtiller tube. 50-16 Gel or gelatin model, 39.21, 4417. 44-18. 4420, 4421 Gel slugs. 54-10 Gel strength. 58-34
ENGINEERING
HANDBOOK
Gelled-oil fracturing fluid, 55-7 Gelled water in acidizing. 54-12 Gelling agents, 54-8 Gels as fracturing fluids, 55-5, 55-6 General Conference on Weights and Measures. l-69 General crude. 46-16. 46-18. 46-21 General flow equations, 13-I General overhead (GO), 41-14 General Petroleum Co.. 46-14 to 46-15 General principles of acidizing, acetic and formic acids, 54-3 hydrochloric acid, 54-l to 54-3 hydrofluoric acid, 54-3. 544 General references: See also References. acidizing, 54-12 to 54-14 automation of lease equipment. 16.16. 16.17 crude oil emulsions, 19-33. 19-34 electric submersible pumps, 7.17 electrical logging, 49-4 1, 49-42 estimation of oil and gas reserves, 40.38 formation fracturing, 55-10 to 55-12 gas-injection pressure maintenance in oil reservoirs, 43-16, 43-17 gas measurement and regulation, 13.59 hydrate/volatile-gas systems, 2527. 25-28 miscible displacement, 45-15 mud logging, 52-30 oil and gas leases, 57-12 petroleum reservoir traps. 29-9 phase behavior of water/hydrocarbon systems, 25-24 to 25-28 relative permeability. 28-16 reservoir simulation, 48-20 sucker rods. 9-14 temperature in welis. 31-7 thermal recovery. 46-45. 4646 valuation of oil and gas reserves, 41-37 water-drive oil reservoirs. 38-20 water-injection pressure maintenance and waterflood processes. 44-52 water/volatile-gas systems. 25-24 to 25-27 wellhead equipment and flow-control devices, 3-40 Generator voltage, IO-2 I Geochemical analysis, 52. I, 52-2 Geochemical model, 24-20 Geochemical parameters. 50-37 Geochemical water analyses, 24-5 Geochemistry. 50-36, 50-37 Geochronology, 58-25 Geodetic surveys, l-69 GEODIP log analysis. 49-37 Geographical distribution of thermal recovery projects, 46-3 Geological analysis, 52-2, 52-7 to 52-9, 52-28 GeologIcal correlation, 5 l-29, 5 I-30 Geological interpretation. 51-28. 51-29 Geological map, 40-4 Geologists, 57-8 Geology, in oil and gas reservoirs development, carbonate reservoirs, 36-5, 36-6 elastic reservoirs, 36-3, 36-4 paleo-environments, interpretanon of, 36-3 shale stringers. extent of, 36-6 Geology in sand control. 56-2 Geometric-mean air permeabilities. 4437 Geometric progression, 6-39 Geometric series. 40-30 Geometric spread of energy, 5 l-3 Geometric spreading, 51-12. 51-13 Geometrical factor, 49. I6 to 49. I8 1 49-22 Geometrical spreading factor. 5 1~I3 Geometrical spreading loss. 49-34 Geophysics, in characterizmg reservoirs, 3b-8. 36-Y
SUBJECT
INDEX
Geopressure detection, 5 l-39 Geopressure evaluation, 52.2, 52-16 to 52-26 Geopressure gradient, 52-25 Geopressure transition zone, 52-24 Geopreasured shales, 52-22 Geopressured zone, 52-22 to 52-24 Geoiechnical analysis, 18-41 Geothermal gradient, assumed to estimate BHT, 31-6 basis for pressure-at-depth curves, 5-5 definition of, 52-22 in sedimentary basins, 31-2 in southwest U.S.. 31-3 increased, 5-23 linear, 46-5 temperature protile, 4-6 Geothermal temperature. 5-26 Geothermal temperature gradient, 5-6 Geothermics, 58-33 Germanium (Ge) detector, 50-14. 50-23 Germany. 12-39. 46-3 Getting ;he well drilled, 57-8 Gettv Oil Co.. 46-4, 46-14, 46-15, 46-18, 46-20, 46-23. 46-24 Gibbs theory, 47-8, 47-l I Gilbert’s equation. 34-45. 34-46 Gippsland basin. Australia, 27-19 Clash wool. 19-14 Glauconite. 46-21 Glen Hummel field. Texas, 46-15, 46-18 Glenpool field. Oklahoma, 54-l GLOBAL log analysis. 49-37 Gloriana field, Texas. 46-15, 46-29 to 46-32 Glossary of terms, reserves estimation. crude oil, 40-3 improved recovery, 40-4 natural gas, 40-3 natural gas liquids, 40-3 possible reserves, 40-4 probable reserves, 40-4 reservoir, 40-3 Glossary of terms, petroleum reservoir traps, 29-8, 29-9 Glossary of terms. reservoir engineering phase behavior, 22-20, 22-21 Glucan. 47-3 Gluconic acid, 44-45 Glycol absorbers. 13-54. 14-18 Glycol-condensate separator, 14-7 Glycol dehydrators, 12-35. 14-18 Glycol foaming, 14-20 Glycol injection LTS system. 14-6 to 14-8, 14.14. 14-15 Glycol rcboiler, 14-6. 14-7. 14-15 Glycol/water mixture, 39-5 Glycols, 12-35. 13-36, 14-6 IO 14-E. 14-15, 14-18 to 14-20 Government authorities or agencies, 12-39, 18-44 Governmental regulations. 3-34 Governors. IO-14 Graben. 29-3, 29-8 Gradlent curves. 5-25. 5-36. 5-37 Gradienr flmd tlow, 31-4 Gradlent gas flow, 31-4 Gradient of power tluid, 6-25. 6-26, 6-29. 6-43. 6-44 Gradient of return Huid. 6-43 Gradient of well servicing fluid, 4-7 Grain density, 50-28, 50-33 Grain density test. 27-l Grain roundness factor. 55-8 Grain-bize distribution, 56-3, 56-7 Grain size of proppants. 55-X Grain size test. 27-l Grain volume: See Sand grain volume Granting clause. 57-3. 57-4
37
Graphic plots. Introduction, 24-18 Reistle diagram, 24-19 Stiff diagram. 24-19 Tickell diagram, 24-19 Graphic relationships for SI units, 58-23 Graphical correlations, 22-5, 22-7. 22-8 Grabhite. 12-41 Graphite impregnated cloth model, 39-2 I G&e-tlow’pack, 46-19 Gravel-pack completions, 47-6 Gravel-pack failure, 56-6 Gravel-pack permeabdlty improvement, 56-6 Gravel packing, 56-3. 56-5 to 56-9 Gravel quality. 56-6. 56-7 Gravel selection. 56-6. 56-7 Gravel sizes available. 56-6 Gravimetric determination of BV, 26-3 Gravimetric system, 58-3 Gravitational forces. 26-12. 26-24, 29-3 Gravitational units. 58-5 Gravity conservation with storage tanks, II-12 to II-14 Gravity drainage, 28-l I, 29-7, 37-1, 37-2, 37-5, 37-7, 37-17. 40-14, 40-15, 40-29, 41-l 1. 43-l to 43-3. 43-5 to 43-7, 43-16, 44-36, 44-39. 47-8, 484. 48-12 Gravity dump piprng, 6-62 Gravity faults, 29-3 Gravity forces, 37-l I. 44-31 Gravity losses, preventing, 1 l-12. I l-13 Gravity platform construction, 18-23, 18-24 Gravity segregation, 12-3, 37-2, 37-4, 40-8, 43-5, 43-7. 43-16. 45-7, 45-8, 48-8 Gravity separation, 6-56 to 6-59, 12-8, 12-19, 12-21, 12-23, 15-21, 19-6, 19-7, 19-13 Gravity separation devices, 15-23 Gravity settling, 15-18, 19-14, 19-15, 19-28 Gravity stabilization, 45-8 Gravity structures. 18-2, 18-3, 18-23, 18-4 I, 18-42 Gravity systems ID piping design, 15-14, 15. I5 Graywacke sediments, 29-7 Great Britain. l-70 Great Lakes. 18-l Great Salt Lake, 24-19 Grid network, 44-17 Grid orientation effects, 48-10 to 48-13 Grid spacmga. 48-8 Gridblocks, 37-2. 48-2 to 48-8, 48-10 to 48-12. 48-14. 48-15, 48-17 Gridded multiphase reservoir simulators. 37-11. 37-13, 37-14 Gridded reservoir models. 37-2, 37-5 Gridded simularor equations, 37-l I, 37-22 Gridded SLmulator studies. 37-2 Groningen gas field. Netherlands, 51-47 Grooved pin-end plunger, 8-4 Grounding of electrical system, 10-31, IO-32 Guar as thickening agent, 55-5 to 55-7 Guard-electrode device, 49-20 Guarding of pumping units. IO- I2 Guatemala. 25. I8 Guide posts, 18-19, 18-32 Guide, to number of digits to retain, 58-6 to style for metric usage. 58-l 1 Guidebase, ocean floor, 18-18. IS-19 Guidecones, 18-14 Guided wave, 51-13 Guideline tensioning systems, 18-l I, 18-13 Guidelineless drilling systems, 3-39 Guidelineless re-entry systems, 18-14 Guidelines, for marine cargo Inspection, 17-8 for offshore structure selection. 18-25 for running down BOP stack. 18-16
for selection of storage tanks, 1 I-l for use of SI units, 17-7 for wire-rope, spudding offshore wells. 18-18 susbsea system, 18-19 to BOP testing procedures, 18-12 to surveys to be performed and analyzed for offshore drilling permit, 18-5 Guides for using metric units. 58-8 Guides to acid fracture treatment design, 54-l I Gulf BHP gauge, 30-l Gulf coast. 18-2. 24-7, 24-8, 29-3, 33-21. 41-5, 47-3. 51-38, 51-39 Gulf of Mexico, 18-2, 18-3, 18-7, 18-24. 19-5, 19-15, 25-18. 29-7. 51-34, 57-l 1. 57-12 Gulf of Thailand. 36-9 Gulf Oil Corp.. 16-12, 46-15, 46-16, 46-18, 46-28 to 46-30 Gunbarrel tank, 19-20 to 19-22 Gunbarrels. 19-7, 19-18, 19-32 Guyed towers, 18-2, 18-3, 18-24. 18-25 Guyline system, 18-24, 18-25 Gypsum (gyp), 56-I. 56-2 Gyroscopes for dxectional surveys, 53-3 Gyroscopic orientation, 53-7
H h-mode telemetry, 53-I Habendum clause, 57-4 Halite, 24-20 Hall-Yarborough equation, 20-8 Hammer lugs, 3-39 Hand-held calculator, 20-7, 20-9, 20-13, 40.30 Hand-off-auto switch, IO-27 Handling ESP equipment, 7-12 Hard-wired logic, 16-1, 16-8 Hardness. 4444, 47-5, 47-10, 47-l I. 47-13 Harmonic decline. 40-29, 40-3 I, 40-32, 41-l 1, 41-12 Harmonic-decline deferment factor, 41-29. 41-31, 41-35 Harmonic voltages, 10-30. IO-32 Harrisburg field, Nebraska, 44-40, 47-22 Hassler method, 28-3, 28-5 to 28-7 Hastalloym . 7-3 Havlena and Odeh‘a method for OIP. 37-3. 38-12 Hazardous area classification, 10-36, IO-37 Hazardous areas, electrIcal syslems offshore, 18-46 Hazen-Williams equation, 15-2 HCI: See Hydrochloric acid Head, definition, 34-2 Head loss due to friction, 15-l Head meters, 13-2 Heading, in separators, 12-22. 12-31, 12-35 Heading conditions, 5-22. 5-24. 5-25, 6-60 Heading of wells. 34-46, 34-50 Heads of well fluids, 12-1, 12-32 Heal of fracture. 55-2 Healing, 47-8 Heat capacity. of rock. 46-7 of steam. 46-5 of water. 46-2 Sl units. 58-28 volumetric. 46-7. 46-10 Heat conduction, 46-4. 46-12. 48-5 Heat conductiun. transient. 46-6 Heat content. of petroleum fractions. 2 l-6 of natural gas. 14-17 Heat exchange rate. 58-38 Heat exchangers, I I-12. 1 I-13, 12-13, 14-5 to 14-8. 14-11. 14-14, 14-18. 14-21. 14-22. 19-8. 19-21, 19-23, 19-28
38
Heat flow, conversion of units, table, 1-79 Heat flow distortion, 52-22 Heat flow rate, 58-23 Heat in oil and gas separation, 12-7, 12-13 Heat injection rate, 46-8 Heat losses, factor in pattern selection, 46- 17 higher steam rate required in steamfloods, 48- 18 surface lines, 46-4 wellbore, 46-5. 46-19 with thermal stresses, 46-19 Heat of reaction, 46-12 Heat of vaporization, 14-21 Heat transfer. 9-1. 14-1, 14-3, 14-20, 28-13 Heat tra,.sfer coefficient, 58-35 Heat treating, 9-1, 9-2 Heated gunbarrel emulsion treater, 19-22 Heat treater, 15-21, 16-3 to 16-5, 16-12 Heating capacity, 19-29 Heating efficiency, 19-28 Heating in treating emulsions, 19-7, 19-11 Heating value, gross, of natural gas mixtures, 11-7 Heats of combustion, 52-3 Heavy oil-in-water emulsion-type fracturing fluid, 55-7 Heavy viscous oil, 12-17 Heidelberg field, Mississippi, 46-15, 46-18 Helical spring BHP element, 30-l Helium, 14-17, 50-14, 52-5, 52-6, 52-10, 52-13 Hemispherical head equations, 12-38 Hempel distillation, 21-3 Hencky-van Mises theory of yielding, 2-55 Henry’s law constants, 25-17 Hercules wellhead, 7-7 Heterogeneity effects on waterflooding, 44-29 Heterogeneous system, definition, 22-21 Hewitt field, Oklahoma, 44-35, 44-36 Hewlett Packard BHP gauge, 30-4, 30-7 HF: See Hydrofluoric acid Hibernia development, 18-3 Higgins-Leighton method, 44-28, 44-30, 44-31 High-capacity operation of separator, 12-42 High-frequency phase analysis, 27-1 High injection-gas cycle frequency, 5-5 1 High-liquid-level control, 12-39 High-pH chemistry in chemical flooding, 47-18. 47-19 High-pH field tests, 47-21 to 47-23 High-pH processes, consumption, 47-22 displacement mechanisms, 47-19, 47-20 high-pH chemistry, 47-18, 47-19 rock/‘fluid interaciions, 47-20, 47-21 High porosity presentation, 49-40 High-pressure gas engine starters, IO-19 High-pressure gas injection, 45-4, 45-l 1, 45-12 High-pressure gas wells, 33-4 High-pressure models, 46-13 High-pressure seals, 3-36 High-pressure service regulators, 13-55 High-bressure steamfloo&, 25-4 High-resolution spectroscopy, 50-4, 50-35, -50-37 -High-slip motors, 9-3 High-speed engines, lo-14 to lo-19 High-voltage megger, 7-13 High yield strength pipe, 15-12 Hirask-Lawson theory, 47-9 Histogram of acid numbers, 47- 19 Historical background of relative permeability, 28-2
PETROLEUM
Historical performance of reservoir, 36-10 Historical review of offshore operations, 18-1 to 18-3 History matching, 48-9, 48-13 History of reservoir simulation, 48-1 Holddown, 8-2, 8-3 Hole azimuth, 53-1, 53-2, 53-7, 53-8, 53-10, 53-17 Hole casing programs, 1841 Hole deviation, 52-13, 53-2, 534, 53-10, 53-17 Hole deviation, angle of, 53-3 Hole direction, 534 Hole enlargement, effect on acoustic velocity logging tools response, 51-15 Hole rugosity. X-19 Homestead statutes, 57-3 Homogeneous system, definition, 22-21 Hondo platform, 18-2, 18-23 Honduras, 58-20 Hooke’s law, 51-1, 51-2 Horizontal emulsion treater, 19-21, 19-23, 19-25, 19-26 Horizontal flow system, 26-11, 26-12 Horizontal force vs. displacement curve, 18-10 Horizontal fractures, 44-26, 44-28, 55-2 Horizontal FWKO, 19-18 Horizontal gas flow, 43-10, 43-11 Horizontal permeability, 39-17 to 39-19 Horizontal pressure vessel sizing, 15-24 Horizontal scrubber, 12-38 Horizontal separator, 12-1, 12-6, 12-7, 12-10, 12-16 to 12-18, 12-20 to 12-31, 12-35, 12-40, 16-15, 18-28 Horizontal separator sizing, 12-30 Horizontal stresses, 55-l Horizontal three-phase separator, 19-17 Horizontal three-phase oil/gas/water separator. 12-4 Horizbntal vessels, 13-53 Homer plot, 30-9, 35-15, 35-16, 35-19 Homer-type analysis of static BHT, 3 l-6 Horsehead, 10-2 to 10-4, lo-12 Horsepower at prime mover, lo-18 Horseuower, definition, 6-14, 58-24 Horsepower of engines, lo-17 to 10-19, 10-32, 10-33, lo-35 Horsepower of pumping unit, 9-11 Horsepower-rated motors, lo-21 Horsepower rating of motors, 10-17, 10-19, 10-20 Horsepower requirements, 34-41, 34-42, 3444, 34-45 Horsepower vs. injection pressure, 34-44 Horst, 29-3, 29-8 Hoskold method, 41-16,41-18,41-20 to 41-22 Hot-dip process, 1 l-l, 11-6 “Hot” dolomites, 50-16 Hot electric grid, 19-25 Hot oil prodiction, 46-9, 46-10 Hot oil productivity, 46-11 Hot oil treatments, 46-21, 56-2 Hot-rolled steel, 9-l Hot spots, 7-1 Hot water, cooling of, 46-6 Hot-water iniection, 46-I Hot-water stimulation, 48-2 Hot waterflood. 46-4, 46-5, 46-13, 46-23, 46-24 Hot-wire detector, 52-3 Huff’n’puff method, 46-1. 47-10, 56-2 Hugoton field, Texas, 33-1, 33-7, 33-9, 33-22, 34-46 Humble formula (relation), 26-29, 26-31, 494, 49-32 Humble gauge temperature element, 31-1 Humble pressure gauge, 30-l
ENGINEERING
HANDBOOK
Huntington Beach field, California, 19-5, 46-22, 46-23 Husky Oil Co., 46-22, 46-23 Hutton platform, 18-24 Hydrate depression, 25-19 Hydrate dissociation model, 25-9 Hydrate dissociation predictions, 2.5-5 to 25-9 Hydrate dissociation pressure, 25-6 Hydrate formation, 12-3, 14-1, 14-2, 144 to 14-7, 14-17 Hydrate formation, condition of methanol propane mixture, 25-20 conditions, effect of GOR, 25-19 conditions for paraffin hydrocarbons, 25-4 on expansion of gas, 25-l 1 pressure, procedure for determining, 25-8, 25-9 temperature, 12-40 Hydrate inhibition, 25-19, 25-20 Hydrate inhibitors, 14-3, 14-5 to 14-8, 14-17 Hydrate problem, 13-53 Hydrate stability conditions, 254 to 25-9 Hydrate temperature, 14-2, 14-3, 14-5 to 14-7, 14-17 Hydrate/volatile-gas systems, 25-3 Hydrated iron oxide, 14-22 Hydrates, 5-12, 5-24, 14-2, 14-3, 14-5, 14-6, 33-20, 33-21, 39-24, 39-25 Hydration of cementation material, 26-18 Hydraulic actuators, 3-2 1, 18-28 Hydraulic BOP control system, 18-21 Hydraulic connectors, 18-12. 18-18. 18-34 Hidraulic control circuit, 3-33 Hydraulic control system, 18-l 1, 18-15 Hydraulic currents,-24-2 Hydraulic forces, 4446 Hydraulic fracturing theory, 55-1, 55-2 Hydraulic head, 26-10, 26-12 Hydraulic horsepower, 6-45, 10-17, lo-18 Hydraulic installations, system pressures and losses, in calculation of fluid gradients, 6-26 in closed power-fluid system, 6-26 in fluid friction in tubular and annular flow passages, 6-26, 6-27 in open power-fluid system, 6-25 Hydraulic power transmission, 6- 1, 6- 15 Hydraulic pressure, 55-I Hydraulic-pumped-well control, 16-11 Hydraulic pumping, downhole pumps, 6-2 to 6-7 fluid properties, 6-66 to 6-69 frictional relationships, 6-69 to 6-72 introduction, 6-1, 6-2 jet pumps, 6-34 to 649 principles of operation-reciprocating pumps, 6-8 to 6-33 references, 6-72 surface equipment, 6-49 to 6-63 Hydraulic ivcompressibility method, 26-8 Hydraulic radius, 34-27, 34-39 Hydraulic-set packer, 4-3, 4-5, 4-6 Hydraulic subsea controls, 1849 Hydraulic surface safety valves, 3-20, 3-21 Hydraulic transformer, 6-19 Hvdraulic transformer orocess. 6- 16 Hidraulic transmission’system, 18-3 Hydraulic turbine, 6-1 Hidrocarbon analyses, crude oil and gas condensates, 39-2 formation evaluation service, 52-2 to 52-7, 52-13 of produced well stream, 39-7 of separator products and calculated well stream, 39-7 used in pressure depletion predictions, 39-10, 39-11
SUBJECT 1NDEX
Hydrocarbon chromatogram, 52-16 Hydrocarbon content of samples, 52-9, 52-10 Hydrocarbon content from logs, 5 l-35 to 5 1-38 Hvdrocarbon gas viscositv. 15-6 H;drocarbon/cquid conddnsation, 39-13 Hvdrocarbon liquid recovery, 37-22, 37-23 Hidrocarbon liquid recove; calculations, 14-16 Hydrocarbon liquid recovery system, 14-8 Hydrocarbon liquid saturations, 39- 10 Hydrocarbon mixtures, 39-2, 394, 39-12 Hydrocarbon pore space, 39-8, 39-9, 39-l 1, 39-18 Hydrocarbon recovery systems, leaseoperated, gas treating for removal of water vapor, CO, and H,S, 14-17 to 14-22 lOW-temperature separation (LTS), 14-l to 14-17 references, 14-22 Hydrocarbon recovery unit, 14-10, 14-11 Hydrocarbon reservoir, definition, 39-l Hvdrccarbon-rich phase at three-phase critical conditi&, 25-5 _ Hydrocarbon saturation, 49-27, 50-2 Hidrocarbon stabilization, 14-13 to 14-17 Hydrocarbon/water phase diagrams, 25-l to 25-4 Hydrocarbon/water systems, 25-3, 25-27 Hydrocarbon Well Log Standards Committee, 52-30 Hydrocarbons in place, ownership of, 57-1 Hydrocarbons presence detection, 50-1, 50-3 Hydrocarbons, removing from solids, 15-30 Hydrocarbons, treating from water, 15-2 1 Hydrochloric acid (HCL), acidizing treatments, 54-1, 54-2 as synthetic polymer gel, 55-5 channeling and wormhole effect, 54-8 combined with HF. dissolving action. 54-9 density at 6O”F, 54-2 dissolution of concentrated, 54-3 dissolving limestone, 54-2 in acidizing, 54-l to 54-3 in matrix acid stimulation, 56-5 inhibited, as mud-dissolving acid, 56-l inhibitors used with, 54-1, 54-6 matrix treatment of carbonates, 54-10 organic inhibitors in, 54-6 reaction rate, effect of, acid concentration, 54-5 area/volume ratio, 54-5 flow velocity, 54-5 formation composition, 54-6 pressure, 54-4 retardation of, 54-8 rubber lining protection from, 11-6 temperature, 54-4, 54-5 to acidize pH, 24-4 to clean tubing, 56-3 to dissolve corrosion products, 39-26 to remove scale, 56-2 used in combination with HF, 54-3,54-9 Hydrocyclone, 6-62 Hydrocyclone operation, 15-19, 15-30 Hydrodynamic forces, 18-17, IS-25 Hydroelectric valve operators, 16-3 Hydrofluoric acid (HF) in acidizing, 54-3, 54-4, 54-9, 54-l 1 Hvdrofluoriclhvdrochloric acid (HF/HCl) mixNreS in-acidizing, 54-11 Hydrogen, l-80, 26-18, 50-1, 50-3, 50-4, 50-9, 50-13, 50-17, 50-18, 50-20, 50-26, 50-31, 50-34, 51-31 Hydrogen density, 50-32 Hydrogen embrittlement, 3-36 Hydrogen flame detector, 52-4
39
Hydrogen sulfide (H,S), 3-36, 3-37, 4-4, 4-5. 6-4, 6-54, 7-11, 7-14. 8-9, 9-1, 9-5, 9-8, 11-6, 12-3, 12-8, 14-3, 14-13, 14-17. 14-20 to 14-22. 15-28. 15-29. 18-20. 18-47, 20-5, 20-6, 22-5, 24-5, 24-17, 39-5, 39-6, 40-22, 44-36. 44-42 to 4444, 45-5, 52-4 to 52-7, 52-13, 547 Hydrogen sulfide content, 25-5, 25-8, 25-13, 25-20 Hydrogen sulfide fumes, lo-13 Hydrogen sulfide gas detectors, IS-47 Hydrogen sulfide/water system, 25-27 Hydrolysis of methyl formate, 54-4 Hydrolyzed polyacrylamide (HPAM), 47-3 to 47-6 Hydrometer, l-80, 54-3 Hvdrometer test method, 17-5 Hidrophile, 47-7 Hydrophobe/hydrophile balance, 19-10 Hidrobhobic surface, 47-8 Hydropneumatic tensioning units, 18-13, 18-14 Hydrostatic equilibrium, 26-l 1 Hydrostatic gradient, 58-25 Hydrostatic head, 6-25, 6-28, 6-51, 55-7, 55-8 Hydrostatic pressure, 3-29, 3-31, 18-17, 29-1, 51-39, 5144 Hydrostatic PV compressibility technique, 26-8, 26-9 Hydrostatic test pressure, 2-62, 3-1,3-2, 3-13 Hydroxyethyl cellulose (HEC), 47-3 Hydroxyfluoboric acid, 54-4 Hydroxyl reactions, 47-21 Hydroxypropyl guar as thickening agent, 55-5, 55-6 Hyperbolic cosines, table, l-59 Hyperbolic decline, 40-28, 40-29. 40-31, 40-32, 41-10, 41-11, 41-29 Hyperbolic-decline deferment factor, 41-29 ‘to 41-31 Hyperbolic sines. table, l-58 Hyperbolic tangents, table, l-60 HypercleanTM technique, 46-2 1 Hysteresis, 28-2, 28-3. 28-6, 28-10, 28-13, 30-3, 30-6, 30-7, 33-6 I I-wire, 7-5 Ice characteristics, 18-38 Ice-class rigs, 18-2 1 Ice impact, 1843 Ice islands, 18-39 Ice loading, 18-39 Ice management. 18-43 Ice point, 25-l to 25-3, 25-5 Icebergs, 18-39 Icebreaker assistance vessels. 1843 Ideal equilibrium ratios, 23-l 1 Ideal gas, 20-l to 20-3, 26-12 Ideal-gas law, 13-8, 20-2, 204, 20-6, 20-7, 39-8, 40-21, 47-13 Ideal productivity index (PI), 32-3 Ideal solution principles. density from, 22-2, 22-5 Idealized pore models, 26-28 IFP-ICPP, 46-4, 46-15. 46-18, 46-28, 46-29 Igneous rock, 29-3, 29-8 Ignition devices, 46-20 Illinois, 40-16, 40-32, 40-33. 44-41, 44-42, 46-3, 46-4, 46-15 Illinois basin, 24-6, 24-7, 24-9, 4444 Illite, 46-21,50-21,50-32,50-34,50-37,52-21 Illuminance, unit and definition, 58-l 1, 58-23, 58-36 Imbibition curves, 26-24, 28-5, 28-9 to 28-12
Imbibition effect, 40-20 lmbibition of water, 40-20 Imbibition without relative permeability data, 28-4 Immiscibility of methane gas and oil, 45-2 Immiscible disulacement. 42-2 Immiscible d&lacement fluid, 40-4 Immiscible fluids. 28-2. 28-12. 28-13 Immiscible gas drive, 45-4 Immiscible gas injection, 43-1, 43-2 Immiscible liquids, 19-1, 19-2, 19-14 Immiscible processes, 39-18 Impact energy, 58-32 Impact kinetic energy, 13-l Impact loading or loads, 3-1, 18-5 Impact pressure, 13-45 to 13-48, 33-l to 33-4 Impact requirement, wellhead equipment, 3-38 Impedances, IO-30 Impingement, 12-S to 12-11, 12-13, 12-19 Implicit-pressure/explicit-saturation formulation (IMPES), 48-14, 48-15 Implied covenant, 57-6 Impressed-current system, 11-6 Improved recovery reserves, 40-3, 40-34 Impurities in well fluids. 12-3 In-transit deck-load capability. 18-8 Inaccessible pore volume (IPV), 47-5 Inbreathing (vacuum relien of storage tanks. 11-6, 11-7 Incident flux, 50-5 to 50-7 Incident gamma ray, 50-7, 50-12. 50-13 Inclination angle, 53-5, 53-6 Inclinometer, 53-8 Inclinometer section, 53-7 InconelO, 7-3, 15-21 Incremental gas production, 37-10 Incremental oil production, 37-9, 37-17 Incremental oil recovery (IOR), 47-6, 47-2 1 to 47-23 Incremental recovery, potential for, 46-3 Incrustation, 17-3 Independent oil company, 57-8 Independent screwed wellhead, 3-39 Indian Petroleum Corp., 18-1 Indiana, 24-7 Indirect beater, 14-3, 14-5, 14-6 Indirect-fired heaters, 19-2 1 Indonesia, 12-39, 46-3, 46-4 Induced-gamma-ray spectroscopy, 50-4, 50-34, 50-35, 50-37 Induced hydraulic fractures, 54-l 1 Induced porosity, 26- 1, 26-2 Induced radiation, 50-6 Induction conductivity curve, 49-15 Induction device, deep-reading (ID), 49-15, 49-17, 49-20 Induction device, medium-reading (IM). 49-15, 49-17, 49-18 Induction-electrical log (IEL), 49-27. 49-29 to 49-3 1 Induction-electrical surveys (IES), 49-11, 49-15 Induction log (IL), 49-l, 49-2, 49-5, 49-6, 49-14 to 49-18, 49-25 to 49-27, 49-29, 49-30 Induction log resistivity, 51-17, 51-26, 51-37, 51-38, 5146 Induction motors, lo-19 to 10-21, lo-23 to 10-25, 10-30, 10-32, lo-36 Induction motor poles vs. synchronous speeds, lo-23 Induction spherically focused log (ISF), 49-15, 49-16, 49-19. 49-20. 49-34, 49-36 Inductive couplers, 18-52 Inelastic gamma-ray spectroscopy, 50-35 Inelastic neutron reactions, 50-13 Inelastic scattering, 50-9, 50-23
40
Inelastic spectrometry. 50-22 Inert-gas injection. 39-16 Inertial effects, 35-10 Inerttal forces, 35-l I Industrial multitube boilers, 46-19 Inferential meters, 16-5 Infiltration by permeation, 24-18 Infinite-acting pressure solution, 35-3, 35-4. 35-7. 35-12. 35-14 Infinite aquifer. 38-3, 38-6. 38-9 Infinite boundary, definition, 38-l Infinite linear aquifers, 38-2, 38-8 Infinite radial aquifer, 38-3. 38-5 to 3X-8 Inflation factor. 41-15 Inflow performance relationship (IPR), 6-4, 6-25, 6-41 to 6-43, 6-46, 6-47. 34-30 to 34-35, 34-46. 34-50. 37-17 to 37-21 Inflow well performance, 5-22 Influence-function curves, 38-3 Infrared (IR) absorbance, 12-16 Infrared absorption detector, 52-5 to 52-7 Infrared absorption method, 46-21 Infrared detectors, 3-34 Infrared fire sensors. 18-47 Inglewood field, California, 46-14 Initial fluid saturations, 37-3 Initial gas saturation, 446, 4438 Initial hydrate formation conditions, 25-l. 25-2, 25-5, 25-6. 25-l I. 25-12. 25-15, 25-19 Initial hydrate formation, estimating, 25-5 Initial oil saturation. 44-4 Initial saturation conditions. 43-5 Initial saturations. effect of, 44-6 Initial water distribution. 44-l I, 44-37 Injection application, ESP, 7-2 Injection, BHP calculation, 34-28 to 34-30 InjectIon fluids, 42-2, 42-5 Injection-gas breakthrough, 5-52 Injection gas cycle, 5-12, 5-43, 5-48, 5-52 Injection-gas-cycle frequency, 5-55 Injection-gas cycles per day, 5-40 to 5-42, s-54. 5-55 Injection gas-line pressure, 5-48, 5-54. 5-55 Injection-gas/oil ratio (GOR), 3441 to 3443 Injection-gas opening pressure, 5-18 to S-20, 5-26, S-28, S-29, S-33, 5-39. 5-40, 5-51 Injection-gas operating pressure, 5-48, 5-53 Injection-gas pressure, 5-20, 5-2 I, S-24, 5-26, 5-28. 5-31. 5-32, 5-35. 5-37. 5-39 to 5-41, 5-44, S-46, 5-48 to 5-54 Injection-gas-pressure-at-depth Curves, 5-5 Injection-gas-pressure-at-depth traverse, S-36 Injection-gas rate, proper adjustment, 5-53 to 5-55 Injection-gas requirement for intermittent lift, S-40 to 5-42 Injection-gas throughput. maximum, 536,543 Injection-gas volume per cycle, S-S 1 Injection-gas volumetric rate, 5-3, 5-54 Injection-gas volumetric throughput, 5-37, 540 Injection-gas volumetric throughput profiles, 5-20 Injection operations. 42-1 to 42-6 Injection pressure effect on horsepower, 3442 InJeCtiOn-preSSUre-Operated gas lift Valve, 5-13, 5-14, 5-16 to 5-24, 5-27, 5-32. 5-33, S-36, 5-40, 5-54 Injection profile, foam, 47-9 Injection profiles, 4-6 to 4-8 Injection-pumping rate, controlling, 16-14 Injection quill, 19-I 1 Injection treatments, large-volume, 56-2 Injection water, 24-5 Injection well plugging, 39-26
PETROLEUM
Injection wells. gas. 34-28 to 34-30 liquid. 34-28 lnlectivity. 44-29. 44-33 to 44-35. 44-43. 46-22 Injectwy, effect of damage on, 54-8, 54-9 Injectivity index. 4434, 44-35 lnjectivityiproductiwty ratio, 46-17 Injectivity profile. of water-injection well, 31-4 Injectivity testing. 39-25. 39-26, 44-46 Inner-valve assembly. 13-49 Inorganic constituents. anions, 24-9, 24-12 cations. 24-9 Inorganic solids. 19-5 Input safety valves (ISV’s), 3-35 Insert pump. 8-l In-situ analyses, IX-26 In-situ combustion, 19-28, 48-2. 48-5 to 48-7 In-situ combustion models, 46-12 In-situ combustion processes. chemical reactions. 46-37 dry forward combustion, 46-1, 46-2 production by, 46-4 reverse combustion, 46-2 wet combustion, 46-2, 46-3 In-situ “static” analysis, 18-27 Insoluble reaction products, 54-1 Inspection of tubing and casing by caliper logs. 53-17. 53-18 Installation design calculations, gas lift, 5-29 to s-32 Installation design considerations. gas lift, 5-22 Installation design. contmuous flow gas lift, calculation of test rack-set opening pressure, 5-29. 5-33 determmation of valve depths, 5-28, 5-29, 5-32. 5-33 example calculations. 5-29 to 5-35 selection of port size. 5-28 Installation design, intermittent gas lift, calculation of test rack-set opening pressure, 5-46. 5-49 determination of valve depths, 5-45, 5-46, 5-48, 5-49 example calculations, 5-46. 5-47, 5-49, 5-50, 5-52 lift chamber application. 5-50 to 5-52 percent tubing load, 5-48 selection of port size. 544 Installation design methods, gas lift, 5-22 Installationimamtenance system controls, 1848 Installation of ESP equipment, 7-12 to 7-14 Installation of prime mover, IO-19 Installation of pumping units, 10-7, IO-12 Installation of safety devices, 12-40 Institut Franqais du P&role method, 28-7 Instrument-adjustment factor, 13-52 Instrumentation for liquid hydrocarbon metering systems, 17-4 Instrumentation systems offshore, 18-43 to 1a-47 Insulating additive. 46-19 Insulation classification, IO-26 lnsulatlon for oilwell pumping motors, classification of. IO-26 winding materials for, IO-26 Insulation materials, winding of, to-26 Intangible drilling costs, 57-I 1 Intangibles and intangible cost, 41-l I. 41-13, 41-14, 41-15 Integral flange, 3-16, 3-22, 3-24 Integral joint tubmg, 2-38 to 2-45, 2-64, 2-65
ENGINEERING
HANDBOOK
Integral \,aluCs, tabulated. 34-5 to 34-7, 34-10 to 34-22 Intensified acid, 54-3, 54-S Intensity/time recording. 51-18 Intensive properties. 22-2 I. 39-2 Interaction coefficient. 28-3 Interest, carried, 57-10 landowner’s, 57-1. 57-2 mineral, 57-6 net profits. 57-10 royalty, 57-5 to 57-8 working. 57-5. 57-7, 57-9, 57-10 Interest tables, 4 l-25 to 4 I-34 Interface level controller. 19-23 Interfacial buildup, 19-30 Interfacial sludge, 19-32 Interfacial tension (IFT) deadend oil, 22-17 defimtlon. 22-l. 24-16 effects on relative permeability. 28-10, 28-l 1 gas/oil. 45-4. 45-6 liquid/gas, 22-16 of acid solutions, 54-6 of condensate and water, 34-50 oil/water, 47. I, 47-9. 48-5 reduced by surface-active agents, 44-39 results in spherlcal form of water droplets. 19-I units and conversion factors, 58.38 Interfacial tension reducer. 56-5 Interfacial tension reduction. 44.40, 48-2 Interference, 44-33 Interference effects, 38-1, 38-3 Interference tests and testing, 30-S. 36-7, 36-8, 42-4 Intergranular porosity. 26-1, 26-3, 5 I-3 I Intermediate domes, 29-5. 29-6 Intermediate packers, 4-11 Intermittent controller. 16-4 Intermittent flow, skim pde. 15-26 Intermittent gas lift. comparison of time cycle to choke control of injection gas, 5-41. 5-42 cycle of operation, 5-38 daily production rates, 5-40 disadvantages of, 5-38, 5-39 gas-lift valves, 5-42, 5-43 heads or slugs in, 12-32, 12-35 injection gas requirement. 5-40, 5-41 installation design methods, 5-39, S-42. 5-44 to 5-50 introduction, 5-38 lift chamber application and installation design, 5-50 to 5-52 operation, 5-1, 5-3, 5-l 1, 5-13, 5-19. 5-37 to 5-53 percent tubing load installation designs, 548 plunger applications, 5-52 pressure-gradient spacing factors. 5-43, 5-44 surface closing pressure of valves, 5-44 types of installations. 5-39, 5-40 unloading Injection-gas pressure. effect of installation design methods, 5-39 valve port size, 5-44 Intermittent pressure-gradient spacmg factor, 5-42, S-43 Intermittent spacing factor, 5-45 Intermittent spacing factor gradient, 5-44, s-45, s-47 Intermittent spacing factor traverse, 5-46, 5-47 Internal coatings, 11-4. II-5 Internal-combustion-engine driven generators, 18-45 Internal-combustion engmes. diesel, 10.15, IO-16 four-stroke cycle, IO-15
41
SUBJECT INDEX
in inert gas injection, 39-16 installation, IO-19 multiplex pumps analogous, 6-49 oil engine, 10-15. IO-16 selection of, IO-16 to IO-19 two-stroke cycle. 10-14. IO-15 Internal corrosion, 3-36 Internal energy. 13-I Internal floating roofs, I l-2, 1 l-6 Internal flushing efficiency, 39-18 Internal gas drive. 37-1, 40-E Internal gas-driven reservoir, 32-15, 32-16 Internal injection, 43-2 Internal pressure leak resistance, of casing, 2-5. 2-7, 2-9, 2-l I, 2-13, 2-15. 2-17, 2-19. 2-57. 2-58, 2-64 Internal pressure, of casing, 2-1, 2-61 of pipe, 2-59 of line pipe, 2-56, 2-63 Internal pressure resistance of. casing, 2-5, 2-7, 2-9, 2-11, 2-13, 2-15, 2-17, 2-19 line pipe. 2-56 tubing, 2-46 Internal rate of return (ROR) method, 41-17 Internal Revenue Code, 41-14. 41-15 Internal Revenue Service, 41-2 Internal spiral element, 12-19 Internal water weir, 12-35 Internal yield pressure of pipe and couplings, 2-5, 2-7, 2-9, 2-l 1, 2-13, 2-15, 2-17, 2-19, 2-32, 2-56, 2-57, 2-63, 3-l Internal yield pressure safety factor, 2-2, 2-32, 2-34, 2-35, 2-45, 2-46 Internally coated pipe, 39-26 Internally plastic-lined tubing, 44-46 International atomic weight table, 20-l Intl. Bureau of Weight and Measures, l-69 to l-71 Intl. Commission on Radiological Protection, 58-10 International foot, l-69 Intl. Metric Convention. l-68, 1-69 Intl. prototype kilogram, l-69, I-70 Intl. Standards Organization (ISO). IO-12 Intl. system of units, guidelines for use, 17-7 Interpretation. chart for Rocky Mountain method, 49-3 I, 49-32 chart for R,,IR, and shaly sand method, 49-28 IEL method, 49-30, 49-31 of caliper logs, 53-17 of casing inspection log, 53-23 to 53-26 of chemical analyses, 24-18, 24-19 of EPT log, 49-34 to 49-36 of rmcrolog, 49-23 of paleo-environments, 36-3 of pipe analysis log, 53-13 to 53-26 of rules of dipmeter, 53-10, 53-12 of well logs, 49-25 to 49-36 quantitative, of hydrocarbon saturation, 49-21 stratigraphic, 53-13, 53-14 Interpretation of nuclear logs, gamma ray measurements, SO-24 to SO-26 introduction, 50-23, 50-24 lithology determination, 50-33 to 50-35 porosity determination, 50-26 to 50-33 saturation determination, 50-35 to 50-37 Interstate Oil Compact Commission, 33-15 Interstitial clay, effect on formation resistivity factors, 26-30 Interstitial water, 24-2, 24-3, 24-16, 24-18. 26-30, 27-8, 40-8, 40-10, 40-13, 40-16, 40- 19. 40-23
lnterstltlal water content, 39-17, 39-18, 39-21 to 39-23. 40-12 Interstltlal water saturation. 26-26. 28-4, 28-14, 37-3, 37-4, 37-15, 37-17, 39-10, 40-5 lo 40-10, 40-12. 40-15. 40-16, 40.19. 40.24. 42-4, 43-5, 44-4, 446, 449, 4436 Interstitial water saturations, capillary pressure, 26-23. 26-24 oil-based mud. 26-22, 26-23 Interval transit (travel) time, 51-15, 51-17. 51-19, 51-23. 51-24, 51-27, 51-43, 58-25, 58-33, 58-36 Interzonal hydrostatic head, 7-2 Intrawell continuity, 36-l. 36-6, 36-7 Invaded-zone correction, 49-22 Invariant point, 47-12 Invasion effects on IL. 49-17 Invasion efficiency, 39-15, 39-17, 39-18, 39-22, 39-23. 40-34, 47-l Inverse emulsion, 19-l Inverse lever rule. 23-3. 23-8 Inverse simulation, 48-9 Inverted bucket traps, 13-53 Inverted nine-spot well patlern. 45-10, 46.17, 46.18, 46-28 Investors method, 41-17 Involute element, 12-19 Iodide. 19-10, 24-9 Iodine, 24-5. 24-20, 24-21 Ion diffusion, 24-19 Ion exchange, 24-19, 24-20 Ion-exchange conduction, 49-4 Ion-exchange reactions, 52-21 Ion-exchange resins. 15-29 Ionization, 50-3 Ionized-gas counter, 50-12 Iran, 29-6 lron bacteria, 44-43 Iron chelating agents, 56-l Iron-control agents, 54-7, 54-8 Iron sponge sweetening. 14-22 Iron sultide, 14-22, 19-4, 19-9, 44-44 Iron sulfide deposits, 1 l-10 Irreducible saturation, 28-5, 28-8 Irreducible water saturation, 44-6, 44-l I, 44-12, 46-34. 46-37, 46-38, 47-9 lrreversibihty losses, 34-2 Isobaric contour maps, 39-23 Isobutaneiwater system, 25-25, 25-27 Isochronal backpressure test, 34-31 lsochronal test data, 39-25 Isochronal testing, 33-4 to 33-6, 33-10 to 33-13 Isoelectric point, 54-7 Isolation packer, 4-2, 4-3 Isometric of fractures, 51-28, 51-29 Isopachous maps. 39-2 I, 40-5, 41-8, 46-30, 46-31 Isopentaneiwater system, 25-26 Isoporosity map, 39-22 Isoporosity maps, 44-3 Isopotential lines, 4415 to 4417 Isopropyl alcohol in acidizing, 54-E Isothalic thermoset resin, 9-12 Isothermal coefficient of compressibility, 55-4 Isothermal compositional model, 48-5 Isothermal model, 48-4 lsovol map, 39-17 Italy. 12-39 Iterative method or solution. 37-8, 37-9, 37-11. 48-l. 48-13
J J function, definition, 26-25, 26-26 J-lay first-end connection, 18-38
Jackson candle units (JCU). 44-44 Jackup rig, 3-38 Jackups, 1X-2 to IX-6 Japan. 12-39 Jay/Little Escambla Creek field. 44-36, 44-37 Jefferson limestone. Kentucky, 54. I Jet pump, 6-l. 6-2. 6-4, 6-7 application range, 6-46, 6-47 application sizing, 6-41. 6-42 approximation for handling gas, 6-38, 6-39 calculation sequence and supplemental equations, 6-42 cavitation in, 6-35, 6-36 downhole pump accessories, 6-47 to 6-49 hydraulic, 6-6 installation. 6-43 mathematical presentation, 6-36 to 6-38 nomenclature. 6-35 nozzle and throat annulus area, 6-4 I nozzle and throat size. 6-39, 6-41 performance characteristics. 6-34 to 6-37 production unit performance. 6-42 ratios and throat annulus areas, 6-40 reverse-flow casing type, 6-5 single seal, 635 subsurface. 6-32, 6-47 worksheet and summary of equations, 6-44, 6-45 Jetting wells. 32-15 Jobo field, 46-4 Johnson pressure gauge, 30-2 Johnston-MaccoiSchlumberger BHP gauges, 30-4 Joint efficxncy. 12.38. 12-40 Joint-interest owner, 4 l-2 Joint-operating agreements, 57-9 Joint strength of. casing, 2-2. 2-5, 2-7. 2-9. 2-l I, 2-13, 2-15, 2-17, 2-19. 2-60. 2-61 line pipe, 2-48, 2-61 to 2-64 tubing, 2-39. 2-41, 2-43, 2-61 Joint strength safety factor, 2-2. 2-32, 2-34, 2-35, 2-45, 2-46 Jostling decrement. 5 l-47 Joule-Thomson effect, 12-17, 14-2 Jug heater, 19-21 Jumpout load of casing. 2-61 Junction box, ESP, 7-7. 7-8 Jurassic, 36-2 Juvenile water. 24-2 K K&C systems, 18-15 K-MonelO , 4-4. 4-5, 7-3. 7-6 K-value correlation, 39-12 K-values. 23-10. 23-l I. 25-5, 39.12, 48-4, 48-5 Kalman filtering, 50-S Kalrez@, 4-5 Kansas, 16-12, 16-13. 19-3. 21.2, 24.8, 24-9. 27-8, 27-10 to 27-13, 33-1, 39-25. 40.23, 44-42, 46-4, 46-14 Kansas Corp. Commission, 33-15 Kaolinite, 46-2 I, SO-2 I, 50.32, 50.34. 50-37 Karma” vortex trail, 13-49 Kay’s rule, 20-5 Kentucky, 24-6, 24-7. 41-l 1, 46-16, 54-l Kern River field, California, 46-4, 46-14, 46-15, 46-18, 46-20, 46-23. 46-24, 46-34, 46-39 Kerogen, 52-16 Kerosene, 19-4 Kerosene/water system, 25-27 Kettleman Hills field, California. 6-24, 29-2
42
PETROLEUM
Kick-off injection-gas pressure, 5-24. 5-25, 5-28, 5-33 Kickover tool, 5-2 Kihara potential, 25-5, 25-8, 25-9 Kill and choke (K&C) valves, 18-12 Kill fluid, S-24, IS-33 Killed steel, 12-41 Kilogram, definition of, I-69 Kilogram of the Archives, 1-69 Kilovoltamp reactive (WAR), 10-31, lo-33 to IO-35 Kilovoltamps (WA) rating of transformers, IO-30 to 10-35 Kinematic viscosity, 6-67, 669, 19-8, 22-13, 24-16, 58-35 Kinetic energy, 6-34, 13-1, 1345, 20-1, 20-2, 34-9, 34-29, 34-36, 50-3, 50-8, SO-13 Kinetic mixer, 19-l 1, 19-12 Klinkenberg corrections, 27-1 Knife-edge blade electrodes, 53-8, 53-9 Knitted-wire-mesh coalescing pack, 12-10, 12-11 Knitted-wire-mesh fibrous packs, 12-12 Knitted-wire-mesh mist extractor, 12-7, 12-8, 12-10 Knocking, 6-33, 6-50 Knockout drum, trap or vessel, 12-1, 12-4 Kobe porosimeter, 26-4, 26-6 Kozeny equation. 26-20 Krypton-85, 46-21 Krypton-86, l-69, l-70 Kuparuk field, Alaska, 18-3 Kuster pressure gauges, 30-2 Kyrock field, Kentucky, 46-!6
L La Concepcidn field, Venezuela, 24-13 La Paz field, Venezuela, 24-13 Laboratoty coreflood, 47-17, 47-21 Laboratory curves, for lateral sonde, 49-13 for normal sonde, 49-12 Laboratory depletion recovery, 39-14 Laboratory-derived data, 39-10, 39-l 1 Laboratory displacement tests, 4440 Laboratory experimentation, elemental models, 46-12, 46-13 fuel content, tirefloods, 46-16 of AOR and WAR, 46-17 partially scaled models, 46-13 use of water in firefloods, 46-18, 46-19 Laboratory layout for performing routine core analysis, 26-22 Laboratory-measured relative-permeability data, 374 Laboratory measurement of capillary pressure, centrifuge method, 26-Z dynamic method, 26-24 evaporation method, 26-24 mercury-injection method, 2624 porous-diaphragm method, 26-24 Laboratory measurement of porosity, bulk volume, 26-3 carbonate rocks, 26-6, 26-7 pore volume, 26-5, 26-6 precision of measurement, 26-6 sand-grain volume, 26-3 to 26-5 Laboratory measurement of transit times, 5 l-26 Laboratorv pressure-depletion studv. 39-13 Laboratory PVT analysis, 39-13 . Laboratorv PVT data. 37-3 L.aborato~ restored-state floods, 444 Laboratory solubility tester, 54-10
Laboratory testing of formation rock for acidizing, 54-9 Labyrinth path design, 7-4 Labyrinth path protector, 74, 7-5, 7-11 Lacq Superieur field, France. 46-27 to 46-29 LACT systems or units, 11-13, 15-14, 174 Lactic acid as sequestering agent, 54-7 Lag, 13-50 Lag stroke, 52-8 Lag time, 52-8, 52-14, 52-18, 52-22 Lagoonal clays, 364 Lagoven, 46- 14 Lagunillas field, Venezuela, 24-13, 464 Lake Maracaibo field, Venezuela, 18-l Lakeview pool, California, 40-15 Laminar-flow regime, 28-13 Laminar-flow region, 34-3 Landman, 57-8 Landowner’s interest, 57-1, 57-2 Landowner’s royalty, 41-1 Langmuir constants, 25-9 Laplacian interblock flow terms, 48-15 LaSalle anticline, 24-7 Lasater correlation, 22-5 to 22-7, 22-9, 22-10 Laser liquid particle spectrometer, 12-15, 12-16 Last-chance hydraulic stab system, 18-15, 18-16 Last-stroke method, hydraulic pumping, 6-28 Latched packers, 4-3 Late-time region (LTR), 35-3, 35-6 to 35-8, 35-11, 35-12 Latent heat, factor in refrigeration cooling load, 14-10 Latent heat from sensible heat, 19-15 Latent heat of steam. 46-5 Latent heat of vaporization, 46-2 Lateral device, 49-12, 49-19, 49-31 Lateral loading or loads, 18-S. 18-6 Lateral-sweep factor, 40-16, 40-17 Lateral wave loading or loads, 18-23, 18-26 Laterals in hard formations, 49-13 LaterologTM (LL). 49-1, 49-5, 49-6, 49.11, 49-18, 49-21, 49-23, 49-25, 49-27 Laterolog 3 (LL3), 49-18 to 49-22 Laterolog 7 (LL7), 49-18 to 49-22 Laterolog 8 (LLS), 49-15, 49-17. 49-20, 49-27 Layout drawings, 15-30 Layout of electrical offshore facilities, 1844 Leaching, 24-20, 26-2 Lead acetate, 52-6 Leak resistance, casing joints, 2-l Leak resistance limit, 2-59 Leakage, fluid, 6-21 fluid-seal plunger, 6-33 in downhole unit, 6-55 in pump plungers, 84, 8-5 of field gas-condensate samples, 39-5 of pump, 6-24 of tubing pressure, 6-3 pressure-relief valve, 6-33 Leakoff of fluids, 54-8, 55-2, 554, 55-8 Leaky modes of acoustic waveforms, 51-12, 51-13 Leap-frog formulations, 48-14 Lease, and assignment provisions, 41-9 automatic custody transfer (LACT), 16-1, 16-7, 16-12, 16-13 bonus, 41-1, 41-13 broker, 57-8 facilities, 4 l-9 location data, 41-8
ENGINEERING
HANDBOOK
problems, 57-10 purchases, 57-8 tank battery installation, 1I-10 Lease-operated hydrocarbon-recovery systems, gas treating for removal of water vapor, -CO,, andH,S, 14-17 to 14-22 . low-temperature separation (LTS), 14-1 to 14-17 references, 14-22 Leasehold costs, capitalized, 41-13 Leases, oil and gas, 57-1 to 57-12 Least-squares fit, 38-10 Lee-Kesler equation, 20-13, 20-17 Legal requirements, directional surveys, 53-4 Lena platform, 18-24 Length equivalents, table, 1-71 Length, standard of, l-70 Lenticular deposits, 49-25 Lessor, in the oil and gas lease, 57-3 LETC field site, Utah, 4633 Letter subscripts, SPE std., 59-52 to 59-70 Letter symbols for mathematical equations, 58-3 Letter symbols in alphabetical order, SPE std., 59-2 to 59-17 Leutert pressure gauge, 30-2 Level controllers and gauges, 19-31 Lever-operated dump valves. 19-22 Lever rule, 23-5 Lever-type valve, 12-6, 12-18 Leverage, 41-8 Life of engine equipment, 10-16, lo-17 Lift equipment, effectiveness of, 40-27, 41-9 value of BHP measurements, 30-14 Lifting potential concept, 34-50 Lifting surface flowmeter, 32-13 Light, units and conversions. 58-36 Lightning arresters, 10-28 to IO-32 Lignites, 49-25 Liguera platform, 18-2 Limestone sonde, 49-14, 49-26, 49-27 Limit switches, 16-3, 16-13 Limitations of gas lift, 5-1, 5-2 Limited character sets, 58-l 1 Limited Entry@ technique, 55-9 Limiting tie line, 45-3 to 45-5 Line disconnect switch, lo-27 Line drive pattern, 44-1, 44-20, 44-25, 46-17, 46-18 Line pioe, and- coupling, schematic, 2-54 axial stress, 2-48. 2-49 collapse pressure, 2-48, 249 collapse pressure under axial-tension stress, 2-55 collapse resistance, 248 collapse resistance under axial load, 248, 249 dimensions, 2-47, 2-50 to 2-53 elongation, 246 equations for calculating performance. 246, 2-54 to 2-56 hydrostatic test pressure, 2-62, 2-63 internal-pressure leak resistance, 2-57 to 2-59 internal-pressure resistance, 2-56 internal yield pressure, 2-56 joint strength, 248 plain-end, 2-50 to 2-53 safety factors, 2-32 tensile strength, 246 test pressure, 247, 2-50 to 2-53, 2-62 thread dimensions, 2-58, 2-65 thread form, 2-62
SUBJECT INDEX
thread height dimensions, 2-62 threaded or threads, 2-47, 2-48, 3-2 tolerance on lengths, 247 weight, 247, 2-50 yield strength, 246 Line scale, 12-2 Line sink, 39-20 Line source, 39-20 Line-source solution. 35-4 Line tension, maximum, 18-10 Linear-absorption coefficient, 50-7 Linear aquifers, 38-2, 38-4, 38-18 Linear diffraction analysis, 18-39 Linear dimensions, conversion of, 58-7 units applied to, 58-5 Linear-flow system, 26-13 to 26-15 Linear frontal advance, 38-13 Linear gels, 55-5, 55-6 Linear geometry, definition, 38-l Linear parabolic difference equations, 48-15 Linear partial differential equation, 35-1, 35-10 Linear variable differential transformer, 51-5 Linear velocities, conversion of, table, 1-76 Lined pipe, 39-26 Liners in steel pipe, 15-10 Lipophiles, 47-7, 47-11, 47-19 Liquefaction, 12-3 Liquefied gases in acidizing, 54-8 Liquefied petroleum gas (LPC), as injection fluid, 42-2, 45-1 to 45-3, 45-6 to 45-9, 45-12, 45-13 Liquefied petroleum products, density of, 17-5 Liquid block or blocking, 39-26, 46-1, 46-3 Liquid (oil) capacity of separators, 12-28, 12-29, 12-31 Liquid carryover, from compressor, 39-26 in mist extractor, 12-40 in separator, 12-42 Liquid contents of GC systems, 39-4 Liquid desiccants, 14-17 Liquid-discharge control valves, 12-42 Liquid-distribution coefficient, 34-39. 34-40 Liquid entrainment, 34-36 Liquid fallback, 5-40, 5-43, 5-44, 5-48, 5-52 Liquid/gas ratio, 12-35, 39-2, 39-5 Liquid holdup, 34-36, 34-37, 34-46 Liquid hydrocarbon, 12-33, 12-35 Liquid-hydrocarbon content, 12-15 Liquid-hydrocarbon recovery, 11-13 Liquid injection, BHP calculation, 34-28 Liquid knockout, 12-l Liquid-level control, 3-19, 13-51, 13-53, 13-54 Liquid-level controller. 12-2, 12-5 to 12-7, 12-9, 12-18, 12-35, 12-39, 14-3, 14-14, 14.18, 19-17 to 19-20, 19-31, 32-7 Liquid-level controls, 16-4, 16-5 Liquid/liquid equilibria, 23-l Liquid loading in wells, 34-46, 34-50 Liquid measurement, 16-S Liquid mist, 12-8 to 12-12, 12-20, 12-22 Liquid natural gas (LNG), 17-4, 17-7 Liquid petroleum, calculation of quantities measured by turbine or displacement meters, 17-7 Liquid petroleum (LP) gas, 10-15, 10-16, 17-4 Liquid-phase distribution, 39-25 Liquid-phase shrinkage, 39-4 Liquid production per cycle, 5-52 Liquid recovery, maximum, 5-51, 12-32 Liquid recovery per cycle, 5-40 Liquid-saturation data, 27-8
43
Liquid saturations, 27-8 Liquid seal in separator, 12-5 Liquid slug process, 45-l Liquid slugs, 5-1, 5-11, 5-19, 5-38 to 544, 5-51, 5-52, 5-54 Liquid-storage facilities, 12-33 Liquid surges, 12-2, 12-20 Liquid turbine meters, 1348 Liquid/vapor equilibrium, 23-1, 23-5 Liter, definition of, l-69 Lithium, 24-9, 24-20, 24-21, 50-6, 50-14 Lithological log, 52-14, 52-19 Lithology determination, direct measurement, 50-37 induced-gamma-ray spectrometry, 50-34, 50-35 introduction, 50-2 neutron/density combination, 50-33 photoelectric factor, 50-33, 50-34 Lithology, effect on formation factor, 49-4 effect on water-injection efficiency, 44-2 estimation from logs, 51-35 parameters, 50-18 Lithostatic pressure, 26-8 Lloydminster field, Canada, 46-34 Lloyds of London, 18-44 Load analyses, offshore facilities, 1844 Load capacity, ultrahigh-slip motor, lo-22 Load fluid gradient, 5-25, 5-28, 5-33, 545, 546 Load fluid production rate, 5-53 Load fluid traverse, 5-25 Load production pressure, 549 Loading or load up of wells, 32-15, 34-46, 34-50. 39-16 Loan payout calculation factors, 4 l-32 to 41-35 Loan payout, calculation of, 41-31 to 41-36 Local control loops, 1847 Local remote switch, lo-27 Location surveys offshore, 18-5 Lock screws, 3-3, 3-5, 3-6, 3-8, 3-9 Lockout cap, 3-27 Log analyses, company computer centers, 49-37 in coring program, thermal recovery, 46-21 Log-linear grid, 49- 15 Log mean temperature, 34-8, 34-9 Log-normal permeability distribution, 44-8 Log presentation, acoustic logging, 51-16 Log (electric) presentation and scales, 49-15, 49-16, 49-22, 49-23 Log-probability graph paper, 40-18 Logarithmic decrement, 514, 51-47 Logarithmic energy decrement, average, 50- 10, 50-l I, 50-22 Logarithmic probability diagram, 56-6, 56-7 Logarithmic sensitivity scale, 49-27 Logarithms of equivalents, l-73, l-75, 1-77 Logging engineer, 52-30 Logging geologist, 52-9, 52-18, 52-30 Logging-system schematic, MWD, 53-2, 53-3 Logging umt systems, 52-25, 52-26 Logistics considerations offshore, 18-4, 18-5 Long Beach crude oil, 47-20 Long, gross, or shipper’s ton, l-70 Long-range planning, 42-1 Long-spaced acoustic logging, borehole-size effects, 5 I-19, 51-20 formation-alteration effect, 51-20, 5 l-21 introduction to, 51-19 summary of. 51-23, 51-24 tool, 51-21 to 51-23, 51-47 Long-spaced acoustic logs. 51-22 Long Spacing SonicTM tool, 51-21
Long-term forecast, gas-well performance, 35-13 Long-thread casing, 2-5, 2-7, 2-9, 2-l 1, 2-13, 2-15, 2-17, 2-19, 2-31, 2-58, 2-64 Longitudinal capillary imbibition, 28-12 Longitudinal dispersion, 45-6 Longitudinal waves, 51-2 Looped networks in gathering and distribution systems, 15-14 Lorenz coefficient, 44-36 Los Angeles, 46-24 Loss-free propagation time. 49-32 to 49-34 Loss-ratio method, 40-32 Louisiana, 18-1, 18-2, 214, 24-7, 24-8, 24-20, 26-7, 26-23, 27-6 to 27-8, 29-3, 32-1, 36-4, 37-25, 39-16, 40-23, 41-1, 44-37, 46-3, 46-4, 46-15, 46-18, 46-19, 49-29, 574, 57-10, 57-l 1 Louisiana Dept. of Conservation, 32- 1 Louisiana gulf coast, 27-6 to 27-8, 44-37, 51-22, 51-23 Louvered baffles, 19-23 Low-alloy steel, 12-41 Low-interfacial-tension (IFT) processes, lowering ROS, 47-9, 47-10 MP flooding, 47-10 to 47-18 Low-liquid-level control, 12-39 Low-pressure service regulators, 13-55 Low-pressure waterflooding, 42-2 Low-temperature fractional distillation, 39-6 Low-temperature operation of separator, 12-40 Low-temperature separation (LTS), temperature, 14-17 with hydrate inhibitor, 14-6 to 14-8 without hydrate inhibitor, 14-3 to 14-6 Low-temperature separation (LTS) systems, compression refrigeration, 14-9, 14-10 constant-enthalpy expansion, 14-3 to 14-8 cooling, 14-1, 14-2 hydrate formation, 14-2, 14-3 hydrocarbon stabilization, 14-13 to 14-17 mechanical refrigeration, 14-8, 14-9 retrograde condensation, 14-l selective absorption, 14-10 to 14-13 theoretical considerations, 14-1 to 14-3 turbine expansion, 14-8 Low-temperature separation (LTS) unit, 12-1, 13-57, 18-46 Low-temperature separator, 12-17. 14-5 Low-temperature stabilization, 14-7 Low-tension ignition, lo-17 Lower explosive limit (LEL), 1847 Lower marine riser package (LMRP), 18-12, 18-15, 18-17, 18-19 Lubricating oils, temperature correction for, 17-6 Lubrication of pumping units, lo-12 Lubricator, 648, 6-54, 6-57 Luminous flux, unit and definition. 58-11, 58-23, 58-37 Lump-sum deferment factors, 41-20, 41.21, 41-24, 41-25 Lump-sum payment, 41-25 Lynes BHP gauges, 30-4 M Machining details, extreme-line casing joint, 2-64, 2-67, 2-68 Macrodevices, 49-7, 49-14 Macroresistivity curves, 49-26 Macroscopic anisotropy, 49-5 Macroscopic convective dispersion, 45-6 Macroscopic cross section, 50-10, 50-21, 50-23, 50-36 Macroscopic fluid velocity, 35-10
44
Macroscopic photoelectric cross sectton. 50-17. 50-33. so-34 Macroscoptc thermal absorption cross section, 50-10 to 50-12, 50-21, 50-30, 50-33 Magnelog. 53-19 Magnesium, 24-5, 24-6, 24-8 to 24-13, 24-18. 24-20. 24-21, 4444, 4445. 47-13 Magnesium chloride, 8-9, 19-29, 54-l Magnetic collar locator, S3- 18 Magnetic compass for hole deviation, 53-3, 53-4 Magnetic flux, 53-21 to 53-23 Magnetic flux density, unit and deftnmon. 58-l I, 58-23. 58-36 Magnettc flux, untt and definition, 58-l I, 58-23. 58-36 Magnetic induction, unit and detinitton. SE- I I, SE-36 Magnetic permeability, 49-33. 53-23 Magnetic relative permeability, 53-20 Magnetic sensor, 13-48 Magnetic tape recordings. 49-36, 49-37 Magnetic trip capability of circuit breakers, IO-28 Magnetic valve operators, 16-3 Magnetism, units and conversions, 58-36 Magnetometer. 18-S Magnetos. IO- I7 Magnolia Petroleum Co.. 46-14, 46-16 Main Reservoir field, Louisiana. 37-25 Maintenance and operation of tank batteries, II-IO. II-11 Maintenance cost, emulsion treating, 19-33 Major thermal recovery projects, 46-3. 46-4 Makeup gas, 39-23, 39-24, 4441 Mandl-Volek model, 46-15 Mandl-Volek refinement of MarxLangenheim method, 46-8, 46-9 Mandrel and boll-weevil tubing hangers, 3-16 Mandrel hanger, 3-39 Manganese, 3-3. 24-4, 24-S. 24-9, 4444, 50-12, 50-18, SO-35 Manifolds, high-pressure. 55-9 Mamfolds in subsea completions, 18-32 Mamtoba, Canada, 24-8 Manometer factor. 13-8. 13-35 Manual adjustable positive choke, 13-57 Manual casing hanger, 3-6 Manual emergency shut-down valve, 3-19 Manufacture. of fiberglass sucker rods. 9- 12 of steel sucker rods. 9-l. 9-2 Manufacturer’s field representative, 7-13 Manufacturers’ pumps, multiplex-plunger type, 6-52 to 6-55 nozzle and throat stzes. 6-39 nozzle vs. throat annulus area, 6-41 throat annulus areas and area ratios. 6-40 types of. 6-10 to 6-17 Manufacturers’ rated capacities for separators, 12-32 Manways, 1l-6. 12-42 Marathon Oil Co.. 46-15 Maraven. 46-4. 46-15 Marginal well tests, 12-17 Maricopa field, Califorma. 6-24 Marine bulk carriers. metering systems for loading and unloading. 17-4 Marine cargo inspection, guidelines for, 17-E Marine environment. 56-2 Marine measurement, 17-E Marine pipelines, 18-43 Marme risers. 18-14 to 18-16. 18-19 Marine terminals. 18-43
PETROLEUM
Marine water. 24-19, 24-20 Mark II crank-balanced pumping units, 10-t to 10-4, 10-6, 10-E. IO-9 Market capacity. 32-l Market value. 41-3, 41-5, 41-6 Market-value yardstick, 41-5 Marx-Langenheim method, 46-7 to 46-9 Mass-absorption coefficient, 50-8 Mass-balance equations, 48-3 Mass balance of hydrocarbons, 46-11 Mass balance of oxygen, 46-12 Mass balance of water. 46-11 Mass-conservatton equation, 48-3. 48-S Mass equivalents, table, l-75 Mass flowmeter, 32-13 Mass flow ratio, 6-36 to 6-38, 6-45 Mass or force as weight quantity, 58-3, 58-S Mass, special terms and quantities involving, 58-7, SE-8 Mass spectrometry, 27-l Mass, standard of. I-70 Mass, unit and definition, 58-3, 58-5, 58-23. 58-27 Mass vs. weight, I-70 Massachusetts Inst. of Technoloav, 51-49 Material balance, 14-16, 38-4, 38-S Material-balance calculations, 22-13, 28-t I, 35-16, 37-13. 40-1, 40-13, 40-24, 42-3, 43.12, 43-16. 48-l. 48-14 Material-balance equation, 35-8, 37-2, 37-5 to 37-7, 37.10. 37-13 to 37.17, 38-4, 38-8. 38-9, 38-12 to 38-14, 40-6, 40-7, 40-9, 40.10, 40.12, 40-33, 40.44, 43-4, 43-6. 43-X. 43-12, 43-13 Material-balance method, for average reservoir pressure, 3.5-3 for nonassociated gas reservoirs, 40-33 for oil in place, 40-2, 40-6 to 40-E Material-balance studies, 36-7 Materials of construction for separators, 12-38, 12-39 Materials of construction for storage tanks, 1 l-9 Mathematical analysis of areal pattern efficiency, 44-13 to 4417 Mathematical analysis. water-drive oil reservoirs, 38-i to 3X-17 Mathematical modeling, 28-7, 28-10 Mathematical models.9.3, 36-10. 39-17, 39-18, 48-l Mathematical reservoir simulatton, 39-24, 45-10 Mathematical reservoir simulators, 39-22 Mathematical-simulation models, 38-16 Mathematical simulators. 39-17, 45-13 Mathematical iables, 1-2 to 1-67 Matrix acid stimulation, 56-5 Matrix acidizing. A/V ratio high. 54-5 carbonate formations, 54-10, 54-l 1 definition of. 54-8 overflush. 54-t 1 sandstone formattons. 54-l 1 with surfactants. 54-6 Matrtx blocks. 48-5 Matrix compactron. 26-7 Matrix correctton chart. SO-29 Matrix, definition, 26-2 Matrix density. 50-l. 50-27, 50-28 Matrix effect on neutron porosny, 50-28 to 50-30 Matrix identification chart, 50-19 Matrix permeability, 26-15. 27-18 Matrix porosity, 26-7. 44-2 Matrix steam injection. 46-27, 4628 Matrix transit time. 51-30, 51-35
ENGINEERING
HANDBOOK
Matrix treatment with acid, 56-5 Maximum efficient rate (MER), 32-2, 41-9 Maximum-indicating pressure gauge, 30-4 Maximum present worth, 42-2 Maximum producible oil index, 49-28 Maximum theoretical valve spread, 542 Maximum transfer pressure, 5-32 Maxwell’s equation, 49-33 May Libby field, Lomsiana, 46-15 Mean average boiling point, 21-l 1, 21-12. 21-15 Mean free path. 50-10. SO-22 Mean hydrauhc radius, 26-31 Means field. Texas, 36-5, 36-7 Measured phase compositions, 23-12 Measurement, of barges, 17-3 of horizontal tanks, 17-3 of liquid hydrocarbons by displacement meter systems, 17-4 of petroleum by weight, 17-7, 17-8 of petroleum liquid hydrocarbons by positive-displacement meter, 17-4, 17-5 of spheres and spherotds. 17-3 of tank cats, 17-3 of upright cylindrical tanks, 17-3 Measurement control charts 17-7 Measurement methodologies of relative permeability, calculation methods, 28-7 capillary-pressure and endpointdisplacement method, 28-8 critique of methods, 28-7 stationary-fluids methods. 28-8 stead-,-state methods. 28-3 to 28-7 unsteady-state methods, 28-7 Measurement tickets, 17-7 Measurement-while-drilling (MWD), data listing for, 53-6 data-transmission schematic. 53-2 directional vs. multishot directional, 53-S downhole assembly, 53-2 log, 53-2, 53-4 logging system, 53-3 measuring systems, 53-l rotary-drilling log, 53-4 services, 52-1, 52-28 Measuring crude oil. 17-I to 17-8 Measuring natural-gas fluids, 17-7 Measuring quality of separated fluids, 12-15, 12-16 Measuring temperature of petroleum and petroleum products, 17-5 to 17-7 Mechanical damage, 5 I-20 Mechanical data, electric submersible pump (ESP), 7-9 Mechanical degradation. 47-S Mechanical energy, 22-21, 51-2, 51-3 Mechanical-energy gradients, 28-13. 28-14 Mechanical fail&, -39-25 Mechanical flow sheets, IS-31 Mechanical lock holddown, 8-8 Mechanical losses in hydraulic pumps, 6-19. 6-20, 6-21 Mechanical power. 6- I5 Mechanical pressure control, 12-39 Mechanical properties. elasttc module, 5 I-43 fracturing. 51-44 sand control, 5 145 Mechanical recording BHP gauges, 30-2 Mechanical refrigeration. I I-13 Mechanical-refrigeration systems, 14-8 to 14-10 Mechamcal trmers, 164 Mechanical wave propagation. 5 l-2 Mechamcally operated valve. 13-53
SUBJECT INDEX
Mechanically set packer, 4-3, 4-4, 4-6 Mechanics, units and conversions, 58-33, 58-34 Mediterranean Sea, 24-19 Medium-slip motors. 9-3 Melcher-Nutting grain-volume method, 26-3 Melting curve, 23.l( 23-2 Membrane-filterability tests, 4443 Membrane filtration, 24-18 to 24-20 Memory jogger, metric units, 58-21 Mene Grande field, 24-13 Mene Grande Oil Co.. 46-16 Mene Grande tar sand, Venezuela, 46-3 Mercaptans, 14-17 Mercury. 26-3, 26-4, 26-24. 39-8 Merc&njection method of capillarypressure measurement, 26-24, 26-25 Mercury manometers, 13-3, 13-36 Mercury method of calculating directional surveys. 53-6 Mercury porosimeter, 26-22 Mercury-pump method, 52-19 Mercury-pump porosimeter, 26-6 Mercury test site, Nevada, 53-5 Mercury-type meters, 13-8, 13-35 to 13-37 Mercury valve switch, 16-3 Metal-on-metal seal ring, 18-18 Metal spray coupling, 9-9 Metal-to-metal plungers, 8-4 Metallic storage tanks, 1 l-9 Metamorphosed rock, 29-3, 29-8 Metastable dewpoint locus, 25-1, 25-2 Metastable equilibrium, 14-4 Metastable-equilibrium locus, 25-2 Metastable liquid water, 25-10 Meteoric water, 24-2 Meter, definition, 1-69 Meter factor or multipliers, 32-10, 32-12, 32-13 Meter loops, 6-54 Meter model. 474 Meter proving, 16-6. 16-14, 17-4 Meter-tank-type LACT system, 16-12, 16-13 Meter tube, 5-53 Metering and metering assemblies, 17-4, 17-5 Metermg separator, 12-17 to 12-19, 32-13, 32. I4 Metering systems, critical flow provers, 13-37. 13-45 orifice well tester. 13-37 pitot tube, 13-2, 13-45 velocity, other meters using, 13-45, 13-48. 13-49 Metering trim. 13-53 Meters using velocity, centrifugal (elbow) meters, 13-45 eccentric orifices, 13-45 rotameter, 13-45 segmental orifices, 13-45 sonic meters, 13-48 turbine meters, 1345 vortex shedding meter. 13-48 Methaneibutaneldecane system, 23-5 Methane/butane system, 23-6 Methaneidecane system. 23-6 Methane hydrates, 25 10 Methane/propane hydrates, 25-10 Methane/propane system, 25-9 Methane/propane/water system, 25-10 Methane-rich gas, 25-13 Methane/water system. 25-l. 25-2. 25-17. 25-18 Methanol, as hydrate inhibitor. 25-19. 25-20 for freezing and corrosion protection, 3-3.5 Method of least squares. 26-3 1. 40-6
45
Methyl alcohol, in acidizing, 54-8 in in-situ formation of hydrofluoric acid, 54-4 Methyl orange end point, 54-3 Methyldiethanolamine (MDEA), 14-21, 14-22 Metric Conversion Act of 1975, l-69 Metric standard for orifice equations and constants, 13-3 Metric system, definition. origin, and development, l-68, l-69 Intl. Bureau of Weights and Measures, I-69 present status in U.S., l-69 units and standards of, 1-69 Metric ton, l-70 Mexico, 12-39, 21-2. 58-20 Micellar floods, 19-28, 48-5. 48-7 Micellar fluids, 28-l 1 Micellarlpolymer (MP) flooding, 47- 1, 47-9 to 47-22, 48-6 formulation, 47-13, 47-15 phase behavior, 47-l 1, 47-13, 47-20 slug, 47-10, 47-15 to 47-17 surfactants, 47-7, 47-17 Micelles, 47-10, 47-1 1 Microannulus, 51-41 Microbiological growth, 44-44 Microcaliper curve. 49-1, 49-l I, 49-22, 49-25, 49-26, 49-29, 49-31 Microcaliper log, 53-16 Microcomputers, 16-1, 16-6, 16-8 Microdevices, 49-7, 49-14 Microemulsion, 28-1 I, 45-l Microemulsion flooding, 47-10 Microemulsion phase, 47-l 1 to 47-14 Microfiche, 17-5 Microfilm, 17-S Microinverse, 49-23 Microlaterolog (MLL), 49-22, 49-24 to 49-26. 49-28 Microlog (ML), 26-31, 443, 49-22 to 49-29, 49.31. 49-32 Microlog shaly-sand method. 49-28 Micrometer screw, 26-3, 26-4 Micronormal. 49-23 Microprocessor-based instrument system, 18-47 Microprocessors, 16-l Microresistivtty. 51-19 Microresistivity devices, 49-1, 49-22 to 49-25, 49-26 Microresistivity survey, 49-11 Microscopic anisotropy, 49-5 Microscopic convective dispersion, 45-6 Microscopic cross section, 50-6 Microscopic displacement of fluids, 39- I8 Microscopic efficiency, 40-34 Microscopic pore volumes, 39-17 Microscopic studies, 46-2 1 Microscopic sweep efficiency, 47-2 Microseismogram, 5 l-24, 51-35, 51-45, 51-46 Micro-Seismogram LogTM. 51-18 MJCROSFL (MSFL), 49-20, 49-22, 49-24, 49-25 Microswitch valve switch, 16-3 Mid-American trench, 25-18 Mid-Continent, 21-4, 21-6, 24-8 to 24-10, 29-3. 40-19, 41-5, 44-4 Middle East, 27-9, 27-20. 52-22 Middle-time region (MTR). 35-3, 35-4, 35-6. 35-8, 35-10 to 35-12, 35-14. 35-15 Midway field, California, 29-2
Midway Sunset field, California, 4614, 46-15, 46-18, 46-19 Midwest Research Inst., 8-10 Midyear compound-interest factor, 4 1 17 Midyear lump-sum deferment factor, 41-6 to 41-8, 41-27 to 41-29 Miga field, Venezuela. 46-15, 46-18 Migration length, 50-12, 50-20, 50-21, 50-29, 50-30, 50-32 Migration of clay particles, 56-5 Migration of oil and gas, 24-l Migration of oil, 24-17 of water, 24-18 Mile Six Pool, Peru, 40-14 Mill scale, I l-5 Mill varnish, 51-41, 56-3 Miller-Dyes-Hutchinson (MDH) plot, 35-15, 35-17 to 35-20 MilliporerM filter test, 44-45 Mineral, analyses of cores, 46-2 1 deeds, 57-6 dissolution, 47-20 interests, 41-1, 41-15, 57-6 owner, 57-1, 57-6 severance, 57-2 Mineral Management Service, 3-34 Mineralogy, 56-3 Minerals, in water, 4444, 44-45 in a lease or a conveyance, definition, 57-2 recovery from brines, 24-20, 24-21 Miner’s rule, 18-27 Minicomputer, 5 l-4 Minifrac job, 55-9 Minimum hydrodynamic potential, 29-3. 29-B Minimum miscibility pressure (MMP), 45-6. 45-8, 45-9 Minimum pump intake pressure, 7-10 Minor isostatic adjustment, 29-7, 29-8 Miscibility, definition, 45. I, 45-6 development, 45-4, 45-5 maintaining, 45-7 of methane gas and propane liquid, 45-2 of propane liquid and oil, 45-2 of refrigerants with water. 14-10 pressure, 22- 17 providing to improve recovery, 39-15 Miscible displacement, engineering examples, 45-10 to 45-13 engineering study, 45-8 to 45-10 factors affecting displacement efficiency, 45-6 to 45-8 fluids, 40-4 general references, 45-15 introduction, 45-1 methods. 44-19 nomenclature, 45-13 numerical dispersion effect in, 48-10 processes, 23-7 references, 40-13 to 40-15 theoretical aspects, 45-l to 45-6 Miscible-drive projects, 42-5 Miscible flood, 39-23, 48-2, 48-10 Miscible-fluid displacement. 43-7 Miscible-phase displacement, 39-16 Miscible processes, 39-18 Miscible slug process, 42-2. 45-l to 45-3, 45-6 to 45-9, 45-12, 45-13 Mississippi, 24-20, 24-21, 26-19, 40-23, 46-3, 46-4, 46-15. 46-18, 46-28 to 46-30, 54. I Mississippi River, 36-4 Missour), 24-B, 46-3, 46-14 Mist eliminators, 12-12, 39-26
46
Mist extractors. 12-l to 12-5, 12-7 to 12-9, 12-11, 12-12. 12-1.5, 12-19, 12-21. 12-23 to 12-26, 12-31, 12-40, 19-22. 19-24, 19-25, 39-26 Mist flow, 34-27, 34-36, 34-37, 3440 Mix-based fracturing fluids, 55-7, 55-8 Mixed-lithology rocks, 51-35 Mixing efficiency, 19-27 mm to decimals of an in., table, l-72 Mobil Corp., 46-4, 46-15, 46-18 Mobile analyzer, 24-4 Mobility, 58-38 Mobility-buffer drives, 47-l Mobility buffer, MP flooding, 47-10, 47-17 Mobility-buffer salinity, 47-15 Mobility-control processes, effect of low mobility on oil recovery, 47-1, 47-2 foam floodine, 47-6 to 47-9 polymer flooding, 47-2 to 47-6 Mobility improvement, 44-39, 44-40 Mobility of hisplacing fluid, 44-17 Mobility of foams, 47-8, 47-9 Mobility ratio, 39-15, 39-18, 39-21, 40-18, 40-19, 43-7, 43-8, 44-4, 44-8 to 44-10, 4415, 44-17 to 4425, 4427, 44-29, 4433 to 44-40, 45-4, 45-7, 45-9, 45-l 1, 47-1, 47-2, 47-20 Mobility-ratio effects, 44-17 to 44-24, 44-34, 4436 Mobility. total, 35-2 Model assumptions, 48-9 Model basin,’ 18-7 Mode1 formulation, 48-14 to 48-16 Model grid selection, 48-7 Model input data, 48-6 Model, radial flow, 35-6 Model(s). analog, 39-22, 44 18 analytical for pump performance, 7-12 analytical for steam injection, 46-7 to 46-l 1 assumptions, 48-9 black oil, 48-4 to 48-7, 48-9, 48-14 blotter, 44 17 bundle of capillary tubes, 28-12 chemical flood, 48-4, 48-5, 48-7 composItional, 43-2, 48-4, 48-6, 48-7, 48-9, 48m14 computer, 39-4, 44-38 conductive cloth, 44-20 dispersed clay, 5 1-34 drilling, 52-24 10 52-26 dual-water, 49-38 electrolytic, 39-20, 39-21, 4417, 4418, 44-20, 44-2 1 electronic. 39-20 elemental, 46-11 to 46-13 fluid flow, 44-20. 44-21 fluid mapper, 4420 fractured matrix, 48-5 framewood structural. 5 l-34 frontal displacement, 46-7 to 46-9 future interpretation, 50-36 gel or gelatin, 39-2, 44-17, 44-18, 44-20, 44-2 1 geochemical, 24-20 grain boundary structural, 51-34 graphical, 22-5, 22-7, 22-8 graphite-impregnated cloth. 39-2 1 aridded reservoir, 37-2. 37-5. 37-l I high-pressure. 46-13 hydrate dissociation, 25-9 idealized pore, 26-28 in-situ combustion, 46-12 isothermal, 48-4 Kuster-Toksdz. 5 1-34 laminated. 5 1-34
PETROLEUM
Lasater, 22-5 to 22-7, 22-9, 22-10 Mandl-Volek. 46-15 mathematical, 9-3, 36-10, 39-17, 39-18, 48-1, 48-16, 48-17 mathematical simulation, 38-16 meter, 47-4 numerical, 44-17. 44-20, 46-l 1, 46-20 numerical simulation, 40-2 partially scaled, 46-l 1 to 46-13 perforation prediction, 37-19 physical, 46-1 1 to 46-13 porous reservoir, 44-17 positive seal double-bag, 7-l 1 potentiometric, 39-21, 39-22, 4417, 44-19, 44-34 power law, 47-4, 55-5 process, 28-3 randomized network, 28-12 reservoir simulation, 38-16, 40-34, 43-2, 43-17, 48-1 to 48-6 resistance network, 44-20 rock flow, 44-20 sand, for fluid flow, 26-l 1 to 26-13 scaled physical, 45-10 scaled porous, 44-17, 44-34 shalv sand, 51-34 simple two-mineral, 50-33 simulation, 44-31, 44-32, 48-7 to 48-9 steam chest, 46-9 steam injection, 46-l I, 46-12 streamtube, 45-10 tandem labyrinth path, 7-11 tank-type, 37-2, 37-4, 37-5, 37-l 1, 37-14, 37-17 theoretical, 5 l-8 thermal, 48-4 to 48-7, 48-14 thermal numerical, 46-12 vacuum, 46. I3 Modems, 16-10 Modified black-oil simulator, 45-10 Modified Griffith and Wallis method, 34-37 Modified Stiles permeability-block method, 40-20 Modified turnkey format, 15-32 Modulus of elasticity, 9-3, 9-l 1, 9-12 Moisture-resistant coatings. I l-6 Molal average boiling point. 21-6, 21-11, 21-13 to 21-15 Mole, definition, 22-21 Mole fraction gas mixtures, 20-4 Mole, unit and definition, 58-25 Molecular diffusion, 45-6 Molecular sieves, 14-21 Molecular weight, 20-1, 20-3, 204, 20-9, 20-10 Molecular weight, effect on water content in vapor phase, 25-16 Molybdenum, 9-5 Moment of inertia, 58-34 Monatonic gases, 13-37 Monel@ , 3-36, 7-5, 15-21, 30-4 Monel bellows, 5-16. 5-17 Monitor log, 53-8. 53-l 1 Monitoring programs, thermal recovery, 46-20, 46-2 I Monoethanolamine (MEA), 14-2 1, 14-22 Monotube separator, 12-16, 12-21, 12-22 Monovalent cation. 47-15 Monovalent/divalent ratios, 47-13 Montana, 24-8. 24-l 1. 24-20, 40-23 Montmorillonite, 442, 47-2 1, 52-2 I, 52-22 Moody diagram, 15-2, 15-3. 15-7 Moody friction factor, 34-24, 34-38 Moonpool, 18-2, 18-23, 18-42 Moored buoy, 18-30 Moored positioning, 18.2, 18.9
ENGINEERING
HANDBOOK
Mooring analysis, 18-9, 18-16, 18-17, 18-21 Mooring systems, 18-4, 18-8 to 18.10, 18-16, 18-18, 18-21, 18-24 Morkill method, 41-16. 41-19, 41-22 Mother Hubbard clause, 57-6 Motion characteristics, drilling vessels, 18-7 Motion compensators, 18-2 Motion-response curves, 18-l Motor control centers (MCC’s), 18-44, 1846 Motor, control for, IO-27 to lo-29 cyclic load factor of, lo-25 derating factors for. IO-25 direct current. IO-21 drip-proof, 10-26, 18-46 efficiency of, IO-25 electric, for oilwell pumping, lo-19 to 10-37 enclosures for, lo-26 explosion-proof, 10-27, 18-46 fr&tional horsepower, 18-46 fuses for, IO-28 horsepower ratings of, IO-20 induction, lo-19 to 10-21, IO-23 to lo-25 insulation for, IO-26 multiple-horsepower rated, lo-20 multiple-size rated, IO-21 oiltield, control for and protection of, lo-27 to lo-29 performance factors of, IO-23 to IO-26 power factor of, IO-25 power triangle for, lo-33 rated voltage, 10-2 1 selecting size of, lo-21 service factor of. 10-25. lo-26 single-phase, 10-2 I slip of, 10-23, IO-24 speed variations of, 10-24, IO-25 splash-prmf, IO-26 starter contactor for, lo-28 temperature rise of, lo-26 torque of, IO-25 totally enclosed, 10-26, 18-46 ultra-slip, IO-24 voltage frequency of, IO-2 I, IO-23 winding temperature sensors, lo-29 Motor flat cable, ESP, 7-5 Motor horsepower, IO-36 Motor load transducers, 46-2 I Motor rated voltage, IO-21 Motor torque, IO-24 Motor valve diaphragm pressure, 13-54 Motor winding temperature sensor, lo-29 Motor windings. lo-26 Mount Poso field, California, 46-4, 46-15, 46-18 Movable oil, 46-8 Mud acid, 56-5 Mud acid preflush, 54-4 Mud acid system, 54-4, 54-l 1 Mud contamination, 56-l. 56-3 Mud damage, 35-4 Mud-dispersing agents. 56-l Mud log, 49-23 Mud-log data, 52-26 Mud-log format, 52-l I to 52-16 Mud-log services, 52-1, 52-2 Mud logger, 52-30 Mud logging, 52-l to 52-30 Mud logging contractor services, 52-28 Mud removal, 56-l Mud-removal acid, 54-3, 54-4, 54-l I Mud transit time, 51-20, 51-23 Mud weight, 30-15 Mud-weight factors, 2-1 I 2-3, 2-33, 2-38
SUBJECT INDEX
Multicomponent Rash method, 37-23 to 37-26 Multicylinder diesel engines, lo-17 Multicylinder gas engine. 6-l Multicylinder pump, 4447 Multifingered caliper logs, 53- I7 Multilayer prediction method, 44-31 Multiphase displacement experiments. 28-3 Multiphase flow, Buckley-Leverett description of, 28-6 continuous-flow gas-lift design, 3440 to 34-45, 34-50 correlations, 5-22, 5-25, 5-26, 5-38, 5-40, 34-37, 37-40 gas plus liquid, hydraulic pumping, 6-27 immiscible fluids, no gravity forces, 28-2 in heterogeneous porous media, 48-1, 48-2 introduction, 34-35, 34-36 modeling of, 28-12 pseudosteady-state behavior. 35-6 theoretical considerations, 34-36, 34-37 well-performance equation, 35-2 Multiphase flowing gradient calculations, 6-72 Multiphase flowing pressure-gradient curves, 5-2 1 Multiphase inflow performance relationship (IPR) equation, 34-32 Multiphase pressure-drop correlations, 34-37 Multipiece structure, 18-23 Multiple-bore mandrel tubing hanger, 3-14, 3-16 Multiple-bore riser, 18-35 Multiple-completion equipment, 3-13 Multiple completions, 56-5 Multiple-contact miscibility, 39-16, 45-1, 45-5, 45-6. 48-5, 48-10 Multiple-cylinder engines, IO-15 Multiple-horsepower-rated motors, lo-20 Multiple-motor installation, IO-36 Multiple-parallel tubing strings, 3-14 Multiple-regression equation, 2-60 Multiple-seal pumps, 6-39 Multiple-segment tubing hanger, 3-16 Multiple-size-rated motors, lo-21 Multiple-stage separation, 12-16, 12-32, 12-33 Multiple thrusters, 18-10 Multiple tubing strings, 3-8 Multiple-zone fracturing, 55-9 Multtples of 0.4343, table, l-60 Multiples of 2.3026, table, l-60 Multiplex BOP control system, 18-21 Multiplex pumps, 6-28, 6-49 to 6-55. 6-57 to 6-59, 6-62 Multiplex transmission systems, 18-3 Multiplexed electrohydraulic control, subsea, 18-52 Multiplication factor, for casing joint length, 2-29. 2-3 1 for tubing joint length. 2-45 Multipoint backpressure test, 34-31 Multipoint gas injection, 5-32, 5-36 Multipoint testing, 334 to 33-13, 33-22 Multipool aquifers, 38-16 Multishot survey, 53-3 Multistage centrifugal pumps, 6-l Multistage emulsion, 19-2. 19-3 Multiwell templates, 18-32 Multiyear ice, 18-39 Muskat material balance, 37-13 Muskat method, 37-10 to 37-13, 37-21 Muskat’s correlations, 39-20 Muskat’s method, 40-9
47
N n-Butane/water system, 25-26 nDecane/water system, 25-26 n-Hexaneiwater system, 25-26 n-Pentane/water system, 25-26 Naphtha, 26-22 Naphtha/water system, 25-26 Naphthenic base. 19-27 Napierian logarithms, l-56, 1-57 Natl. Assn. of Corrosion Engineers (NACE), 4-4 Natl. Bureau of Standards (NBS), 1-68 to l-71, 17-4 Natl. Conference of Weights and Measures, 17-7, 17-8 Natl. Electric Code (NEC), IO-26 Natl. Electrical Code, 18-46 Natl. Electrical Manufacturers Assn. (NEMA), classification for control enclosures, 7-5, 7-6, IO-27 D-electric motors, 10-17, lo-18 rated motors. IO-24 specifications for motors, IO-20 Natl. Science Foundation. IX-15 Natural cosecants, table, l-48, l-49 Natural cosines, table, l-44, l-45, l-50 to I-54 Natural cotangents, table, l-46, l-47, l-50 to l-54 Natural gamma ray activity, 50-2, 50-15 Natural-gas container, 36-2 Natural-gas. definition, 12-3, 40-3 Natural-gas engineering letter and computer symbols. 59-2 to 59-51 Natural-gas engines, 15-16 Natural-gas fluids measurement, 17-7 Natural-gas fuel. lo-15 Natural-aas liquids (NGL). 40-3. 40-4 Natural-gas m;xtures. 17-7 Natural Gas Policy Act, 43-2 Natural-gas/water-system, 25-3 Natural gases. compositions and gas gravities. 25-6 Natural gasoline, 40-3 Natural gasoline content of gas, 20-10, 20-11 Natural gasoline plants, 4 I- I 1 Natural gums in acidizing, 54-8 Natural logarithms, table. I-56, 1-57 Natural secants, table, l-48, 149 Natural sines, table, l-44, l-45, l-50 to l-54 Natural tangents, table. l-46, l-47, l-50 to 1-54 Natural water drive, 39-15 to 39-17, 39-26, 442 Nearshore carbonate deposits, 36-6 Nebraska, 24-8, 24-20, 40-23, 44-40, 46-14, 46-15, 46-18, 46-21, 46-30, 4633, 47-22 Nederlandse Oil Co., 46-14 Negative gas show, 52-14 Negotiated turnkey format, 15-32 Neopentane/water system, 25-26 Neothene, 52-20 Nephelometer, 4444 Nephelometric turbidity units (NTU). 4444 Net cash flow, 41-3, 41-5 to 41-8 Net-oil computers, 16-2, 16-7, 16-8, 16-12 Net-pay/net-connected-pay ratio, 36-7 Net positive suction head (NPSH), 15-17 Net-profit/initial-investment ratio, 41-22 Net-profit/unreturned-investment-balance ratio, 41-22 Net-profits interest, 41-1, 41-2, 57-10 Netherlands, 12-39, 46-3, 46.14, 51-47
Neuquen basin, Argentina, 51-33 Neutron absorption. 50-2 Neutron cross section, total, 50-9 Neutron/density combination, 50-30, 50-31, 50-33 Neutron-density crossplot, 50-30, 50-33 Neutron detectors. 50-14. 50-I 5 Neutron energy, 50-8 to 50-10, 50-23 Neutron/gamma-ray tool, 49- 19 Neutron interactions, 50-E to 50-12 Neutron log, 44-3. 49-26. 49-34. 49-38, 51-31, 51-33 Neutron porosity, 50-24. 50-31, 51-20, 51-33 Neutron-porosity devices, 50-17 to 50-21. 50-28 to 50-33 Neutron-slowing-down properties, 50-2, 50-4, 50-l I Nevada, 24-2 I, 53-6 New England, 29-7 New Hampshire, 51-45 New Mexico, 6-24, 21-4. 24-8, 24.20, 27-16, 27-17, 36-8, 39-25, 40-23, 44-40 New Mexico Conservation Commission. 33-15 New York, 24-l, 44.1 Newton-Raphson iteration procedure, 23-l I, 48-14, 48-15 Newtonian fluid, 22-13 NEXUS log analysis, 49-37 Ni-Resist, 7-3 Ni-Span C@ , 30-3 Nickel, 9-5 Nigeria, 50-26 Nigerian reservoirs, offshore, 48-6 Nikurodse friction-factor equation. 34-24 Nine-point difference scheme, 48-l I Nine-spot grids. 48- 11 1 48-12 Nine-spot pattern or network, 43-2, 44-13, 44-14, 44-21, 44-23 to 44-25, 4434, 46-17, 46-25, 46-28 Nipple-up operations, 3-6 Niralloy. 7-3 Nitric acid (HNO,). 24-4 NitrileO , 4-5 Nitrogen (NJ I-70, 5-6, 5-7, 12-3, 14.13, 14-17, 16-3, 20-5, 22-5, 22-17, 23-7, 25-14, 26-18, 37-24, 39-2, 39-6, 39-14, 39-16, 40-22, 43-2, 45-1, 45-4, 45-6, 45-12, 48-5, 48-6, 48-9, 52-6, 55-6, 55-9, 56-5 Nitrogen-charged dome pressure, 5-7 Nitrogen-charged gas-lift valves, 5-16, 5-17. 5-26 Nitrogen in acidizing. 54-8 Nitrogen/water system, 25-3 Nitroglycerin, 24-1, 56 I Nitrox solution, 46-22 Nominal decline rate, 40-27 to 40-29 Nominal interest rate, 41-25 to 41-35 Nominal rate-of-return (ROR), 41-18 Nominal value. definition. 58-9 Nomograph, 22-5, 22-6. 22-10, 22-13 Non-API, pumps, 8-9 steel-grade casing, 2-5, 2-7, 2-9, 2. I I, 2-13, 2-15. 2-17, 2-19 weights and grades of casing, 2-4. 2-6, 2-8, 2-10, 2-12. 2-14. 2-16, 2-18 Non-Darcy flow, 34-31, 34-32. 34-34, 35-10, 35-11 Non-Darcy flow factor, 33-5 Non-Newtonian effects, polymers, 47-4 Non-Newtonian rheology, 28-13 Non-S1 metric units, 58-10, 58-21 Non-upset tubing, 2-38 to 2-44, 2-64, 2-66 Non-US. areas, core analysis data from, 27-9
48
Nonassociated dry gas reservoir. 40-24 Nonassociated gas. 40-3. 40-23, 40-33, 40-34 Noncircular drainage area, 32-S Noncollinear flow, 28-12 Nonequilibrium gas displacement, 43-16 Nonideal effects, micellaripolymer (MP) flooding, 47-13 Noninjection gas requirements in cycling, 39-23 Noninteractive scattering theory, 51-8. 51-9 Nonionics, 47-7, 47-8 Nonlinear partial differential equation, 35-2 Nonmetallic storage tanks, I l-9 Nonmetric units, 58-S Nonownership theory, 57-l Nonsymmetrical aquifers, 38-3 Nonsymmetrical geometry, definition, 38-l Nonwetting immiscible fluids, 28-3, 28-5, 28-6 Nonwettine phase. 26-24, 40-26, 47-9 Normal ammeter chart, electric submersible pump (ESP), 7-14, 7-16 Normal boiling point, 20-I I Normal brass standards, I-71 Normal compaction trend line, 51-39 Normal device, 49-12, 49-19, 49-20 Normal fault with drag, 53-12 Normal faults, 29-3, 29-8 Normal-flow installations, 6-6 Normal startup chart, electric submersible pump (ESP), 7-14 Normal venting capacity of tanks, 1 l-7 Normalized total gas. 52-18 Normals in hard formations. 49-13 North America, 24-6, 29-3 North Anderson Ranch field, New Mexico, 36-8 North Atlantic, 18-38 North Burbank unit, Oklahoma, 47-6 North Dakota, 24-20, 57-10 North Louisiana area, 27-4, 27-5 North Sea, 18-2, 18-3, 18-18, 18-23 to 18-26, 18-36, 18-41. 1844. 27-9, 27.20, 36-2, 44-37, 44-46, 50.24, 50-25, 51-39, 51-40. 52-16, 52-26 North Slope, 18-3 North Tisdale field. Wyoming, 46-15 Northward-Estes field, Texas. 47-22 Northwest Atkinson field, Texas, 29-4 Norway, 12-39, 18-25, 21-9 Norwegian fields, 18-23 Nozzle flow gradient, 6-37 Nozzle of jet-pump, 6-32, 6-34 to 6-39, 6-411 6-42, 6-46, 6-62, 6-63 Nozzle loss coefficient, 6-37 Nozzle size, jet pumps, 6-35 to 6-39, 6-43, 6-44 Nozzle/throat-area ratio, jet pumps, 6-35 Nuclear counting rates. SO-5 Nuclear log, 53-26 Nuclear logging techmques, interpretation of nuclear logs, 50-23 to 50-37 introduction, 50-l to 50-3 nomenclature, 50-37. 50-38 nuclear physics for logging applications, 50-3 to so-15 nuclear radiation logging devices, 50-15 to SO-23 references, 50-38 Nuclear magnetic logging (NML), 52-26 Nuclear magnetic relaxation analysis, 27-l Nuclear magnetic resonance (NMR), 28-10, 50-2 Nuclear measurements, 50-24
PETROLEUM
Nuclear physics for logging applications, fundamentals of gamma ray interactions, 50-6 to SO-8 fundamentals of neutron interactions, SO-8 to 50-12 nuclear radiation, SO-3 to SO-6 nuclear radiation detectors, SO-12 to 50-15 Nuclear radiation, in wireline logging, 50-l introduction, 50-2 to 50-5 nuclear reactions. 50-6 particle reactions, 50-S. 50-6 Nuclear-radiation detectors, gamma ray, 50-12 to 50-14 neutron, 50-14, SO-15 Nuclear-radiation logging devices, gamma-gamma density, 50-16, SO-17 gamma ray, 50-15, SO-16 inelastic and capture gamma ray spectrometry, 50-22, 50-23 neutron porosity, 50-17 to 50-21 pulsed-neutron logging, 50-21. 50-22 Nuclear reactions, 50-6 Nuclear spectrometry. 49. I Nucleonic densitometer, 12-16 Number groupings, Sl metric system, 58-12 Numerical dispersion, 48-10 to 48-12 Numerical models, 44-17. 44-20 Numerical simulation, in-situ combustion models, 46-12 models. 40-2 of chemical flood performance, 48-6 of thermal recovery processes, 46-l I, 46-12 steam injection models, 46-l I. 46-12 Numertcal simulators, 3D and 3-phase, 46-7, 46-I 1 Nutating disk positive displacement (PD) meter. 32-11, 32-12 NuTriTM, 46-22
0 Obigbo field, Nigeria, 36-7, 36-8 Obsidian, 19-S Obstruction in tubing, 33-21 Occurrence, origin, and evolution of oilfield waters, introduction, 24-19, 24-20 membrane filtration, 24-20 quantities of produced water, 24-20 shale compaction, 24-20 Ocean enuineers. 18-3 Ocean sahwater, 44-42 Oceanographer, 18.4, 18-26 Octane number, 21-4, 21-7 Off-lap deoosition, 29-8 Offset: 41:11, 41-15 Offset-drilling rule, 57-2 Offset of controller, 13-52 Offshore bars, 36-3 Offshore field operations. drillstem testing, IS-20 establishing location, 18-18 introduction, 18-17 plug and abandonment, 18-20 running 20-m. casing, 18-18 30-m. casing, 18-l 8 BOP, 18-18 to 18-20 spudding well, IS-18 Offshore installations, 6-5 to 6-7, I l-6 Offshore leasing, economic impact, 57-12 jurisdiction, 57-l I procedure, 57-11 producing history. 57-l I
ENGINEERING
HANDBOOK
Offshore operations, arctic. 18-38 to 1843 drilling, 18-3 to IS-17 electrical, instrumentation, and control systems, 18-43 to 18-52 field, 18.17 to 18-20 historical review, 18-l to 18-3 introduction. 18-I production, 18-27 to 18-38 references, 18-52 special considerations. 18-20 to 18-22 structures, 1822 to 18-27 Offshore pipelines. expensive element, 18-29 flowlines for subsea wells, IS-36 to 18-38 larger lines, 18-38 Offshore platforms, rigs, or structures, 5-2, 6-55, 6-59, 6-63. 7-l. 7-2. 12.16, 12-18, 12-20, 12-21, 12-35. 12-39, 18-l to 18-7, 18-22 to 18.25. 18-28 to 18-30. 18-40 to 18-42, 18-44 Offshore production operations, floating production facilities, 18-34 to 1836 introduction. IS-27 pipelines, 18-36 to 18-38 platform production, 18-28 to 18-30 subsea completions, IS-30 to 18-34 Offshore, special considerations, cold environment, 18-2 I deepwater drilling. 18-20, IS-2 I high-current drilling, 18-2 I, 18-22 Offshore structure classification, concrete gravity, IS-23 gravity platform construction, 18-23, 18-24 template/jacket, 18-22 template/jacket construction, 18-22. 18-23 Offshore Technology Conference, 18-38 Oficina field, Venezuela, 24-13 Ohio, 24-6, 24-7, 26-23, 43-l Ohmtc potential drop. 49-13 Ohm’s law, 26-16, 26-29. 39-20, 4417. 49-14 Oil and gas differences, best depletion techniques, 36-2, 36-3 sales method, 36-2 Oil and Gas Inst., 41-7 Oil and gas leases, 57-I to 57-12 Oil and gas separators, accessories, 12-39, 12-40 capacity curves, 12-27 to 12-32 centrifugal gas scrubbers, 12.20, 12-21 centrifugal separators, 12-20, 12-21 classification, 12-16 to 12-20 comparison of horizontal, spherical, and vertical types, 12-2 I computer sizing, 12-25 to 12-27 construction codes, 12-38. 12-39, 12-41 controls, 12-39, 1240 estimated quality of separated fluids. 12-13 to 12-16 estimating sizes and capacities, 12-21 to 12-25 general references, 12-43 illustrations of, 12-2 I introduction, 12-l to 12-3 measuring quality of separated fluids, 12-15, 12-16 methods used to remove gas from oil, 12-13 methods used to remove oil from gas, 12-8 to 12-l 1 mist extractors for, 12-11. 12-12 nomenclature, 1242, 1243 operation and maintenance considerations. 12-40
SUBJECT INDEX
practical consideratton in sizing, 12-32 primary functions of, 12-3, 12-4 references, 12-43 safety features. 12-39, 1240 secondary functions of, 124, 12-5 selection and application of separators and scrubbers, 12-35 to 12-38 special problems in. 12-6 to 12-8 stabilization of separated liquid hydrocarbons, 12-33. 12-35 stage separation of oil and gas, 12-32 to 12-35 summary, 12-l valves, 12-39, 1240 well fluids and their characteristtcs, 12-3 Oil bank, 44-l 1, 4433 Oil-base (based) muds, 26-21 to 26-23. 40.19, 444. 53-8, 53-9 Oil-based fluids, 18-49, 18-52 O&based fracturing fluids, 55-5 Oil-bucket construction. 12-35 Oil carrying agent, 56-2 Oil changing in pumping units, lo-13 Oil collectors. 19-20 Oil coning, 48-9 Oil cut, 47-18 Oil density, definition, 22-1 Oil-density determination from ideal-solution principles, composition known, 22-2 to 22-4 composition unknown, 224, 22-5 Oil-discharge control valve, 12-5, 12-6, 12-9, 12-39 Oil-displacement efficiencies, 4439 Oil-displacement rate, 46-8 Oil engines, IO-15 Oil equivalent volumes, 41-13 Oil-external microemulsion. 47-12. 47-15 Oil foam. 12-6 Oil formation volume factor (FVF) 6-67, 22-1, 22-10 to 22-13, 22-20, 37-16, 40-6, 40-8, 40-9, 40. I 1, 40-16 Oil FVF, constants for, 22-l 1 Oil FVF correlations, saturated systems, 22-10 Standing. 22-10 undersaturated systems, 22-l I to 22-13 Vasquez and Beggs, 22-10, 22-11 Oil/gas/water separator, 12-4, 12-5, 12-21 Oil gravity, effect on air requirements, 4616, 46-17 effect on fuel cc&nt, 46-16, 46-17 test, 27-l Oil in effluent gas. 12-15, 12-16 Oil in effluent water, 12-15, 12-16 Oil-in-place (OIP), 37-2 to 374, 37-6, 40-5 IO 40-8 Oil-in-water dispersion-type fracturing fluid. 55-7 Oil-in-water emulsions, 6-27, 19-l to 19-3, 19-11, 19-27, 24-2, 55-7 Oil isoperms. 28-7 Oil isothermal compressibility, Ttube method, 22-11, 22-12 Vasquez and Beggs method. 22-12, 22-13 Oil mist, 12-19. 44-4 Oil mobility, 43-7 Oil mobilization, 28-12, 484 Oil payments, 41-1, 445 Oil power fluid, 6-27, 6-29, 6-44, 6-47, 6-55, 6-56, 6-60. 6-61. 6-63 Oil pressure function, 37-8 to 37-10 Oil production above bubble point, 37-6 Oil production, time required for, 37-21 Oil property changes, steamfloods, 46-15 Oil property ownership, 41-l. 41-2 Oil-rate-vs.-time plot, calculation of, 47-17
49
Oil recovery. by chemical flooding. 47-13. 47-16, 47-17. 47-19. 47-20 by gas displacement, 43-3 by solution-gas drive. 37-2, 37-5, 37-6, 37-10, 37-11, 37-13 to 37-1s. 37-17, 37-19, 37-21, 40-18. 40-20, 444 by water injection, predtcting, areal sweep and pattern efficiency. 44- I2 to 44-25 dtsplacement calculation procedures, 44-7 to 44-12 reservoir fractures, effect of, 4425, 44-26 waterflood performance method selection, 44-3 1, 44-32 waterflood performance prediction methods, 44-26 to 44-3 1 by waterflood. 445. 44-S effect of low mobility, 47-1, 47-2 efficiency. 4430, 4432, 47-16 estimation, 48-l process, 48-3. 48-4. 48-12 thermal, 46-14, 46-15 vs. volume of fuel burned, 46-15 Oil relative permeability, 28-6, 28-8 to 28-13, 44-12, 46-37, 46-38 Oil-removal efficiency, 15-28 Oil reserves: see reserves Oil reservoir, development plan for, 36-I IO 36-l I Oil reservoir volume factor, 37-10 Oil reservoir with gas cap, 40-7 Oil reservoirs, depletion technique, 36-2 Oil reservoirs in gas-hydrate region, 25-18, 25-19 Oil reservoirs under gravity drainage, case histories after pressure depletion, 40-15 occurrence of, 40-14, 40-15 Oil reservoirs with gas-cap drive, 40-13, 40-14 Oil reservoirs with water drive, average recovery factor, 40-16. 40-17 buoyancy and inhibition effect, 40-20 general discussion, 40-15. 40-16 permeability distribution effect, 40-18 to 40-20 recovery-efficiency factor. 40. I6 unit recovery computed by frontal-drive method, 40-17, 40-18 unit-recovery equation, 40-16 Oil retention time, separator, 12-3, 12-15, 12-25 to 12-30 Oil saturation, 26-22, 37-9. 37-10 Oil Show AnalyzerTM (OSA), 52-10, 52-l 1 Oil shrinkage, 37-l. 37-6, 37-22, 37-23, 40-S Oil sizing of separator. 12-30 Oil-soluble coating. 9-10 Oil-soluble paint, 9-2 Oil-soluble resins, 54-8 Oil specific gravity, 6-67 Oil stainmg. 52-9. 52-10 Oil/steam ratio, 46-9, 46-15. 46-23 Oil storage, appurtenances, I l-6 capacity, 18-30, 18-36 general references, 1ll14 gravity conservation, 11-12, II-13 gravity structure, 18-41 materials of construction, I l-9 production equipment. 1l-9 to 1 l-l I references, 1 I - 14 tank corrosion protection, I I-4 to II-6 tank types, 11-l to 11-4 tanks, 11-6, 11-7, 18-43
temporary. 18-2 underground storage, 1l-13. 1I-14 vapor control, 11-12, II-13 vapor losses, 11-11, II-12 vapor-recovery system, 11.12. 11-13 venting atmospheric and low-pressure storage tanks. I1 -6 to 1l-9 Oil surge chamber. 19-23, 19-24 Oil system correlations, bubblepoint pressure, 22-5 to 22-9 density determination, 22-2 to 22-5 empirical, 22-7 FVF, 22-10 to 22-13 gas/oil IFT. 22-16. 22-17 general references, 22-22 glossary, 22-20, 22-21 graphical, 22-5, 22-7. 22-8 introduction, 22- 1 pseudoliquid density. 22-2 references, 22.21, 22-22 oil FVF, 22-10 to 22-13 solution GOR for saturated oils, 22-9. 22-10 total FVF’s, 22-13 viscosity, 22-13 to 22-16 Oil viscosities, 22-1, 22-13 to 22-16, 37.12, 37-16, 40-9, 40-17, 40-32, 46-31. 46-34, 46-35 Oil-viscosity correlations, factors affecting, 22-14 introduction, 22-13 saturated systems, 22-14 to 22-16 undersaturated systems, 22-16 Oil/water capillary pressure, 26-29 Oil/water contact (OWC). 41-9, 44-39 Oil/water interface. 12-39. 18-47. 19-4, 19-5, 19-9, 19-11, 19-18 10 19-20, 19-22, 19-23, 19-30, 19-31. 40-15 Oil/water interfacial tension. 4440, 47-9 Oil/water mobility ratio, 48-5 Oil/water relative-permeability curve, 47-18 Oil/water separator. 24-3 Oil/water system, 25-27. 25-28, 39-20 Oil/water viscosity ratio, 40-19, 44-6. 44-9 Oil-weight factors, 2-l. 2-33. 2-38 Oil wells, computing inflow rates, 34-32 future inflow performance, 34-34, 34-35 inflow performance, 34-30 to 34-33 single- and two-phase 1PR equation. 34-33, 34-34 Oil-wet, 19-9, 44-6 Oilfield brines, 24-5 Oiltield motors, equipment for control of, 10-27, lo-28 protection equipment for, 10-28, IO-29 Oilfield steam generators, 46-19 Oilfield waters, analysis methods, 24-5 chemical properties, 24-5 to 24-13 composition, 24-6 definition, 24-18 evolution, 24-19. 24-20 occurrence, 24- 19, 24-20 origin, 24-19, 24-20 pH, 24-16 physical properties, 24-12 to 24-l 8 sample description, 24-5 Oilwell performance, infinite-acting pressure solution, 35-3, 35-4 production rate variation (superposition), 35-8, 35-9 pseudosteady-state behavior, 35-6 to 35-8 skin effect. 35-4 superposition, example problem, 35-9
so
transient and pseudosteady state, example problem, 35-7, 35-8 well pressure performance-closed reservoir. 35-2, 35-3 wellbore storage effect, 35-4 to 35-6 Oilwell production-meter installation. 32-13 Oilwell Research porosimeter, 26-6 Oklahoma, 6-24, 16-13, 21-2, 21-4, 21-10, 24-8. 24-10. 24-21, 27-8, 27-9 to 27-12. 33-1, 33-7. 33-9, 33-12, 40-15, 40-23, 441, 444, 4436, 4441, 44-44, 46-3, 46-14, 46-16, 47-6, 57-10 Oklahoma City field, 6-24, 40-2 Oklahoma City Wilcox reservoir, 4s 15 Oleic phase, 47-l I, 47. I5 Olympic pool. Oklahoma, 44-41 On-lap deposition. 29-8 Oolicast, 29-9 Oolicastic porosity, 29-8. 29-9 Oolith. 29-9 Oolitic porosity, 26-l Open-cycle selective hydrocarbon adsorption system, 14-12 Open delta transformer, 10-30, IO-31 Open-flow capacity, 30-10, 33-3 Open flow of gas wells. 33-l to 33-23 Open-flow potential, 33-5 to 33-S. 33-10, 33-11 Open-flow testing of gas wells, 13-45 Open-flow tests, 33-3, 41-9 Open gas-lift installation, 5-2, 5-3 Open-loop control, 16-2 Open power-fluid system, 6-17, 6-18, 6-25 to 6-28. 6-30, 6-57 to 6-59, 6-63 Open regeneration system, 14-l 1, 14-12 Openhole completions, 47-6, 56-8, 56-9 Openhole logging, 50-I Operating agreements, 41-9 Operating costs, emulsion treating, 19-33 Operating downtime offshore, 18-8 Operating equipment, BHP gauges, 30-3, 30-4 Operating expenses, ad valorem taxes, 41-12 average cost per barrel, 41-l 1, 41-12 breakeven, 40-32 check list item for evaluation, 41-9 cost per well-month, 41-l 1 direct, 41-l 1 direct lifting, 41-l 1 field or district, 41-12 range of, 41-12 recompletion, 41- 12 stimulation, 41-12 trucking charges, 4 I 12 Operating gas-lift valve, 5-39 to 5-42, 5-44, 5-51 to 5-53, 5-55 Operating injection-gas pressure, 5-23, 5-26 to 5-28, 5-30, 5-32, 5-35. 5-36, 5-38, 5-39, 5-44. 5-48, 5-49, 5-53, 5-54 Operating interest, 41-2, 41-13 Operating limits, drilling vessels, table, 18-E riser, table, 18-18 Operating manuals, offshore. 18-16 Operating pressures, of separators, 12-16 of wellhead equipment, 3-l Operating problems, gas condensate (GC) reservoir, number of wells required, 39-26 well injectivity, 39-25. 39-26 well productivity and testing, 39-24, 39-25 Operation and maintenance considerations for separators. cleaning of vessels, 12-42 corrosive fluids, 1240
PETROLEUM
gauge cocks and glasses. 12-42 high-capacity operation, 12-42 insulation of safety devices, 12-40 low temperatures, 12-40 mist extractors. 12-40 paraffin, 12-42 periodic inspection. 12-40 pressure gauges, 12-42 pressure shock loads, 1242 safety heads (rupture disks), 12-40 throttling discharge of liquid, 12-40 Operation factor, 12-22 Operation of ESP equipment, 7-12 Operational considerations for emulsion treating equipment, burners and fire tubes, 19-28 cleaning vessels, 19-28, 19-29 corrosion, 19-30. 19-31 excelsior packs, changing of, 19-31, 19-32 interfacIal buildup, 19-30 level controllers and gauges, 19-3 I removing sand and other settled solids, 19-29, 19-30 safety features for electrostatic treaters, 19-3 I water-in-oil detectors (BS&W monitors), 19-3 I Operational considerations, subsea control systems, 18-49 Operational problems and remedies, problems common to steam and tirefloods, emulsions, 46-21, 46-22 sanding, 46-2 1 well productivity, 46-21 problems plaguing ftrefloods only, corrosion, 46-22 exploration hazards, 46-22 poor injectivity, 46-22 problems plaguing steamfloods only, steam placement, 46-22 steam splitting, 46-22 Operational well modes, 4-6 to 4-8 Optical emission spectrographic analysis, 56-3 Optimal conditions, generating for micellar/polymer (MP) flood. 47.14, 47-15 Optimal economic recovery, 42-l. 42-2 Optimal time to waterflood, 44-5 Optimization, of injection operations, 42.1, 42-3 Optimization studies, 48-7 Optimum efficiency of fracturing, 55-9 Optimum pressure on separator, 124 Orcutt Hill field. California, 47-22 Organic constituents of oiltield water, 24-17, 24-18 Organic inhibitors, 54-6 Organic liquid desiccants. 14-17 to 14-20 Organic phosphates, 44-45 Organic solvents, 56-2 Orgamck and Golding correlation, 21-I 1 to 21-15 Orgamsms, 44-43 Orientation curves, 53-9 Orifice check valve, 5-10, 5-22 to 5-24, 5-26, 5-28, 5-31. 5-35, 5-36 Orifice coefficient for provers, 13-45 Orifice constants. basic ordice factor, 13-3 expansion factor, 13-8 flowing-temperature factor, 13-3 gauge-location factor. 13-8 manometer factor, 13-8 pressure-base factor, 13-3
ENGINEERING
HANDBOOK
Reynolds-number factor. 13-8 specific-gravity factor, 13-3 supercompressibility factor, 13-8 temperature-base factor, 13-3 thermal-expansion factor. 13-S Orifice equations, 13-3 Orifice location, 13-36 Orifice meter, 5-53, 13-8, 13-36, 13-45, 1348, 16-6, 16-S. 33-6, 33-13 Orifice metering of natural gas, 17-7 Orifice-plate flowmeter. 32-l 3 Orifice plates, 14-2. 17-7 Orifice well tester, 13-37 to 13-44, 32-6. 32-14 Original oil in place (OOIP). 38-9 to 38-13 Orkiszewski correlation, 34-37 to 34-40 Orogenic movements, 29-7 Orthogonal-wave equation migrations, 36-8 Onhomin technique, 48-17 Oscillating piston PD meter, 32-l I Oscilloscope, 51-3, 51-12 Osmotic effects, 24-19 Ossum field, Louisiana. 26-7 Otto cycle, IO-15 Outbreathing (pressure relief) of storage tanks, 11-6, 11-7 Outer continental shelf (OCS). 3-34, 57-l I, 57-12 Oval gear positive displacement (PD) meter, 32-l I Overall displacement efficiency, 39-18 Overall economic analysis, 39-27 Overall efficiency of miscible displacement, 45-7 Overall efficiency of pumping system, lo-25 Overall heat-transfer coefficient. 46-4 to 46-7 Overall instantaneous cycling efficiency, 39-18 Overall oil recovery, 46-14 Overall particle-removal efficiency, 15-27 Overall recovery efficiency, 43-3, 45-8 Overall recovery factor, 40-23 Overall reservoir recovery efficiency, 40-34 Overbalance condition, 52-l 8 Overburden heat loss, 48-5 Overburden pressure. 26-9. 26-19, 5 l-4 to 51-7, 51-25, 51-44, 51.47, 52-26. 55-8, 56-2, 56-3 Overburden stress, 28-4, 28-13, 514, 51-30, 5143 Overflow connections for tank, 1 l-9 Overflush agent, 56-5 Overflush in acidizing. 54. I 1 Overhead, 41-12, 41-13 Overhead allocation, 41-9 Overhead costs, 36-2 Overload shutdown conditions, ESP chart. 7-16, 7-17 Overloading separators with liquid. 12-10 Overpressure, of storage tanks. I l-4 Overpressured formations, 35- 1 Overpressured gas reservoir, 40-34 Overpressuring of separator, 13-58 Overriding royalty interest, definition. 41-l to 41-3 Overtemperature lockout circuit, IO-29 Overtensioning of pipe, 18-37 Overtorquing, 9-9 Overtravel of fiberglass rods, 9-l I, 9-12 Overturned anticlines. 29-2 Ownership maps, 41-8 Ownership of hydrocarbons in place, 57- 1 Oxidation potential, 24-16 Oxyalkylated phenols, 19-10
SUBJECT INDEX
51
Oxygen (O,), 6-55, 9-8, 14-3, 14-17, 14-20, i4-22, 15-28, 15-29, 19-30, 19-31, 24-4. 24-5, 24-16, 24.17, 24.20, 39-16, 44-42, 4443, 44-47, 46-12, 46.22, 46-34, 48-5, 50-1, 50-13, 50-18, 50-35 Oxveen analvzer. 19-28 Ox$gen corrosion, 3-36 Onvaen-enriched air fireflood, 46-31, 46-34 Oxygen injection, 42-6 Oxygen scavengers, 15-29, 47-5, 47-10 Oxygen utilization efficiency, 46-15, 46-2 I P p-x diagrams for mixtures of CO,, 23-10 P-wave critical angle, 51-12 P-wave modulus for drv rock. 51-49 P-wave modulus for rock frame, 51-49 P-wave velocity, 51-l I, 51-37 P-waves, 51-2to 51-5, 51-11, 51-36, 5147 Pack gravel, 56-4 Packer mechanics, 44 Packer operations, modes of, 4-1 Packer seats, location of, 53-17 Packer selection, considerations for, corrosive well fluids, 4-4 fishing characteristics, 4-6 packer mechanics, 44 purchase price, 4-6 retrievability, 4-5 sealing elements, 4-5 surface/downhole equipment coordination, 4-4 through-tubing operations, 4-6 Packer utiltzation, 4-1 to 4-3, 4-6 permanent packers, 4-3 retrievable packers, 4-2, 4-3 success, 4-6 Packing of uniform spheres, 26-l Packoff element. 3-6 Painter field. Wyoming, 39- 16 Pair production, 50-6 to 50-8, 50-13, 50-14, 56-16 Paleo-environments, interpretation of, 36-3, 36-7 Paleontologists, 57-8 Paloma field, California, 26-30 Paluxy gas-condensate reservoir, Texas, 39-20, 39-2 I Pan AmericaniCasper Oil Co., 46-14, 46-18 Panama Canal, 18-7 Panhandle equation, 15-7 Panhandle field, Texas. 44-30 Paper-tape-type H,S detector, 52-7 Parachor, definition, 22-16 Parachors, for hvdrocarbons. 22-18 for pure substances, 22-17 Paraffin, 5-25, 5-52, 5-53, 6-31 to 6-33. 7.13. 11-13. 12-3. 12-7, 12-8. 12-10. 12-li. 12-40, 12-42, 19-4, 19-5. 19-9, 19-10, 19.30. 26-3. 32-l I, 44-4 Paraffin hvdrocarbons. 20-13. 39-2 Paraffin inhibitors, 56-2 Paraffin problem, 3-27 Paraffin removal. 56- 1. 56-2 Paraffin scrapers, 18-33 Paraffintc hydrocarbon series, 20-5 Paraffinic o&. 6-67. 24-18 Paraguay, 58-20 Parallel-bore valves. 3-15 Parallel-plate interceptor (PPD. 15-24, 15-25 Paris Academy of Science, l-68 Paris Valley field, California. 46-22, 46-23 Paroscientitic digiquartz. 30-7 Parrish and Prausnitz development, 25-5 to 25-9 Partial buildup curve. 30-9
Partial cement bonding, 51-41, 51-42 Partial differential equations, 48-2 Partial penetration, 35-4 Pantal pressure maintenance, 42-3, 43-9 to 43-17 Partial pressure of gas, 20-4 Partial water drive, 39-24 Partial water-drive reservoir, 40-6 Partially scaled models, high-pressure, 46. I3 physical types. 46-11, 46-12 vacuum, 46-13 Particle reactions, 50-5, 50-6 Particle-size distribution, 26-2, 4445 Partition, 57-2 Past performance analysis, gas pressure maintenance, 43-9 Pattern effects on waterflooding, 4429 Pattern efficiency, 44-15, 44-18, 45-6, 45-8 to 45-10 Pattern (h@weighted) efficiency, 39-15, 39-17, 39-18, 39-20 to 39-23, 39-26 Pattern floods, 46-l Pattern injection, 43-2 Pattern selection, thermal recovery, 46-17 Pattern types in firefloods and steamfloods, 46-18 Payout, 41-3, 41-35, 41-36 Payout schedule, 41-31 Peace River field, 46-34 Peak crank torque, 9-2, 9-3 Peak polished-rod load, 9-2 Peak torque, IO-26 Pendular rings, 26-24 Penetration of acid, 54-8 Peng-Robinson equation, 20-8, 23-13 Penn State arrangement, 28-5 Pennsylvania, 18-l. 21-2, 24-1, 24-2, 24-6, 24-l. 44-1, 444, 47-22 Pennsylvania Oil Producers, 17-1 Penultimate layer, 364 Percent factor, assigned spacing design line, 5-33 Percent-load design method, 5-42 Percent-load intermittent-gas-lift installation designs, 544 Percent-load production pressure, 548 Percent-tubing-load installation design, 548 Percentage depletion, 57. I I Percentage-depletion allowance, 41-5, 41-13, 41-14 Percentage factor, gas lift, 5-32 Percentage-time controller, I64 Percentage timer. LO-28 Percussion-sampling techniques, 27-9 Percussion sidewall core data, 27-9 Perforated-interval completion, 5-5 I Perforating gun, 53-26 Perforating operations, 5 I40 Perforating pipe. 56-l Perforation ball sealers, 54-10 Perforation cleaning methods, backflow, 56-5 backsurging. 56-5 HCI preflush, 56-5 matrix acid stimulatton, 56-5 matrix treatment with acid, 56-5 overflush, 56-5 perforation washing, 56-5 underbalance, 56-5Perforation, sand control, 564, 56-5 Perforation tunnels. 56-l. 564, 56-5, 56-8 Perforation washing. 56-5 Perforations. locating. 53-26 Performance calculations, reciprocating pumps, 6-28 to 6-30 Performance characteristics, jet pumps, 6-34
Performance coefficient, of backpressure equation, 33-5 to 33-10, 33-12 of refrigerants, 14-l I Performance curves, abandonment contour vs. cumulative oil, 40-34 cumulative gas vs. cumulative oil, 40-32, 40-33 improved recovery reserves, 40-34 material balance method for nonassociated gas reservoirs, 40-33, 40-34 of jet pump, 6-35, 6-36, 6-38, 641 to 6-43, 646, 6-47 of tubing and choke, 34-5 oil percentage in total fluid vs. cumulative oil, 40-32 water/oil contact (WOC), 40-34 Performance evaluation of rigs, 18-7, 18-8 Performance factors for mot&s. cyclic load, lo-25 efftciency, IO-25 power, IO-25 service, 10-25, IO-26 slip, 10-23, lo-24 speed variation, 10-24, IO-25 temperature rise, IO-26 torque, IO-25 Performance indicators, common to both steamfloods and firefloods, changes in oil property, 46-15 oil recovery, 46-14, 46-15 sweet efftciencv , 46- 14 p&a&g to firefloods only, air/oil ratio (AOR), 46-17 air requirements. 46-16 fuel content, 46-16 pertaining to steamfloods only, steam/oil ratio (SOR), 46-15 Performance of solution-gas-drive reservoirs, 37-1, 37-2 Performance predictions, models, 37-19 of micellar-polymer flooding, 47-17 of oil and gas reservoirs, 36-9, 36-10 of solution-gas drive, 37-14 to 39-18 of volatile oil reservoir, 37-22 to 37-26 Performance uroiiles, 5-20, 5-2 I Performance properties, of casing, 2-l, 2-4 to 2-19. 2-32 of pipe,-2-46, 2-54 to 2-56 of tubing, 2-38 to 2-43 Performance technique for reserve estimation, 40-I Performance-time predictions, 43-9, 43-10 Performax plate pack, l9- 13 Periodic inspection of separators, 12-40 Periodic production tests, 12-17 Peripheral flood, 44-2, 44-13, 44-17. 44-36 Permafrost, 18-38, 1X-39, 18-41 to 18-43 Permafrost cement, 18-4 1 Permafrost problem, 3-27 Permanent packers, 4-l to 4-6, 4-8 Permeability-block method, 40-19. 40-20. 40-24, 40-26 Permeability, calculations, 26-16 changes, effect on radial flow, 54-9 consideration in waterflooding, 442 conversion of units in Darcy’s law, 26-13 to 26-15 correlation with tube-wave data, 51-48 damage. 30-13, 30-14 definition of, 27-l. 28-l. 55-1 distribution. 26-26, 36-3, 36-7, 39-16, 39-18 to 39-20, 40-12, 40-18 to 40-20, 40-24. 40-25, 44-8. 44-15, 45-11. 45-12 distribution factor. 40-16. 40-17
52
effective, 26-15, 28-l to 28-4, 28-6, 28-8. 28-13, 39-17, 44-32, 44-33, 46-21 factors affecting measurement, 26-18, 26-19 factors in evaluation of, 26-19, 26-20 tlow systems of simple geometry, 26-t 1 to 26-13 from pressure-buildup curve, 30-12 in acoustic logging, 51-47 interstitial-water relationships, 26-23 introductory theory, 26-10, 26-11 limits of formations, 55-2 measurement of, 26-17, 26-18 net thickness product, 39-21 of channels and fractures, 26-15, 26-16 of matrix, 55-9 of uack, 55-8 of propping agents, 55-2, 55-8 of reservoir rocks, 30-I 1, 39-13. 44-3 physical analogies to Darcy’s law, 26-16 pinchout, 4439 prediction, 50-2 profile, 314, 364, 39-19, 44-3, 45-10. 51-47 ratio, 37-14, 37-15 reduction, 47-3 to 47-5, 55-8 reduction factor. 35-5 relative, 28-1 to 28-3, 28-6, 28-8 to 28-14, 28-16, 30-11, 39-13, 44-2, 44-4. 44-5, 44-9, 55-X SPE preferred unit, 58-24, 58-25 stratification, 39-18, 39-20 transforms, 50-37 unit in SI metric system, 58-24. 58-35, 58-36 variation, 39-19, 39-20, 39-23, 39-26. 40-18, 40-19, 443, 448 to 4410, 4436, 45-7 viscosity ratio, 47-8 Perm-plug method of permeability measurement. 26-17 Permeameter, 26-17, 26-18 Permian Basin. 49. I 1 Persian Gulf, 4437 Personal computer, 39-l I, 39-12 Personal property, definition, 57-l Personnel protectton at wellsite, lo-31 Peru, 40-14. 58-20 Peters factor, l-61 Petrographic analysis. 56-3 Petroleum engineering servtces, 52-2, 52-16 to 52-27 Petroleum engineers, 22-1, 22-14 Petroleum Engineers Club of Dallas, 41-5 Petroleum liquid, acoustic velocity in, 51-3 I Petroleum measurement subsidiary, 17-6 Petroleum reserves-definmons and nomenclature, possible, 40-2 probable, 40-2 proved, 40-2. 40-3 proved developed, 40-3 proved undeveloped, 40-3 Petroleum reservoir engineering, 42-l Petroleum reservoir engineering letter and computer symbols, 59-2 to 59-51 Petroleum reservoir traps, 29-l to 29-9 Petroleum sulfonates, 47-7 Petrophysical and physical parameters, relationship to nuclear logging, clay types, 50-2 fluid identification, 50-2 hydrocarbon saturation, 50-2 lithology, 50-2 permeability. 50-2 porosity. 50-1, 50-2 presence of hydrocarbons, 50. I
PETROLEUM
Petrophysical correlations. 28-12 Petrophysical descriptors, 50-2, 50-3 Petrophysical measurements, 52-2, 52-26, 52-27 Petrophysical properties, 28-8, 47-20 Petrophysical work, 48-8, 48-9 pH, 244, 24-5, 24.16, 24.17, 4444 pH control, 4440, 4442 Phase analysis, high-frequency, 27-l Phase behavior, and interfacial tension, 47-14, 47-15 definition. 22-2 I, 23-I of COJC,IC,, mixture, 23-9 of gas/condensate system, 39-2 to 39-4, 39-12, 39-13 of pure component, 23-2 of surfactantlbrineioil system, 47-11 to 47- 13 of water/hydrocarbon systems, 25-l to 25-28 Phase-boundary curves, 45-3, 45-4 Phase compositions, calculation of, 23-10 to 23-13 Phase converters, types of, IO-35 Phase diagrams, by measuring liquid volumes at several temperatures, 39-7 of Eilert’s fluids, 39-3 of gas condensate fluids, 394 of reservoir-fluid systems, 23-6, 23-7 of single component, 23-1, 23-2 of surfactant/brine/oil system, 47.11, 47-12 ternary, 23-5, 23-6 types of, 23-2 to 23-10 Phase equilibrium, 12-2 1 Phase equilibrium calculations, 20-10 Phase lag, 53-20 Phase loss relay, lo-28 Phase rotation, 7- I3 Phase rule, 23-2, 23-8, 25-t Phase shift angle. 53-20 Phenolic-resin gravel packing, 46-21 Philippine Islands, 58-20 Phillips Petroleum Co., 16-13, 45-15, 46-24, 46-26 Phosphoric acid. 11-6 Photoelectric absorption, 50-4, 50-7, 50-12 to 50-14, 50-17 Photoelectric absorption factor, 50-7, 50-17, 50-24, 50-33, 50-34 Photoelectric effect. 50-6 to 50-S Photographic history of injection-fluid fronts, 44-18 Photographs and visual examination of cores. 46-2 I Photometry. I-69 Photomicrographs, 19-2 to 19-5 Photomultiplier. 50-12 to 50-14 Physical analogies to Darcy’s law, 26-16, 26-17 Physical dimension of fiberglass sucker rods, 9-l I Physical models, 46-1 I to 46-13 Physical parameters and nuclear radiation, 50-2, JO-3 Physical-properties data of liquid hydrocarbons, 17-5 Physical properties of foams, 47-8, 47-9 Physical properties of oil, 21-3 to 21-8 Physical properties of oil systems, 22-l Physical properties of produced waters, compressibility, 24-12 to 24-14 density, 24-14, 24-15 dissolved gas, 24-17 formation volume factor (FVF), 24-15, 24-16 organic constituents, 24-17, 24-18
ENGINEERING
HANDBOOK
pH, 24-16 redox potential (Eh), 24-16, 24-17 resistivity, 24-16 surface (interfacial) tension, 24-16 viscosity, 24-16 Phystcal properties of wellhead equipment, 3-2, 3-3 Phystcal setup of metering system, orifice location, 13-36 recorder, 13-36 size of orifice and metering run, 13-36 straightening vanes. 13-36 Physico-chemical changes, 46-12, 46-13 Piercement domes, 29-5. 29-7 Piezoelectric element, 5 l-3 Piezoelectric transducer, 30-5, 30-6 Pig launcher, 15-14 Pig trap, 15-14, 15-16 Pigging, 18-29 Pile hammers, 18-23 Pile jacking, 18-41 Piled structures, 18-42, 1843 Pilings, 3-3 Pilot floods, 4437 to 44-39 Pilot-gas-control manifold, 16-15. 16-16 Pilot-loaded regulators, 13-55 Pilot-loaded valves, 13-55 Pilot LPG flood, 45-14 Pilot-operated control valve. 13-53 Pilot-operated diaphragm motor valve, 13-55 Pilot-operated dump valves, 16-5 Pilot-operated gas-lift valve, 5- 13, 5-43, 5-44, 5-51 Pilot-operated relief valve, I l-8, 12.40 Pilot operation, 45-10, 42-6 Pilot plug, 13-54 Pilot project, 40-3 Pilot relay, 13-50 Pilot valve, 3-34 Pilot valve diaphragm failure, 11-S Piloted union-type rise coupling, 18-15 Pin-and-socket connectors, 18-52 Pinchouts, 29-8 Pinnacle reefs, 36-5 Pipe analysis log (PAL), 53-20, 53-24, 53-25. Pipe analysis tool, 53-23 Pipe body safety factor, 2-2, 2-32. 2-34, 2-35 Pipe-body yield strength, 2-2, 2-4, 2-6, 2-8, 2-10, 2-12, 2-14, 2-16, 2-18, 2-32, 2-56 Pipe coils, 19-21 Pipe diameters, choosing in gas lutes, 15-7 choosing in liquid lines, 15-2 Pipe dope as formation contaminant, 56-3, 564 Pipe-laying reels, 18-37 Pipe rams, 18-11, 18-15, 18-20 Pipe storage, 11-2, I l-4 Pipe taps, 13-3, 13-8 to 13-11, 13-20 to 13-25, 13-28, 13-29, 13-32 Pipe-wall thickness, 15. I 1 Pipeline, gas, 36-2 Pipeline metering systems, 17-4 Pipeline run statements, 41-9 Pipeline trunk lines, 16-2 Pipeline valve, 1 I-l I Pipeline valve switches, 16-3 Piper diagram, 24-19 Piping, design considerations, 15-13 drawings, 15-31 on offshore platforms, 15-l 1 pressure breaks, 15-13 pressure rating classes, 15-13
SUBJECT INDEX
pressure/temperature ratings, 15-13 system design, IS-1 to 15-14 system materials, 15-7 to 15-l 1 Pisolith. 29-9 Plsolitic limestone, 29-8 Piston-and-valve assembly, 6-5 I F’lston BHP element, 30-I Piston effect of tubing string, 4-9, 4-10 Piston gauge, 33-6 Piston-like displacement, 447, 44-9 Piston pneumatic/hydraulic pump ratio, 3 -33 Piston/stem area ratio, 3-21 Piston-type actuators. 3-2 1 Pitcher niaule. 18-14. 18-15 Pitman siie members, 10-3, 10-4, IO-12 Pitot tube. 13-2. 13-37, 13-45 to 13-48, 32-13, 32-14, 33-l to 33-4 Plain-end, liner casing, 2-32 line pipe, 2-46, 2-G to 2-53 Plait point, 23-5, 23-8 to 23-10, 47-l 1 to 47-13 Planar view. directional data presentation, 53-6 Planning and preparations offshore, 18-3 to 18-5 Plant costs, 39-l Plant products, 39-9 to 39-l 1, 39-23 Plastic blanket, 9-14 Plastic-coated sand grains, 55-8 Plastic-collapse pressure equation, 2-54, 2-55 Plastic lining for steel pipe, 15-10 Plastic-packed secondary seal, 3-6 Plastic-packed-type seal, 3-9 Plastic pipe, 15-10 Plasticity, 52-20 Plate coalescers, 15-23 to 15-26 Plate-count method, 44-44 Plate heat exchanger, 19-23 Plate-type heating elements, 19-21 Platform deck layout for process facilities, 18-30 Platform jacket, 18-28, 18-34 Platform loads. 18-44 Platform production. crude oil disposal, 18-29, 18-30 gas disposal, 18-30 process equipment, 18-28 water disposal, 18-30 well completion, 18-28 well servicing, 18-28, 18-29 well workovers, 18-28, 18-29 Platform rigs, 36-2 Platform vibration, 12-23 Platform well bay, 18-29 Platinum-iridium standard, l-70 Plot of buildup with afterflow, 30-10 Plot of water FVF vs. pressure, 24-15 Plow steel, 304 Plug and abandonment of well, 18-20 Plug valves, 3-l 1 to 3-14 Plugback operations, 33-2 1 Plugging, 5-16, 5-23, 5-53, 14-2, 19-15, 19-30, 24-2, 39-25, 39-26, 44-36, 44-42 to 44-45, 56-6 Plugging agents, 29-5, 39-26 Plugging materials, 54-10 Plunger application for intermittent gas lift, 5-52, 5-53 Plunger-arrival detector, 5-52 Plunger clearances, 8-6 Plunger/engine (P/E) area ratio, 6-l 1 to 6-13. 6-15, 6-16, 6-18, 6-27, 6-28, 6-30 Plunger lift, 5-38 Plunger overtravel, IO-25 Plunger pumps, 6-50, 6-52 to 6-55, 8-5 Plunger stroke, 9-2
53
Pneumatic actuators, 3-2 I, 3-27, 18-28 Pneumatic control valves. 16-3 Pneumatic controls, 13-49 Pneumatic/hydraulic relay, 3-33 Pneumatic pilots, 13-56 Pneumatic/pneumatic relay, 3-33 Pneumatic pressure control, 12-39 Pneumatic surface safety valve, 3-20, 3-21 Poettmann and Carpenter correlation, 34-37 Poettmann’s method, 34-9 Point bars, 36-6 Poiseuille’s equation, 26-10, 26-15. 26.19, 26-20 Poisonous-gas sensors, 18-47 Poisson distribution, 50-5 Poisson’s ratio, 51-2, 51-4, 51-13, 51-37, 51-43, 5144, 51-50 Polar packs, 18-39 Polar blots, 53-12 Polished-joint tubing hanger, 3-9 Polished rod, 8-10, 9-1, 10-1, 10-2, 10-5, 10-7 Polished-rod coupling, 9-4 Polished-rod horsepower, 9-2, 9-3, IO-18 Polished-rod velocities and acceleration, 1o-7 Polished-sealbore packer. 4-3, 4-8. 4-9 Polyacrylamide (P’AM), 47-3 Polyacrylamide polymer, 44-39, 44-40 Polyamine derivatives, 19-10 Polyemulsions, 55-8 Pol;ethylene. 1 l-9, 24-4, 24-5 Polyethylene bedding jacket, 18-49 Polyethylene line pipe, 15-10 Polyethyleneoxide (PEO), 47-3 Polyglycol esters, 19-10 Polymer-driven flood, 47-2 1 Polymer-flood statistics, 47-6 Polymer flooding, 19-28, 47-l to 47-6, 47-10, 47-18. 47-22, 48-7 Polymer gels. 55-5 Polymer properties, biological degradation, 47-5 chemical degradation, 47-5 mechanical degradation, 47-5, 47-6 non-Newtonian effects, 47-4, 47-5 permeability reduction, 47-5 polymer retention, 47-5 viscosity relations, 47-4, 47-5 Polymer retention, 47-5 Polymer-solution viscosity, 47-4 Polymerisurfactant incompatibility, 47-13 Polymer types, 47-3 Polymer waterflooding, 48-5 Polymerized oils, 19-10 Polyphosphates, 44-15 Polypropylene, I l-9. 12-12 Polysaccharides, 47-3 Polyvinyl alcohol (PA), 47-3 Polyvinyl chloride, 1 l-9 Polvvinvl chloride (PVC) &tic, 18-46 Pony rids, 9-l. 9-3, 9-11’ Pooling clause, 57-5, 57-6 Poorly consolidated rocks, 51-33, 51-34 Pop-off safety release valve, 5-53 POP-Off valve, 13-59 Porcelain diaphragm, 26-24 Pore aspect ratio, 51-9, 51-12 Pore compressibility, 26-7 Pore configuration, 26-2 Pore-fluid compressibility, 5 l-4 Pore-fluid pressure, 28-4, 51-4, 51-5, 51-7, 51-8, 51-25. 51-30, 51-39, 51-44 Pore geometry, 28-2, 54-6 Pore liquid saturation, 27-9 Pore pressure, 52-18, 52-21, 52-22, 52-24 to 52-27
Pore-size distribuhon, 26-19, 26-24. 4427. 47-5. 47-10, 51-30, 54-6 Pore structure of rock, 26-10 Pore-throat-blocking effect, 47-9 Pore throats, 47-21 Pore volume (PV), 26-l to 26-7. 26-22 Pore-volume compressibility, 26-7 to 26-10, 47-37, 47-38 Pore volume, laboratory measurement, 26-5 to 26-7 Porosimeter, 26-4 to 26-6 Porosity, apparent water filled, 49-34 balance check, 49-30 by density log, 49-26, 49-34, 49-36, 49-38 by electromagnetic-propagation tool, 49-36 by neutron log, 49-26, 49-34, 49-36. 49-38 by sonic log. 49-26, 49-27 compaction and compressibility of porous rock, 26-7 to 26-10 compressibility, 26-8 definition of, 27-l distribution, carbnate reservoirs, 36-6 effect on formation factor. 49-4 estimating, 51-5, 51-33 evaluation from acoustic log. 5 l-30 factor to consider in waterflooding, 44-2, 44-3 index, 49-38 introduction, 26-1, 26-2 investigation, 49-26 laboratory measurement of, 26-3 to 26-7 logs, 49-11, 51-29, 51-31, 51-32 measurement comparisons, 26-6 methods of determining, 26-4, 26-5 of consolidated rocks, 51-29 to 51-32 of poorly consohdated rocks, 51-33, 51-34 of secondary porosity. 51-31. 51-33 of shaly sand, 51-34, S 1-35 profile, 36-4 Rocky Mountain method, 49-31, 49-32 velocity relationship, 5 l-5 Porosity determination, bulk-density measurement, 50-l. 50-2 gamma-gamma density devices, 50-26 to 50-28 neutron-porosity devices, 50-28 to 50-33 Porous-diaphragm method of capillarypressure measurement, 26-24, 26-2.5 Porous diaphragm or membrane, 26-24 Porous reservoir models, 44-17 Port configurations, gas-lift valve, 5-15 Port size, selection for gas-lift valves, 5-28 Port-to-bellows area ratio, 5-15 Portable well testers, 32-6 to 32-8 Portland cement, 46- 19 Portugal, 58-20 Position-sensing valve switch, 16-3 Positive-death indicator, 56-5 Positive-displacement meter, 12-6, 12-18. 12-19, 16-2, 16-5 to 16-7, 16.12. 17-4 to 17-6, 32-6 to 32-8, 32-10 to 32-12 Positive-displacement meter, measurement of petroleum liquid hydrocarbons by, 17-4 Positive-displacement-meter prover tanks, tables, 17-6 Positive-displacement-meter-type LACT system, 16-13 Positive-displacement pumps. 6- 1, 6-34, 6-49 to 6-51, 6-62, 13-54, 15-14, 15-17, 28-4, 44-47 Positive-seal double-bag model, 7-11 Positive-seal protector. 7-4, 7-5
54
Positive-volume dump meters, 16-13 Positive-volume meters, 16-2, 16-5, 16-7 Possible reserves, definition, 404 Posted barges, 18-2 Potassium, 24-5, 24-9. 24-18. 24-20. 50-2 to 50-4, 50-16, 50-18, 50-24 to 50-27, 50-34, 50-35 Potassium chloride for control of clay swelling, 46-20 Potential distribution, 39-20 Potential energy, 6-1, 6-34, 13-1, 13-2, 34-28, 34-29, 34-36 Potential function, 26-l I Potential gradient, 26-I I, 39-2 1 Potential of a process, 13-50 Potential tests, 12-17, 41-19 Potential tests of oil wells, 32-l to 32-16 Potentiometric model, 39.21, 39-22, 44.17, 4419, 4434 Potentiometric model studies, 39-20, 39-21 Potentiometric transducer, 30-5, 30-6 Poth “A” sand, 46-29 to 46-32 Pothead, 7-5 Pounding, 6-33, 6-34 Pour point, 21-7, 21-9, 21-10, 46-27, 46-3 1, 46-33 Power cable, ESP, 7-5, 7-6 Power control manifold module, 6-54, 6-56 Power, definition of, 6-14 Power-distribution system, offshore, 18-45 Power equivalents, table, 1-78 Power-factor correction, lo-35 Power factor of motor, 10-25, IO-33 to IO-35 Power fluctuations, ESP, 7-14 Power fluid, 6-l to 6-5, 6-9, 6-10, 6-20, 6-21, 6-24 to 6-30, 6-34, 6-37, 6-38, 6-41, 6-42, 648, 6-51, 6-60, 6-62 Power-fluid discharge-pressure friction, 6-27 Power-fluid flow thyough nozzle, 6-42 Power-fluid friction, 6-30 Power-fluid friction pressure, 6-27 Power-fluid gradient, 6-25, 6-26, 6-29, 6-30 Power-fluid pressure, 6-7, 6-9, 6-16 to 6-18, 6-25, 6-27, 6-28, 641 to 6-43 Power-fluid systems, 6-54 to 6-57 Power-fluid tubing friction pressure, 6-42 Power-fluid tubing string, 6-2, 6-3 Power-law coefficient, 47-4, 47-9 Power-law model, 47-4, 55-5 Power method for parameter determination, 48-16 Power-oil emulsion, 6-31 Power-oil plunger pumps, 6-33 Power-oil tank and accessories, closed system, 6-59 open system, 6-57 to 6-59 Power stroke. IO-14 Power supplies, uninterruptable (UPS’s), 1845 Power triangle of motor, lo-33 to IO-35 Power, unit and detinmon, 58-11, 58-23, 58-24, 58-32 Powers of numbers, three-halves table, l-19, l-20 Powers of numbers, two-thirds table, I-20 Powers of SI units, 58-12 Pozzolan, 46-19 Precision of gas meter, 13-l Precision vs. accuracy, 58-8, 58-9 Predicted reservoir performance. 42-5. 42-6 Pre-exponential factor, 46-12 Preferred metric unit, 58-21, 58-26 to 58-38 Preflush, hydrochloric acid, 56-5 micellar/polymer flooding, 47-10, 47-15 systems, 56-3
PETROLEUM
PREOS. 25-R. 25-9, Z-16 Preparation of well for testing, 33-6 Present value or present worth, 41-3 to 41-8, 41-12, 41-16, 41-17, 41-23. 41-25, 41-27, 41-29, 42-6 Present-worth factor, 41-25 Present worth of an annuity, table, l-66 Pressure and force m static plunger and cylinder assembly. 6-18 Pressure, average drainage-region, 35-19, 35-20 Pressure-balanced valves, 13-55 Pressure-base factor, 13-3, 13-12 Pressure behavior, constant rate in closed reservoir, 35-2, 35-3 Pressure bombs, 304 Pressure-buildup analysis, 39-18, 39-19 Pressure-buildup behavior, 30-14 Pressure-buildup data, 6-48 Pressure-buildup tests, 42-3, 424, 48-8 Pressure changes in wellbore, calculations including, 46-6 Pressure-composition phase diagram, 23-2, 23-3, 23-6, 23-8, 23-9 Pressure control for high-pressure well, 13-56 Pressure controls, separators, 12-39 Pressure conversions. 58-7, 58-28. 58.29 Pressure correction for gas viscosities, 20-9 Pressure decline, rapid, 37-1, 37-2 Pressure dependence, of compressional- and shear-wave attenuation, 51-6 of compressional- and shear-wave velocities, 51-5 of porosity, 5 l-6 Pressure depletion, 26-21, 39-7 to 39.16, 39-23, 39-24, 39-26, 44-l Pressure-depletion behavior, 39-4 Pressure-depletion operation of GC reservoir, hydrocarbon/liquid-condensation effect, 39-13 prediction with laboratory-derived data and hydrocarbon analysis, 39-10, 39-l 1 prediction with vapor/liquid equilibrium calculation and correlation, 39-l 1 to 39-13 pressure drawdown at wells, effect on productivity and recovery, 39-13 relative merits of measured vs. calculated behavior, 39-13, 39-15 Pressure-depth diagram, 5-21 Pressure distribution, 35-6, 4417, 44-30 Pressure drawdown, 6-48, 34-31, 34-34, 35-6, 37-2, 37-19 to 37-21, 48-10 Pressure drop, across sand-tilled perforations, 564 in flowing gas column, 34-9 in gas lines, 15-5, 15-7 in liquid lines, 15-2, 15-3 in tubing, 6-70, 6-71 Pressure, effect on acid-reaction rate, 544, 54-5 effect on gas-saturated crude oils, 22-16 effect on tubing string. 4-9 Pressure equivalents, table, l-77 Pressure evaluation, 52-26 to 52-28 Pressure filters, 4447 Pressure for hydrate formation, 25-8 Pressure, force and flow in dynamic plunger and cylinder assembly, 6-18 Pressure function, 34-35, 37-8 Pressure gauges, 1242 Pressure gradient, 2-39, 34-29, 38-13, 39-21, 44-3, 44-6, 44-15 Pressure-gradient curves, 34-36
ENGINEERING
HANDBOOK
Pressure-gradient traverse, 5-25 Pressure-hydrometer test method, 17-J Pressure hysteresis, 48-10 Pressure-loaded balanced diaphragm valve, 13-56 Pressure log, 52-1, 52-26 Pressure maintenance. 23-1, 40.4, 40.14. 43-11 to 43-16, 48-2, 48-4 Pressure-maintenance operations, 18-44, 34-28, 43-l to 43-3. 43-8 Pressure maintenance or cycling of GC reservoirs. choosing between, 39-26 combination recovery procedures, 39-24 reservoir cycling, gas injection, 39-16 to 39-24 water drive and water inJection, 39-15, 39-16 Pressure-multiplier pump, 55-9 Pressure-operated gas-lift valve, 5-24 Pressure, optimum of separator, 12-4 Pressure/permeability data, 44-3 Pressure prlot, 13-56 Pressure/production history, 37-3, 37-6 Pressure profiles, 4-6, 35-4 Pressure pulses, 53-l Pressure radius, 4433 Pressure range, GC reservoirs, 39-2 Pressure rating classes of fittings, 15-13 Pressure ratings for steel pipe, 15-l 1 Pressure ratio, 6-36, 6-37, 6-45 Pressure recorders, 6-48 Pressure-recording charts, two-pen, 5-18, 5-23, 5-39, 5-41 Pressure-reducing regulator, 5-13. 12-39 Pressure-reducing valve, 13-55 Pressure reduction in gas analysis, 52-17 Pressure-reduction regulation, 13.54 Pressure regulators, 13-54 Pressure relationships used to estimate producing BHP, 6-28 Pressure relief of storage tanks, 1l-7 Pressure-relief valve, 6-5 1, 1 l-8, 1 l-9, 12-39, 19-28 Pressure ridges, 18-39 Pressure-sensing instrument (PSI), 7-7, 7-8 Pressure shock loads, 12-42 Pressure, SI unit for, 58-5, 58.11, 58-23 to 58-25, 58-28, 58-29 Pressure storage of products, 1 I - I2 Pressure, surface closing, gas-lift valves, 5-44 to 5-46 Pressure surveys, 5-2 Pressure switches, 16-4 Pressure/temperature diagram, 14-2 Pressure/temperature phase diagram, 23-6 Pressure/temperature rating of steel, 3-38 Pressure-transducer technology, 30-6 to 30-E Pressure transducers, 46-21 Pressure-transient behavior, 354 Pressure-transient tests, 5-3 Pressure transition zone, 52-2 I Pressure traverses, 34-36, 34-41 to 34-44, 41-41 to 41-44 Pressure/vacuum relieving system, 11-13 Pressure/vacuum valves, 1 l-8, 11-9 Pressure/volume (PV), compressibility, 51-49 diagram for pure components, 20-2 equilibrium cell, 204 method for waterflood water requirements, 44-41 relation, 20-2, 20-6, 39-7 Pressure-volume-temperature (PVT), analysis, 22-1, 22-5, 22-10, 22-13, 40-21 cell, 39-13
SUBJECT INDEX
data, 7-9, 37-3, 37-22, 40-6 properties, 44-37, 48-2, 48-13 Pressure waves, 51-2 Pressures and forces in reciprocating pumps. 6-10, 6-14 to 6-16 Pressures and losses. in closed power-fluid installation, 6-26 in open power-fluid installation, 6-25 Pressures, forces and flows m hydraulic transformer, 6- 19 Pressures in downhole pumps. 6-16 to 6-19 Pressurized ball joints. 18-12, 18-13 Preventton of emulsions, 19-5 Primary cementing, 56-4 Primary depletion, 37. I, 42-2 Primary drainage, 28-12 Prtmary electric power, 1X-44, I X-45 Prrmary electrical system, IO-29 Primary functions of 011 and gas separators, removal of gas from oil, 12-3 removal of oil from gas, 12-3 separation of water from oil, 12-3, 12-4 Primary oil recovery, 24-3, 40-33 Primary performance, injection operations, 42-3. 42-4 Primary-performance predictions, volatile oil reservoirs, 37-23 Primary porosity, 26-l, 29-3. 36-6 Primary production. 41-12 Primary recovery. 42-l. 45-9 Primary-recovery methods and operations. 44-1. 44-2, 445, 44-36 Primary separation m separator, 12-19, 12-20 Primary separator gas, 39-6, 39-9. 39-10. 39. I4 Primary stratigraphic traps, 29-4, 29-5 Primary term. habendum clause, 57-4. 57-5 Primary waves. 5 l-2 Prime movers for pumping units, electric motors, IO-19 to IO-37 internal-combustion engines, IO-14 to IO-19 Principal amounting to a given sum, table, l-64. l-65 Principle of additive volume, 20-l I Principle of corresponding states, 20-4, 20-5. 20-9. 20-13 Principle of flux-leakage tool, 53-22, 53-23 Principle of operation. reciprocating pumps. 6-8 to 6-32 Principle of superposttion, 38-l to 38-3 Principles of regulation control. derivative response, 13-52. 13-53 nomenclature of process controls, 13-49, 13-50 process characteristics, 13-50 proportional control, 13-5 I, 13-52 reset, 13-52 Principles of TVD. TST, and TVT plots. 53-15, 53-16 Prism diagram, 47-12, 47-13 Probabrhty theory, 26-28 Probable error. factors for computing, table, l-61 Probable reserves, 40-4 Problem examples: see Example problems Problems. common to steamfloods and firefloods, 46-2 I. 46-22 plaguing tirefloods only, 46-22 plaguing steamfloods only, 46-22 Problems, special in or1 and gas separators, corrosion, 12-S paraffin, 12-7. 12-8 sand. silt, mud, salt. etc. 12-8 separating foaming crude oil, 12-6, 12-7
55
Process characteristics, 13-50 to 13-53 Process control computer. 16-10 Process equipment and facilities offshore, 18-28. 18-30, 18-32, 18-42 Process flow for expansion process. 14-8 Process flow sheets, 15-31 Process model, 28-3 Process selection, 15-30 to 15-32 Processing plant, 11-13 Procurement, an engineering effort, 15-31 Pro-Dip log and wellsite analysis, 49-37 Produced-fluid gradient, 6-25, 6-26, 6-29, 6-44 Produced-product prices. 41. I I Produced water, 12-3. 24-5 Producer BHP, steamfloods, 46-17 Producibdity of well, 39-5, 39-6 Producing efticrency, 30-15 Producing gas/oil ratio (GOR), 6-27, 37-l to 37-3, 37-5, 37-7. 37-9 to 37-14, 37-22. 37-23, 37-26, 39-2 Producing properties. check list of data required for oil and gas, 41-8, 41-9 Producing wells, gas, 34-3 to 34-27 gas-condensate, 34-27, 34-28 gas/water flow, 34-27 Product thread form, extreme-line casing joint, 2-64, 2-71. 2-72 Production casing string, 3-S Production data, ESP. 7-9 Production decline, 41-9 to 41-l 1 Production decline curves, constantpercentage, 40-28 to 40-32 decline tables for constant-percentage decline, 40-30 to 40-32 economic limit. 40-27 general principles, 40-26, 40-27 harmonic, 40-29, 4 L 10 hyperbolic, 40-28 loss-ratio method. 40-32 nominal and effective decline, 40-27 relatronship between effective and nominal decline. 40-29 reserves and decline relationship, 40-32 straightening curves, 40-3 I to evaluate pilot flood performance, 44-39 types of, 40-28. 40-29 types of plots. 40-3 1 Production discharge friction pressure, 6-27 Production equipment, tank battery, I l-9 to 1 l-l I tank grades, I l-l 1 Production fluid gradient, 5-40 Production history. 41-9 Production loans, 44-5 Productton logging, 53-17 Production mechanisms, 46-4 Production packers, classification and objectives, 4-l combination tubing/packer systems, 4-l I considerations for packer selection, 4-4 to 4-6 in production packing, 56-8, 56-9 referencea, 4-I 1 tubmg/packer forces on intermediate packers. 4-I 1 tubing/packer systems, 4-6 to 4-9 tubing response characteristics, 4-8 to 4-l 1 tubing-to-packer connections. 4-1 utilzation and constraints, 4-I to 4-3 Production payments. 41-1, 41-2, 41-t. 41-9. 41-15. 57-7 Production-pressure effect. 5-18, 5-30 Production-pressure factors, 5-14, 5- I7 to 5-22. 5-24. 5-26. 5-27. 5-32. 5-33, S-35, S-39, S-40. 5-42. 5-44, 5-48, 5-54
Production-pressure-operated gas-lift valve. 5-13, 5-16, 5-17. 5-21. 5-32, 5-33. 5-35 to 5-37, 540, 5-54 Production profile, 40-l Production-rate allowables. 32-1, 43-2, 43-10 Production-rate and time calculations, solution-gas-drive. introduction, 37-17 rates based on IPR, 37-19 to 37-21 rates based on PI, 37-19 time required for oil production, 37-21. 37-22 Production rate of gas wells, 33-20 Production rate variation (superposition), 35-8, 35-9 Production response from high-pH flood, 47-22 Production safety controls, 16-4 Production separator, 12-17 Production string, 3-39 Production structures offshore, artificial islands, 18-40, 18-41 gravity type, 18-41, 18-42 piled, 18-42 Production taxes, 41-l. 41-3, 41-4, 41-12 Production tests, 18-34 Production-transfer-pressure traverse, 5-36 Productive stringer. 36-7 Productivity, decline or loss, 39-25 Productivity, effect of damage on, 54-8, 54-9 Productivity, from drawdown tests. 4442 Productivity index (PI), 5-38, 5.39, 5.45, 641, 6-46, 30-10 to 30-13, 30-15, 32-2 to 32-6, 34-30 to 34-36, 35-6. 35-10. 37-19 to 37-21, 40-27, 42-4. 46.10. 58-14, 58-38 Productivity index for different GOR’s, 32-5 Productivity-index/permeability correlation, 32-4 Productivity ratio, 30-13. 30-14 Productivity test, 24. I, 39-25 Products of crude oils, temperature correction for, 17-5, 17-6 Profile calipers, 53-17. 53-18 Profile of a gravity system, 15-15 Profiles, injection-gas volumetric throughput. 5-20 Profit margin. 41-6 Profit margin and cost relatronship, 36-2 Profit-to-investment ratio, 41-7 Profitability, 39-17 Programmable calculators, 6-34, 6-38, 6-4 I, 6-46, 20-7, 20-9 Programmable controllers, 16-4, 18-47 Programmable logic controllers, 19-29 Programmer for oilfield motors, lo-27 Project control, 15-32, 15-33 Project definition, 15-30 Project design, thermal recovery. features common to both steamfloods and firefloods, completion intervals, 46. I7 pattern selection, 46-17 producer BHP, 46-17 features pertaining to firefloods only. air injection rate, 46-19 dry vs. wet gas combustion, 46-18 WAR, 46-19 features pertaining to steamfloods only, steam injection rate. 46-18 steam quality, 46- 18 Project execution format. 15-31, 15-32 Project inspection and expediting, 15-31 Project management, 15-30 to 15-32 Projected oil recovery. 42-2. 42-3
56
Prolog wellsite analysis, 49-37 Pronunciation of metrjc terms, 58-13 Propagarion time, 49-32, 49-34 Propane as IC engine fuel, IO-16 Propane as refrigerant, 14-9 Propane compressibiliiy table, 17-7 Propane critical pressure, 25-3 Propane/water system. 25-2. 25-3. 25-17, 25-25. 25-21 Properties and behavior of gas condensate tluids, composition ranges, 39-2 gas/liquid ratios, 39-4 introduction, 39-l liquid contents, 39-4 phase and equilibrium behavior, 39-2 to 39-4 pressure and temperarure ranges. 39-2 properties of separated phases, 39-4 viscosities, 39-4 Properties of construction materials for pressure vessels, 12-41 Properties of crude oils and gas condensates, 39-2 Properties of produced waters, analysis methods for oilfield water, 24-5 chemical properties of oilfield waters, 24-5 to 24-13 morgamc constituents, 24-9, 24-12 interpretation of chemical analyses, 24-18, 24-19 introduction and history, 24-I to 24-3 nomenclature, 24-20 occurrence. origin. and evolution of oilfield waters, 24-19. 24-20 physical properties of oilfield waters. 24-12 to 24-18 recovery of minerals from brmes. 24-20. 24-2 1 references, 24-21, 24-22 sampling, 24-3 to 24-5 Properties of separated phases, CC streams, 39-4 Properties of ternary diagrams, 23-4 Proportional action of controller, 13-52 Proportional control, 13-49, 13-51 to 13-53, 13-56 Proportional counter, 50- 14 Proportional pilot for pneumatic service, 13-56 Proportional/reset controller, 13-52 Proportionality constant for rock, 26. II Proppant, density, 55-8 grain roundness factor. 55-8 grain size, 55-8 grain-size distribution. 55-8 grain strength, 55-8 permeability. 55-8 placement, 55-8 quality, 55-8 transport. 55-7, 55-9 Proppant-transport properties, 55-5 Propping agent, amounts used. 55-l definition of, 55-2 grain size of, 55-8 grain strength of, 55-8 permeability, 55-4 placement of, 55-8 Propylene. 14-9 Propylene compreasdxlity table, 17-7 Propylene/water system. 25-25 Propyneiwater system, 25-25 Proration, 41-3, 41-10, 41-11 Proration records, 13-3 Protected~slope production island, 1X-40
PETROLEUM
Protectmn equipment for oilfield motors. air circuit breaker, lo-28 control fuses, IO-29 lightning arresters, IO-28 motor fuses, IO-28 motor-winding temperature sensors, 10-29 over-temperature lockout circuit, 10.29 phase loss relay. 10-28, IO-29 pumping-unit vibratmn switch, lo-29 thermal-overload relay, lo-29 under-voltage relay, lo-28 Protective coatings, 9-10 Proved developed reserves, definitmn, 40-3 Proved reserves definitmns, 40-2 Proved undeveloped reserves, definition, 40-3 Proving systems, 17-4 Proximity log (PL), 49-22 to 49-25, 49-27 Prudhoe Bay field. Alaska. 18-3, 18-39, 18-41, 48-17 Pseudo-Rayleigh waves. 51-12 to 51-14. 51-25. 51-27 Pseudobinary diagram, 23-9 Pseudocomponenta, 47-I 1 Pseudocritical calculations, from gas analysis, 40-21 from specific gravity, 40-22 Pseudocritical constants, corrected, 20-5 Pseudocritical density, 20-10, 20-15 Pseudocritical pressure, 20-5. 20-7, 20-10, 20-16. 22-12, 40-21, 40-22 Pseudocritical properties, 22-2 I, 34-4 PseudocrItical properties of C, + , 20. IO Pseudocritical temperature, 20-S, 20-7, 20-10. 2I)-16. 22-12, 40-20, 40-21 Pbeudocrltical-temperature gradient factor. 20-7 Pseudocriticals. for heptanes and heavier, 21-17 of gases and condensate well fluids, 21-19 Pseudogeometrical factors, 49-22, 49-25 Pseudoliquid density, 22.2 to 22.4 Pseudophase theory, 47-13 Pseudoreduced compressibility, 20-I 1, 20-12, 22-12, 22-13 Pseudoreduced pressure, 20.5. 20-9, 20-l 1, 20-12. 22-13, 22-21. 40-21 Pseudoreduced properties, 22-21, 34-5 to 34-7, 34-10 to 34-22. 34-24 Pseudoreduced temperature, 20.5. 20.9, 20-11. 20-12, 22-13, 40-21 Pseudorelative-permeability curves, 37-4, 48-8 to 48-10, 48-12 Pseudorelative-permeability data, 37-4, 37.5 Pseudostatic SP. 49-9, 49-10. 49-28 Pseudosteady state, 35-2, 35-3, 35-7, 35-8, 35-10. 35-12 to 35-14. 35-16 Pseudosteady-state aquifer productivity index. 38-8 Pseudosteady-state behawor. 35-6 to 35.8, 35. I5 Pseudosteady-state flow. 5.25. 32.3 to 32-6, 33-5 to 33-7, 34-30, 34-31, 37-19, 37-2 I Pseudoternary diagram, 45-2. 45-3, 45-5 Public Law 93-380, Aug. 21, 1974, 1-69 Public Law 94-168. Dec. 23, 1975, 1-69 Puffer, 52-6 Pull bar. 7-12 Pull curves. casing-hanger. 3-6, 3-7 Pull-m procedure, IS-37 Pull sheet, 53-17 Pull tube, 8-4 Pulling and running sucker rods, 9-10 Pullout strength of line-pipe joint, 2-62 Pulsation dampers, 6-50. 6-51, 6-61. 15-17 Pulse testing or testa, 36-7. 36-8, 48-8
ENGINEERING
HANDBOOK
Pulsed-data transmission systems, 17-4 Pulsed nuclear magnetic resonance analyzer, 52-26 Pulsed-neutron logging. 50-36 Pulsed-neutron logging devices, 50-2 1, 50-22 hltrusion process, 9- 12 Pump discharge pressure, 6-17, 6-25 to 6-21, 6-28, 6-41 to 6-43, 6-47, 6.49, 6-5 1 Pump displacement, 6-I 1 10 6-13, 6-15, 6-16. 6-21, 6-24. 6-29, 6-30, 6-52 to 6-55, 8-5. 8-9, 9-2 Pump drivers, 15-15, 15-16 pump efficiency, 6-24. 6-3 1, 6-37, 6-38, 6-49, 46-2 1 Pump-efficiency equations, 6-68 Pump-end volumetric efficiency, 6-2 I, 6-22 Pump intake, 7-4, 7-5 Pump-out method of solution mming, I l-13, II-14 Pump performance curve, 7-10, 7-l 1 Pump piping and installation, 15.17 Pump-protector motor unit, 7-2 Pump selection, 8-2 to 8-4 Pump-selection table. 7-10 Pump speed, maximum rated, 6-I I to 6.13. 6-15, 6-16, 6-21 Pump submergence. 6-25. 6-26 Pump suction gradient, 6-42, 6-44 Pump-suction (intake) pressure, 6-4, 6-17. 6-25, 6-26, 6-38, 6-43. 6-47 Pump terminology, 8-2. 8-6 to 8-9 Pumpdown pressure recorders, 6-34 Pumped-off well, definition of, 10-27 Pumping equipment for fracturing, 55-9 Pumping speed factor. IO-6 Pumping speed, maximum practical. 9-4, 9-5 Pumping-unit bearings, IO-5 Pumping-unit design calculations, IO-8 to 10-l I Pumping-unit geometry, 9-2. IO-2 Pumping-unit loading, IO-5 Pumping units, 10-I to IO-13 Pumpoff, 7-6. 7-10, 7-16 Pumpoff controls, lo-27 Pumpstroke counter, 52-I I Pure Oil Co., 54. I Purging offshore distribution system, IS-46 Pycnometer, 26-3 Pycnometer method, 52-19 Pyo&type thermocouple, 16-7 Pyramidal rule, 40-5 Pyrenees Mts., 46-27 Pyroanalyzers, 52-28 Pyrolysis. 52-l
Q Quadruple point. 25-15 Quality control. 12-38 Quality factor. 5 l-4 Quality of foams, 47-8 Quality of separated fluids. 12-13, 12-15 Quality power oil, 6.55 Quantities (chemical, electrical, and physical) in alphabetical order, 59.18 to 59-5 I Quantity, definition. 58-9 Quartzose sediments. 29-7 Quaternary compounds. 44-45 Quaternary diagrams. 24-19 Quench water. 46-2 I, 46-22 Quick-cycle units, 14-10, 14.13 Quintaplex pump, 55-9 Quintiplex positive-displacement pump, 6-I. 6-49. 6-5 1
SUBJECT
INDEX
57
R Rabbiting, 56-3 Radial aquifers, 38-2 to 38-4, 38-8 to 38-19 Radial differential temperature log, 31-7 Radial-flow equation, 30-12 Radial-flow pumps, 15-15 Radial-flow system, 26-13 to 26-15 Radial frontal advance, 38-13 Radial geometry, definition, 38-l Radial gridded simulator, 37-21 Radial pseudogeometrical factors, 49-20 Radians expressed in degrees, table, 1-43 Radiation, 46-4 Radiation detector. 50-14 Radiation heat-transfer coefficient, 46-5 Radiation log. 49-25 Radiation, units and conversions, 58-37 Radio frequency, 19-3 I Radio-frequency preheater, 9-12 Radio triangulation systems, 18. I8 Radioactive capture, 50-9 Radioactive decay, 50-4, 50-6, 50-21 Radioactive isotopes, 50. I5 Radioactive rocks. 58-33 Radioactive tracers. 284, 46-2 I Radioactivity logging and logs, 41-8, 5142 Radioactivity surveys, 49-l Radiograph, of areal sweepout efficiency. 44-18 of welded pipe, 1241 Radioisotopes, 46-2 I Radionuclide. 58-10 Radium. 50-4. 50-6, 50-15 Radius of circumscribed circle, equation, I-36 Radius of curvature method of calculating directional surveys, 53-5 Radius of inscribed circle. equation. l-36 Ram preventera. 18-l I, 18-12, 18-15 Ramey’s equation for wellbore heat transmission, 46-5. 46-6 Ramey’s generalization of MarxLangenheim method, 46-8 Random flood pattern or network, 44-13, 44-14. 44-17 Randomized network model, 28-12 Range lengths. API casing and liner casing, 2-3 API tubing, 2-37 line pipe, 2-47 Rangeability of gas meter, 13-I. 13-45, 13-48 Rangely field. Colorado, 23-9. 23-10. 26-23, 48-6 Raoult’s law. 23-l 1 Rarefactions, 51-2 Rasching rings, 12-10 Rate/cumulative curve or relationship, 40-25. 40-27 to 40.29, 40.31, 40-32 Rate-dependent skin factor, 35-10 Rate of frontal advance, 39-17 Rate-of-penetration (ROP). 52-l I, 52-13. 52-18. 52-24. 52-25. 52-27 to 52-29 Rate-of-penetration log. 52-1 Rate of return (ROR), 41-6 to 41-8. 41-16 to 41-24, 442 Rate/pressure curves. 44-36 Rate/time curve or relationshlp, 40-27 to 40.29, 40.31, 40.32, 41-10 Ratio(s). air/water, 46-33 compression, 6-10, 6-21, 8-9, 8-10. 10-15, 18-14, 39-24 conductance, 4434 damage. 30-13
equihbrium, 21-1 I, 21-16. 23-11, 25-5, 39-6, 39-9. 39-1 I to 39-13, 39-15 equilibrium vaporization, 37-23 gas-gravity/condensate-gas, 34-28 gas/oil, 5-25, 5-26. 6-24, 6-25, 6-29, 6-30, 6-38, 6-39, 6-44. 6-47, 12-35, 22.20, 3441 to 34-43, 34-47 to 34-44, 38-16, 39-l, 39-2. 40-33, 41-8, 4439, 58-38 injectivity/productivity, 46-17 liquid/gas, 12-35, 39-2, 39-5 methods. 49-28 net-pay/net-connected-pay, 36-17 net-profit/initial-investment, 41-22 net-profit/unreturned-investment balance, 41-22 of differential pressure to absolute pressure, 13-8 of epithermal counting rates, 50-20, SO-29 of gas-cap/oil-zone volume, 37-5, 37-6, 37.13, 37-14 of net profit. constant, 41-20 of nozzle area to throat area, 6-34 of orifice to pipe diameter, 13-36 of pump displacement to engine displacement, 6-18 oil/steam, 46-9. 46-15, 46-23 permeability. 37-14, 37-15 permeability/viscosity, 47-8 piston/engine (P/E), 6-l I to 6-13, 6-15, 6-16. 6-18. 6-27, 6-28, 6-30 piston pneumatic/hydraulic pump, 3-33 pore aspect. 51-9. 51-12 pressure. 6-36. 6-37. 6-45 producing gas/oil, 6-27, 37-l to 37-3, 37-5, 37-l. 37-9 to 37-14, 37-22, 37-23, 37-26, 39-2 productivity, 30-13, 30-14 profit-to-investment, 41-7 sand. 36-4 solubilizatlon, 47-13, 47-14, 47-20 stage compression, 39-24 stage pressure, 12-33 steam/oil. 46-8, 46-14, 46-15, 46-23, 46-24. 46-27 steam/tar. 46-27, 46-28 sulfur/oxide. 52-7 surface~gas~gravity/weKtluid~gravity, 21-17 tube amplitude, 51-47, 5148 velocity. 51-38 viscosity, 43-5, 43-6, 45-7, 45-l I viscosity vs. pseudoreduced temperature, 20-9 viscous/gravity forces. 44-25 volumetric, 55-6 water/oil, 19-17, 24-20, 28-5, 34-41, 40-18 to 40.20, 447, 44-9. 441 I. 44-3 I, 44-32. 44-39. 46-33 water/oil mobility. 43-7. 448, 47-6 water/oil viscosity, 40-18, 44-10 Reaction kinetics, 48-2 Reaction-rate equation. 46-12 Reaction rate of acids, factors affecting, acid concentration. 54-5 area/volume ratio, 54-5 corrosion inhibitors. 54-6 flow velocity, 54-5 formation composition, 54-6 pressure, 54-4 temperature. 54-4. 54-5 Reactive tluids. effect on permeability measurements. 26-18. 26-19 Reactive power rating of transformers (kVAR). 10-31, lo-33 to IO-35 Real-gas law, 20-4. 20-I I Real-gas pseudopressure, 35-10
Real gases. 20-4 Real property, definition. 57-l Receipt and delivery tickets, 17-7 Receiver of sonic meter, 13-49 Reciprocal gas formation volume factor, 40-22, 40-23, 40-33, 40-34 Reciprocal mobility ratio, 44-19. 4422, 44-23 Reciprocal of numbers. table, I-21 to 1-23 Reciprocated induction curve, 49-15 Reciprocating oilwell pumps, 8-l Reciprocating piston positive-displacement meter, 32-l I Reciprocating pump, displacement of downhole pumps, 6-2 1, 6-24 equipment selection and performance calculations, 6-28 fluid friction and mechanical losses in hydraulic pumps. 6-19 to 6-21 for waterfloods, 15.14. 15.15, 15.17, 15-18 gas/liquid ratio in vented systems, 6-27 in closed power-fluid systems. 6-4 in reverse-flow systems, 6-5 manufacturer speciticatlons, 6-l 1 to 6-13, 6-15, 6-16 multiphase flow and pump discharge pressure, 6-27 pressure and force balance in downhole pumps, 6-16 to 6-19 pressure and forces in, 6-10, 6-14 to 6-16 pressure relationships used to estimate producing BHP, 6-28 principle of operation, 6-8 to 6-10 subsurface troubleshooting guide, 6-3 I system pressures and losses in hydraulic installations, 6-24 to 6-27 turbulence in, 19-5 worksheets and summary of equations, 6-29, 6-30 Recoil electron ejection, 50-12 Recombined separator samples, 39-5 Recommended practices before unloading, 5-53 Recompletion costs. 41-9, 4 I 12 Recompletions. 41-9, 44-7 Recorder for metering system, 13-36. 13-37 Recording acoustic data. methods of. acoustic-array logging, 5 l-25 to 5 I-27 amplitude/time recording, 51-18 conventional acoustic logging, 5 I I5 to 51-18 intensity/time recordmg. 51. I8 introduction, 5 I I4 long-spaced acoustic logging, 5 I- I9 to 51-24 reflection, 51-27. 51-28 shear-wave logging, 5 l-24, 5 1-25 Recording ammeter, 7-14 Recording caliper logs, 53-16 Recoverable gas reserves, 40-24, 40-27 Recoverable gasoline content. 20-I I Recoverable hydrocarbon reserves, 4 l-3 Recoverable hydrocarbons, 39-26 Recoverable oil, 40-27, 44-32, 4437. 44-38 Recovery by miscible displacement, 45-9. 45. IO Recovery by pressure maintenance, 39-9 Recovery efficiency, 39-l I, 39-15. 42-5. 43-2, 43-6, 43-9. 44-3. 45-B. 45.12. 45-13, 46-14, 46-27. 47-16, 47-17 Recovery-efficiency factor, 40-16. 40-17 Recovery estimates. 40. I Recovery factor, 40-l. 40-I 1. 40-19. 40-20. 40-23, 40-25 to 40-27
58
Recovery factor, average from correlation of statistical data, 40-16, 40-17 Recovery factor vs. reserv~lr pressure, 37-14, 37-15 Recovery from gas reservoirs with water drive, 40-26, 40-27 Recovery of LPG products, 45-12 Rectangular tanks, 1 l-2 Rectilinear flow of compressible fluids, 26-11 Red Sea, 24-19 RedalertTM motor controller, 7-6, 7-16 Redlich and Kwong equation, 20-7, 20-8, 23-12, 23-13 Redox potential (Eh), 24-4, 24-5, 24-9, 24-16, 24-17 Reduced properties, definition, 22-2 1 Reduced-state relationships, 22-2 1 Reduced vapor pressure, 20-13 Reducing agents, 54-7, 56-3 Reduction factor or ratio, 6-50, 49-9 Redundancy, subsea production facilities, 1848 Redwater D-3 pool, Alberta, Canada, 40-20 Redwater field, Alberta, Canada, 40-Z Reel barges, 18-37, 1X-38 Re-entry systems, 18-14 References (see also General References), acidizmg, 54-12 acoustic well logging, 51-50 to 5 l-52 automation of lease equipment. 16-16 bottomhole pressures, 30.16. 30-17 casing, tubing, and line pipe, 2-74 chemical floodmg, 47-24 to 47-26 crude-oil properties and condensate properties and correlations, 2 i-20 development planning for oil wells, 36.10, 36-l 1 electric submersible pumps, 7-17 electrical logging, 49-41 estimation of oil and gas reservoirs, 40.37. 40-38 formation fracturmg. 55-10 gas-condensate reservoirs, 39-27. 39-28 gas-injection pressure maintenance in oil reservoirs, 43-19 gas lift, 5-57 gas measurement and regulation, 13-59 gas properties and correlations, 20-18 hydraulic pumping, 6-72 lease-operated hydrocarbon-recovery systems, 14-22 measuring, sampling and testing crude oil. 17-8 mixable displacement, 45. I3 to 4% 15 mud logging, 52-30 nuclear logging techniques, 50-38 offshore operations, 18-52 oil and gas separators. 12-43 oil storage, 1 I- 14 oil-system correlations, 22-21, 22-22 open flow of oil wells, 33-23 other well logs. 53-26 petroleum reservoir traps. 29-9 phase behavior of water-hydrocarbon systems. 25-20 to 25-24 phase diagrams, 23-13 potential tests of 011 wells, 32-16 production packers, 4-l I properties of produced water, 24-21 to 24-23 propertles of reservoir rocks, 26-33 pumping units and prime movers for pumpmg units. IO-37 relative permeability, 28-15. 28-16 remedial cleanup and other stimulation treatments. 56-9
PETROLEUM
reservoir simulation, 48-17 to 48-20 solution-gas-drive oil reservoirs, 37-27 subsurface sucker-rod pumps, S-10 sucker rods. 9-14 surface facilities for waterflooding and saltwater disposal, 15-33, 15-34 temperature in wells, 31-7 thermal recovery, 46-43 to 46-45 typical core analysis of different formations, 27-9 valuation of od and gas reserves, 41-37 water-drive oil reservoirs, 38-20 water-Injection pressure maintenance and waterflood processes, 44-49 to 4452 well-performance equations, 35-21 wellbore hydraulics, 34-55, 34-56 wellhead equipment and flow-control devices, 3-40 Reflected conical wave, 51-12 Reflection method, acoustic-wavepropagation logging. 51-I I, 51-27. 51-28 Reflection peak, 49-13 Refrigerants, comparison of common types, 14-9 Refrigerants, properties of six types. 14-10 Refrigerated storage, 1 l-12 Refrigeration process, 14-9 Regeneration cycle, 14-10 Regeneration gas, 14-l 1 to 14-14, 14-20, 14-21 Regeneration-rate controller, 16-15 Regeneration system, 14-6, 14-7, 14-l 1, 14-12 Regression equations, 46- 15 to 46-17 Regular polygons, table, 1-36 Regulator types, 13-54 to 13-57 Regulatory agencies, 16-1, 16-2, 18-12, 19-28. 32-1, 32-2, 32-15. 33-5, 40-1, 40-3, 40-4. 41-3. 43-2 Regulatory agency form, 32-2 Regulatory codes. 18-44 Reid vapor pressure (RVP), 12-33, 14-13. 17-3, 21.1Y Reiatel diagram, 24-19 Relationship, between bending and curvature radius of casing, 2-61 between total and external load of casing, 2-6 1 Relative atomic mass, 58-24 Relative bearing, dipmeter. 53-10 Relative density, correction of observed value, 17-5, 17-6 definition of, l-80, 58-24 hydrometer test method, 17-5 of C,+ fraction. 20-10 of crude petroleum, 17-5 of liquid petroleum products, 17-5 of natural gas, 20- I3 Relative dielectric permittivity. 49-32 Relative molecular mass, 58-24 Relative oil volume, definition, 22-21 Relative permeability, calculating cumulative gas production, 31-10 conclusions, 28-13, 28-14 critique of recent work. 28-10 to 28-12 curves, 28-6, 28-8 to 28-13 definition. 2X-l effect of GOR or WOR changes, 30-l I factor in waterflooding, 44-2 framework ideas, 28-2, 28-3 general references, 28-16 historxal background, 28-2 in determining mobdity in a layer, 44-9 in two-phase fluid flow, 55-8
ENGINEERING
HANDBOOK
introduction, 28-1, 28-2 measurement methodologies, 28-3 to 28-9 nomenclature, 28-14 of reservoir rock, 44-4, 44-5 ramifications needing attention, 28.12, 28-13 recent literature, 28-9, 28-10 references, 28-15, 28-16 Relative-permeability characteristics, 37-2, 37-19, 44-27 Relative-permeability curves, 28-6, 28-8 to 28-13, 34-31, 39-13, 44-6, 46-13, 46-34, 46-37 Relative-permeability data, 37-3, 37-4, 37-10, 39-9, 40-13, 43-11, 46-12 Relative-permeability-ratio data, 37-23 Relative-permeability ratios, 40-8 to 40.12, 40-14, 43-5 to 43-7. 43-12 Relative pipe roughness, 15-2. 15-3, 15-7 Relative-roughness factor, 34-2, 34-3, 34-38, 34-40 Relaxation pressure, 40-34 Relays for motors, IO-28 Reliability/maintainability, subsea production facilities, 18-48 Reliability of gas meter, 13-l Reliability of sensors. 3-3 1 Remedial operations, 4-9, 33-22 Remedial work, 41-8 Remedial workover operations, 39-24 Remote, closed-loop controls, 18-46 Remote control of subsea equipment, 18-48 Remote-control valves, 18-3 Remote-controlled SSV system. 3-34 Remote terminal umt (RTU), 16-4, 16-6, 16-8 to 16-l 1 Removal of acid gases, 14-21, 14-22 Removal of CO,, 14.17, 14.21, 14-22 Removal of gas from oil, 12-3 Removal of gas from oil in separators, methods used, agitation, 12.13 baffling, 12-13 centrifugal force, 12-13 chemicals, 12-13 heat, 12-13 settling, 12-13 Removal of HZS, 14.17, 14.21, 14-22 Removal of oil from gas, 12-3 Removal of oil from gas in separators, methods used, centrifugal force, 12-9, 12-10 coalescence, 12-10, 12-l I density difference (gravity separation), 12-8 filtering, 12-l 1 flow-direction change, 12-9 flow-velocity change, 12-9 impingement, 12-9 Removal of water vapor, 14-17 to 14-21 Repeatability of BHP gauges, 30-4. 30-6 Repeatability of meters, 13-48 Reperforation, 56-l Representative-element simulation, 48-7 Reproducibility, 13-50 Reserve SPE letter symbols, 59-2 to 59-51 Reserve SPE subscripts. 59-52 to 59-70 Reserved production payment, 4 I - 1 Reserves. and decline relationship, 40-32 cost of developing. 42-1, 42-2 possible, 36-l. 40-4 probable, 36-1, 40-4 proved, 36-l. 40-2. 40-3 proved developed, 40-3 proved undeveloped, 40-3 ultimate depletion of. 42-2
SUBJECT INDEX
Reserves, oil and gas, definition and nomenclature, 40-2, 40-3 estimating, 40-1, 40-2, 40-12 general references, 40-38 glossary of terms, 40-3, 40-4 nomenclature, 40-35 to 40-37 nonassociated-gas reservoirs. 40-2 1 to 40-26 oil- or gas-in-place computation, 40-5 to 40-S oil reservoirs under gravity drainage, 40-14. 40-15 oil reservoirs with gas-cap drove, 40-13. 40- 14 oil reservoirs with water drive, 40-15 to 40-2 I performance curves, 40-32 production-decline curves, 40-26 to 40-32 references, 40-37, 40-38 reservoir-volume computation, 40-4, 40-5 saturated depletton-type oil reservoirs, 40-8 to 40-12 undersaturated oil reservoirs without water drive. 40-12 volatile 011 reservoirs, 40-13 Reservoir above bubblepoint pressure. 38-13 Reservoir anisotropy, 36-8 Reservoir below bubblepoint pressure, 38-13 Reservoir continuity, 36-6 to 36-8 Reservoir-controlled fluids, 55-2, 55-4 Reservoir coverage. 39. I8 Reservoir cycling efticlency, 39-17, 39-18, 39-22, 39-23 Reservoir cycling, gas injection, calculation of cycling performance, 39-17 to 39-20 dry-gas injection, 39-16 inet--gas injection, 39-16. 39-17 noninjection-gas requirements, 39-23, 39-24 prediction of operations with mathematical reservoir simulator, 39-22, 39-23 prediction of operations with model studies. 39-20 to 39-22 ultimate recovery, 39-23 Reservoir cycling operations, efficiency terms, 39-l 8 Reservoir, definition, 40-3 Reservoir deliverability, 5-23 Reservoir depth, 442, 443 Reservoir description, uncertain data, 48-12 Reservoir-dip effect, 4425 Reservoir discontinuities, 36-4, 36-5 Reservoir engineer, 22-10, 26-7, 36-10, 39-3, 39-24, 44-7, 4.431 Reservoir-fluid characteristics, 36-1, 36-2, 424, 42-5 Reservoir-fluid compositions, 37-24 Reservoir-fluid properties, 43-10 Reservoir-fluid recovery. 39-23 Reservoir-fluid samples, 424 Reservoir-fluid systems, phase diagrams, 23-6, 23-7 Reservoir-fracture effect, 4425. 4426 Reservoir geometry, 44-2 Reservoir-geometry factor, 38-13 Reservoir heterogeneities, 28-l 1, 30-14 Reservoir identification from mud log, 52-15 Reservoir interference, 38-3, 38-4 Reservoir limit tests, 32-5 Reservoir performance, calculating under steam stimulation, 46-9 indicator pertaining to steamfloods, 46-15 indicators common to both steamfloods and firefloods, 46-14, 46-15
59
Indicators pertaming to firefloods. 46-16 prediction of. 36-9, 36-10 Reservoir performance data, 37-7 Reservoir productivity guide, 52-16 Reservoir-rock characteristics, 36-l. 36-2. 42-4, 42-S Reservoir-rock heterogeneity, 28-l 1 Reservoir-rock properties, continuity of, factor in waterflooding, 44-2. 44-3 electrical conductivtty of fluid-saturated rocks, 26-27 to 26-29 empirical correlatton of electrical properties. 26-29 to 26-32 fluid saturations, 26-20 to 26-27 nomenclature, 26-32 permeabihty, 26-10 to 26-20 porosity, 26-l to 26-10 references, 26-33 Reservoir simulation, as extension of material-balance technique, 36-7 general references, 48-20 htstory of, 48-1. 48-2 introduction, 48-1 mathematical models for, 43-17 models, 38.16, 40-34, 43-2, 43-17, 48-l to 48-9 nomenclature, 48-17 purpose of. 48-6, 48-7 references, 48- 17 to 48-20 studies of gas-condensate reservoirs, 39-22 technology, 48-13 to 48-17 validity of results, 48-9 to 48-13 Reservoir-simulation models, 38-16, 40-34, 43-2, 43-17, 48-1 to 48-9 Reservoir simulators, 28-14, 36-7, 36-10, 46-11 Reservoir traps, 29-1 to 29-9 Reservoir volume, computation of, 40-4, 40-5 Reservoir-volume estimation, 38-9, 38-11 Reservoir with watersand, 46-26 Reservoirs amenable to thermal recovery, 46-3. 46-4 Reset. 13-50, 13-52, 13-53 Residual free-gas saturation, 40-8 Residual gas saturation, 36-3, 40-16, 44-25, 49-26 Residual hydrocarbon saturation. 446 Residual liquids, defimtion, 27-8 Residual oil after waterflooding, effect of initial saturations, 44-6 fresh-core techniques, 44-5 influence of wettability. 44-6, 44-7 interpretation of conventional coreanalysis data, 445 relative-permeability curves, 446 restored-state technique, 44-5. 446 Residual oil, definition. 22-21 Residual oil saturation (ROS), 28-5, 28-8, 28-11, 373, 40-16, 40-17, 40-19, 42-2, 42-4, 442, 44-4 to 44-6, 449, 4411, 4432, 4446, 46-21, 46-37, 47-1, 47-9, 47-10, 47-17, 49-26, 49-27, 49-36 Residual-resistance factor, 35-5 Residual-viscosity function. 20-9 Residual wellbore storage, 35-19 Residue gas. 10-16, 39-16 Resilient-type seal, 3-9 Resin-coated gravel packing. 56-3 Resin derivatives, 19-10 Resistance factor, 47-5 Resistance function, 38-4 Resistance-network model, 44-20 Resistance networks, 4434 Resistance of a process, 13-50
Resistance thermal detector (RTD), 16-7 Resistivity. annulus region, 49-6, 49-7 apparent, 49-7 devices, requirements for and types. 49-7 formation factor. 49-4 formation, relation to saturation. 49-5 formation waters. 49-4, 49-26 in permeable formations invaded by mud filtrate. 49-5 to 49-7 index. 49-5. 49-26 invaded zone 49-6. 49-7 logging devices, 49-l 1 to 49-14 mud, 49-4 mud-filtrate, 49-4 mudcake, 49-4 ranges of. 49-5 scales, 49-2 1 true, determination of. 49-27 uncontaminated zone, 49-27 units, 49-2 versus NaCl concentration, 49-3 water, dependence on salinity and temperature. 49-3 relation to formation resistivity, 49-5 Resistivity index, 26-28, 26-29, 26-3 I, 44-6 Resistivity log, 51-33 Resistivity of a material, definition, 26-28 Resistivity of formation water, 24-14. 24-16 Resistivity of partially water-saturated rocks, 26-3 I, 26-32 Resolution of BHP gauge, 30-2, 30-4, 30-6, 30-7 Response time, subsea valves, 18-49 to 18-51 Responses of normals and laterals in hard formations, 49-13 Restored pressure measurement, 5 l-31 Restored-state capillary-pressure method, 26-24, 26-25, 284, 28-10 Restored-state technique, 44-5, 44-6 Restoring forces, 18-9. 18-10, 18-16 Retarded acids, 54-8. 54-1 I Retention time for coalescence, 19-9, 19-15. 19-18, 19-22, 19-23 Retort method, 26-2 I Retorting, 27-8 Retrievability, of packers, 4-4, 4-5 Retrievable gas-lift valve, 5-2, 5-34 Retrievable packers, all latched, 4-3 control-head compression, 4-2 control-head tension. 4-2 hydraulic set, 4-3 isolation, 4-2 mechanically set, 4-3 removal of, 4-5, 4-6 solid-head compression, 4-2 solid-head tension, 4-2 weight-set tension type. 4-4 Retrievable-valve mandrel. 5-2, 5-22 Retrograde-condensate gas. 43-1 Retrograde condensation, 14-l. 23-4, 39-3, 39-8, 39-9, 39-16, 48-7 Retrograde dewpoint pressure, 21-12 Retrograde liquid, 39-7 to 39-10, 39-14, 39-16 Retrograde vaporization, 234 Return-flow equations. jet pump, 6-46 Return-flow fluid gradient, 6-42 Return on investment, 36-1 Return water saltwater, 44-42, 44-43 Revenue-interest fraction (RI). 41-2 Revenue interests, 41-3. 414. 41-9 Reverse ballooning of tubing strings. 4-10 Reverse-circulating gravel pack. 568
6(l
Reverse combustion, 46-2, 46-3, 46-14. 46-3 1 Reverse emulsions. 19-l. 19-2, 19-28 Reverse fault. 29-3 Reverse flow, check valve, 5-12, 5-23. 537 free-pump cycle, 6-6 installation, 6-6, 6-8 jet-pump casmp type, 6-5 systems. 6-5 to 6-7 tubtng arrangement. 6-7 Reversionary interest, definition. 4 I 1 Reynolds number. 6-36, 6-56. 6-57, 15-l to 15-3, 15-5, 15-24, 17-7, 19-2, 34-2, 34-3. 34-27. 34-38, 34-39 Reynolds-number factor, 13-8, 13-14 to 13-25 Rheological properties, 55-5. 55-6. 55-8 Rheology, 1829, IS-36 Rhombohedral packing of spheres, 26. I. 26-2 . Rhumba shaker, 52-8 Rice University, 25-20 Rig-selection considerations offshore, criteria, IS-4 drilling equipment, IS-10 to IS-16 mooring system (stationkeeping), 18-8 to 18-10 motion characteristics, 18-7 performance evaluation, 18-7, 18-E types of rigs, 18-5 to 18-7 Rig types for offshore operations, IS-6 to 18-S Right to transfer, by landowner, 57-6 by lessee, 57-7 Ring-joint gasket, 3-28 to 3-32 Ring-type plunger, 8-6 Rim-type _ . tester. 5-16, 5-17 Riser analysis, ball-joint angle. 18-17 mtroduction, 18-16, 18-17 pipe collapse. 18-17 pipe stress, 18-17 sheave friction, I E-17 tensioner-line angle, 18-17 top angle, 18-17 top tension. 18-17 Riser angle, 18-13 Riser pipe, 3-38. 3-39 Riser-pipe collapse, IE- 17 Riser-pipe stress, 18-17 Riser tensioner, 18-11, 18-13 to 18-15 Riser-tensioner systems, 18-17 Riser-top angle, 18-17 Riser-top tensions, 18-4, 18-16 to 18-18 Risk factor. 41-3 RMS efficiency of motor, IO-25 Robinson field, Illinois, 46-15 Robots, 3-36 Rock bulk compressibility. 26-7 Rock compaction, 26-7 Rock composition, 51-5 Rock compressibility, 26-7, 26-9, 37-2, 37-3. 37-6, 37-10 Rock Creek field, Texas, 41-4 Rock-Eva1 11” (RE), 52-10, 52-l 1 Rock flow model, 4420 Rock/fluid interactions, 47-20, 47-21 Rock-frame compressibility, 51-4 Rock-frame incompressibility, 5 l-49 Rock-grain compressrbility, 5 14 Rock matrix, 51-39, 51-49 Rock-matrix compressibility. 26-7 Rock-matrix density, 50-26 Rock mechanics, 55-1 Rock properties, 39-1, 43-7
PETROLEUM
Rock quality dcstgnatton (RQD), 51-43. 51-44 Rock tortuostty. 26-28 Rock wettability alteration, 44-39, 4440 Rocking a well, 5-54 Rockwell C scale. 9-t Rockwell hardness, 2-2. 2-37 Rocky Mountain area, 24-8. 27-14, 27-15, 28-11, 28-18, 41-1, 47-3 Rocky Mountain method, 49-27, 49-3 I. 49-32 Rod-and-plunger system, 6-10, 6-16 Rod and pump data, 9-6, 9-7 Rod grades, Y-5 Rod-pumped-well control, 16-I 1 Rod pumps. 8-l to 8-4, 8-8 Rod stress, 9-2 Rod string design, 9-5 Rollover fault closures, 29-3 Romania. 46-3, 46-4, 46-15, 46-18, 46-28, 46-29 Rose equation. 28-3 Rosin, 44-45 Rotameter. 13-45, 13-48 Rotary converter. IO-36 Rotary cores. 26-20, 26-21 Rotary floatmg drilling vessel, 18-2 Rotary gas meter. 16-6 Rotary gas separator. 7-5, 7-6 Rotary inducer-centrifuge, ‘7-5 Rotary pumps, 15-15 Rotary-vane positive-displacement meter, 32-l 1 Roughness factors for new pipe, 15-2, 15-3 Round-thread casing and coupling, 2-l. 2-5, 2-7, 2-9, 2-11, 2-13. 2-15. 2-17. 2-19, 2-28, 2-30. 2-57. 2-58. 2-61, 2-64 Round-thread tubing form, 2-64 Rounding rules. 58-5 to 58-7 Royalties. definitton, 41-I Royalty. acres, 57-7 clause. 57-5. 57-10 deeds, 51-6, 57-7 gas. 57-10 interest, 57-5 to 57-8 oil, 57-5 overriding, 57-5, 57-7 to 57-10 Royalty interests. definition, 41-l to 41-3 Rubber lining coating, II-6 Rubble pile, IS-39 “Rubm,” computer subordinate routine, 17-6 Rugosity . 5 l-33 Rule of capture, 57-1, 57-2 Rules for writing metric auantities. 58-l 1 Rules of thumb,’ for critical-flow-pressure ratio. 13-37 for liquid recove-ty, LTS system, 14-5 for regulators. 13-55 for sizing transformers, IO-3 1 for sucker-rod length and cycle strokes. 9-3 of performance htstory required, 37-3 of water-handling equipment, 44-46 of when gas-condensate system exists, 39-2 Run tickets, 17-7 Running, and pulling sucker rods, 9-10 BOP, 1818 to 18-20 20.in. casing. 1S- 18 30.in. casing, IS-18 Rupture disk, 12-39. 12-40 Ruska universal uermeameter. 26-17 Russell grain-volume method, 26-3, 26-4 RJR, method for water saturation, 49-28 Rylon@. 4-5 Ryton, 7-3
ENGINEERING
HANDBOOK
s S. El Mene field, Veneaula. 24-13 Splat (cumulative logarithmic diagram). 56-6 S-wave critical angle, 5 I-12 S-wave velocity. 51-l 1. 51-37 S-wave velocity ratio vs. porosity, 51-9 S-waves, 51-2, 51-3. 51-5. 51.11, 51.36. 51-44, 51-47 Saccharoidal. 29-8, 29-9 Sacrificial anodes. 1 l-6 SAE 20 lubricating oil, 25-4 Safe nominal interest rate. 41-21. 41-22. 41-24 Safety and pollution preventton equipment (SPPE) certificate holder, 3-39 Safety controls of engines. IO-17 Safety factor of Goodman diagram, 9-9 Safety factor of motor temperature, IO-26 Safety factors for casing strings, collapse strength, 2-l to 2-3, 2-32, 2-34. 2-35 internal yteld pressure, 2-l. 2-2, 2-32. 2-34. 2-35 joint strength, 2-l. 2-2, 2-32, 2-34. 2-35 pipe-body yield strength, 2-l. 2-2. 2-34, 2-35 Safety factors, gas lift, 5-3, 5-24, 5-27 Safety factors in continuous-flow gas-lift installation design. 5-22 Safety factors, manufacturers’, 3-l Safety features for 011 and gas separators. 12-39 Safety head. 12-39, 12-40 Safety relief valves, 12-40 Safety shut-in system. 3- 19 Safety shut-in valves. 16-3, 16-4. 16-I 1 Safety shutdown system. 13-58, 18-43. 1844 Safety systems offshore. 18-47, 18-48 Safety valves, 6-48, 6-49, 18-28. 18-34 Sage and Olds correlation. 2 l-l 1 Salem unit. Illtno~s. 4441 Sales contracts. 40-l Sales gas, 14-6 to 14-8, 14-12. 14-14 Sales-gas line, 14-5, 14-11. 14-15, 14-18. 14120, 14-21 Sales-gas pressure, 14-3 Sales-gas volumes, 39-10 Sales method of oil and gas, 36-2 Salient gradient floods. 47-15 Salinitv: definition. 47-2 effect on IFT, 47-20 from reuresentative oilfield brines. 47-3 general,* 47- 14 of brine. 19-26, 47-3 to 47-5. 47-10, 47-11, 47-13, 47-21 of ice, 18-39 of injection water, 44-2. 47-22 of oilfield waters, 24-13. 24-20 Salt-bath heater. 14-14. 14-15 Salt content, 19-26, 24-14 Salt deposition in flow string, 33-20, 33-21 Salt domes, 24-7 Salt intrusions, 29-5 Salt plugs, 29-5 to 29-7 Saltwater disposal projects, 24-3 Saltwater sources, 44-41 to 4443 Salty muds, 49-20. 49-25. 49-27 Salvage value. 41-3. 41-11. 41-13 Sample collection and evaluatton. gascondensate reservoirs, dewpoint and P/V relations, 39-7 recombination of separator samples, 39-6 simulated pressure depletion. 39-7 to 39-10
SUBJECT INDEX
Sample containers. 24-4 Sample. Control and Alarm Network (SCAN), 46-20 Sample description tabulation. 24-5 Sample lag time. 52-8 Sample logs. 41-8 Sample procedure, oilfield waters, containers. 24-4. 24-5 field-filtered sample, 24-4 for determining unstable properties or species. 24-4 for sample containing dissolved gas. 24-3 for sampling at wellhead, 24-3, 24-4 for stable-isotope analysis, 24-4 for tabulation of sample description, 24-5 sampling at flowline. 24-3 Sampling crude oil, 17-l to 17-8 Sampling crude-oil emulsions, 19-6 Sampling natural-gas fluids, 17-7 Sampling of petroleum and petroleum products. 17-5 Sampling of produced waters, drillstem test, 24-3 procedure for, 24-3 to 24-5 Sampling of water, 44-43 Samson post, 10-3, 10-4 San Ardo field, California, 46-4, 46-15, 46-18 San Joaquin Valley, California, 46-23 San Miguel-4 tar sand, Texas, 46-26 Sand bridging, gas Ii?, 5-38 Sand-by-sand correlation. 36-7 Sand consolidation treatments. 56-3 to 56-5 Sand control. an acoustic log use, 51-45, 51-46 clay control, 56-5, 56-6 consequences of sand production, 56-3 formation analysis. 56-3 formation properties. 56-2 formation sampling, 56-3 geology of sand formation, 56-2 gravel packing, 56-8. 56-9 gravel selection, 56-6, 56-7 methods of, 56-3 properties of sand formation. 56-2 screen selection. 56-6. 56-7 well preparation, 56-3 to 56-5 why sand is produced, 56-2, 56-3 Sand counts, 49-22, 49-25 Sand filters, 15-20. 15-21, 16-14 Sand formation propertles and geology, 56-2 Sand-grain volume (GV). 26-3 to 26-5, 26-7 Sand-grain volume, laboratory measurement, 26-3 to 26-5 Sand-jetting and drain systems. 19-20 Sand line, 49-10 Sand model, for radial flow, 26-13 for rectilinear flow, 26-11 for vertical flow, 26-12 Sand pans, 19-29, 19-30 Sand pressure filters, 4447 Sand production, consequences of, 56-3 Sand removal, 19-29 Sandblasting, 46-2 I Sandface plugging, 39-25 Sandface pressure, 34-28 Sandia Laboratories, 30-7 Sanding. 46-2 I Sandpacks, 26-l 1, 26-12 Sandstone acidizing, 54-4 Sansinena field, California, 6-24 Santa Barbara Channel, California. 18-1, 18-2 Santa Fe Springs field, California. 29-2 SARABAND log analysis, 49-37 Saskatchewan, Canada, 24-8. 24-12. 51-32
61
Satelhte navigation (SAT NAV) systems, 18-18 Satter’s equation. 46-6 Saturated depletion-type oil reservoirs. 40-8 to 40-12 Saturated liquid. definitmn, 22-21 Saturated-oil viscosity. 22-15 Saturated steam, 46-5. 46-6, 46-40 Saturated systems. oil formation volume factor for. 22. IO. 22. I1 Saturated systems, oil-viscosity correlations. Beal’s for dead oil, 22-14 Beggs and Robmson. 22-15. 22-16 Chew and Connally, 22-14, 22-15 Saturated water content of natural gas, 25-I I to 25-15 Saturation change with frontal advance, 38-15 Saturation CUNCS, 23. I, 23-2 Saturation exponent, 26-31 Saturation gradient. 28-3 Saturation measurements, 28-4 to 28-7 Saturation method of determining porosity, 26-6 Saturation pressure, 14-10, 21-11, 21-13 to 21-15, 22-1, 22-5, 22-21 Saturation vapor pressure. 17-7 Saudi Arabia, 12-39 Saunders-type valve bdies, 16-3 Saybolt seconds furol (SSF). 22-13, 22-14 Saybolt seconds universal (SSU), 22-13 Scale or scaling, 5-25. 5-53, 6-48, 6-55, 9-2, 11-13. 19-1, 19-2, 19-26. 19-29, 19-32. 56-l Scale deposits, 44-43, 56-2 Scale trap. 13-59 Scaled physical models. 45-10 Scaled porous models. 44-17, 44-34 Scales. resistivity, 49-21 Scaling laws. 46-13 Scanning electron micrographs (SEM), 51-8 to 51-l 1 Scanning electron microscope. 46-21 Scannmg-electron-mlcroscope analysis, 56-3 Scattered neutron, 50-9. 50-10 Schilthuis equation, 37-5 Schlumberger. 49-2, 49-36, 49-37, 51-18, 51-21, 51-24, 51-25, 51-41 Schlumberger Borehole Compensated Sonic log, 51-24 Schlumberger Ltd., 53-19 Schlumberger neutron porosity (SNP), 50-29 Scholem Alechem field, Oklahoma, 6-24 Schoonebeek field, Netherlands, 46-3, 46-14 Scintillation detector, 50- 12, 50-13 Scoring, 6-50 Screen-factor devices, 47-5 Screen selection, 56-7, 56-8 Screen specifications and sizes, 56-9 Screening guides and parameters, 47- 1, 47-22 Screening guides. thermal recovery, 46-13, 46-14 Screening thermal prospects, 46-12 to 46-14 Screenout, 56-8 Screens and filters, jet pumps, 6-48 Scrubbers, 6-33, 12-1, 12-2. 12-10, 12.13, 13-58, 39-26 Scurry field, Texas, 29-4 Sea ice. 18-38, 18-39 Seafloor manifold, 18-33, 18-35 Seal Beach field, California, 6-24 Sealing bores, 6-3. 6-4 Sealing element of packers, 4-5 Search angle, dipmeter, 53-10, 53-11 Seating nipple, 5-3 Seatmg shoe, 6-3
Seawater, 24-17. 24-18, 24-20. 24-2 I Seawater-injection projects. 4437 Second-stage separator gas, 39-9. 39.10. 39-14 Secondary/backup power. 18-45 Secondary drainage, 28-12 Secondary electrical systems, 10-29. 10-30. lo-32 Secondary functions of oil and gas separators. maintain liquid seal, 12-S maintain optimum pressure, 12-4 Secondary imbibition. 28-12 Secondary porosity, 26-l. 29-3. 36-6, 51-31. 51-33 Secondary recovery, 16-2. 18-44. 24.2, 24-3, 29-7, 40-4, 41-9. 43-l. 44-45, 45-9 Secondary-recovery methods, 44 I to 44-3 Secondary-seal assembly, 3-6 to 3-8 Secondary separation in separator, 12. I9 Secondary skin-effect correction, 49.16, 49-17 Secondary stratigraphic traps, 29-5 Secondary voltage, lo-29 Section gauge log, 49-25 Securities and Exchange Commission (SEC), 40-1, 40-2, 41-3 Sediment in crude oil by centrifuge method. 17-5 Sediment in crude oils by extraction method, 17-5 Sediment in fuel oils by extraction method, 17-5 Sedimentary features. dipmeter patterns in, 53-13 Sedimentary rock porosity, 26-7 Sedimentation flume capacity, 15.18. 15-19 Seeligson field, Texas. 39-3 Segmental orifices. 13-45, 13-48 Segments of circles, table, i-31, l-32 Segments of spheres, table, l-33 Segregation, complete, 37-14, 37-15 Segregation. in gas-injection performance predictions, 43-16 Seismic analyses, 18-27 Seismic compressional surveys, 5 l-28 Seismic exploration, 5 I-IO Seismic interpretation, 51-28, 51-29 Seismic mapping, 18-18 Seismic studies, 18-5 Seismic velocities, 58-25 Seismograph Service Corp., 5 I-l Seismologists, 57-8 Seisviewer@, 5 l-27 Selecting appropriate PIE ratlo. 6-28 Selecting motor size, IO-2 1 Selecting mud-logging service, 52-28 to 52-30 Selecting pumps and drivers, 15-14 to 15-18 Selection, of backpressure valves, 3-8 of casing hangers, 3-6 of gas-lift installation and equipment, 5-3 of gas-lift port size, 5-28 of independently screwed wellhead equipment, 3-39 of intermediate casing heads, 3-7 of lowermost casing heads. 3-2 to 3-5 of materials for wellhead service, 3-36. 3-37 of multiple-completion tubing hangers, 3-16, 3-17 of storage-tank location, 1 I-1 1 of subshrface safety valves, 3-27, 3-29, 3-3 1
62
of surface closing pressure, gas-lift valves, 5-44 of surface safety valves, 3-27 of tubing hangers, 3-9 of waterflood plants, 44-45 Selection and application of gas scrubbers, 12-35 Selection and applicatton of separators, horizontal, 12-35 spherical, 12-35 vertical, 12-35 Selection data and methods, electric submersible pumps (ESP), 7-9 to 7-12 Selective adsorption systems, 14-10 to 14-13, 14-15, 14-17 Self-contained pressure gauges, 30-l to 30-3 Self-contained thermometers, 31-1, 31-2 Self-generating mud acid (SGMA), 54-4 Self-operated controller, 13-50 Semblance, 51-25 Semiconductor sensor element, 52-7 Semidiesels, 10-15, lo-16 Semilog straight-line solution, 354, 35-8, 35-16 Semipermanent packers, 4-1, 4-3, 4-6 Semiquartzitic sandstone, 26-6 Semisteadv state. 37-2 1, 37-22 Semisubmersible rig, 3-38, 18-2 to 18-7, 18-13, 18-21, 18-25, 18-34 to 18-36 Sensible heat, 14-5, 14-10, 14-21 Sensitivity analysis, 39-17 Sensitivity of t&erial-balance results, 37-13 to 37-17 Sensitivity of regulators, 13-54, 13-5.5 Sensitivity of variable, 13-50 Sensitivity studies, 37-16 to 37-18, 48-14 Sensitivity to shock, BHP gauges, 30-5, 30-7 Sensitivity to vibration, BHP gauges, 30-5 to 30-7 Sensor coils, 53-22, 53-23 Sensor sub. 53-2 Sensors, 3-18, 3-19, 3-31, 3-33, 3-34 Separated fluids, estimated quality of, crude oils, 12-13 gas. 12-15 gas from scrubber, 12-15 measuring, 12-15, 12-16 water, 12-15 Separating foaming crude oil, 12-6, 12-7 Separation of water from oil, 12-3, 124 Separator, design, 12-21 to 12-32, 23-1 Separator high-level float control, 16-9 Separator pressure, 12-16, 12-17. 12-22, 12-23, 12-25 to 12-34, 12-36 to 12-39, 39-9 Separator temperature, 12-17, 12-22, 12-23, 12-25, 12-26, 12-28 to 12-30, 12-36, 12-37, 12-40, 12-41 Separators: see oil and gas separators Sequence-restart timer, 10-27 Sequential-piloted hydraulic control, subsea, 18-5 I, 18-52 Sequestering agents, 4445, 54-7, 54-9 Service company nomenclature (table), 49-2 Service facilities, 39-24 Service factor, of motor, 10-25, 10-26 Service factor, of steel sucker rods, 94, 9-5 Settled solids removal, 19-29 Settling, in breaking foaming oil, 12-7 in water treating, 44-46 to remove gas from oil in separators, 12-13 Settling space, in emulsion treating, 19-8 Settling tanks, 6-59, 19-18 to 19-21 Settling time, 11-13, 12-3, 19-9, 19-15
PETROLEUM ENGINEERING
Seven-point, hexagonal-gridblock scheme, 48-11 Seven-spot pattern, 43-2, 4413, 4414, 4416, 4417, 44-21, 44-23, 44-34, 46-17, 46-18, 46-26 Severance of minerals, 57-2 Severance tax, 39-27, 41-9, 41-12, 41-15 Shaker screen, 52-8, 52-19 Shale baseline, 49-10 Shale bulk density, 52-19 Shale compaction. 24-20 Shale-data log, 52-20 Shale distillation, yield, 58-29 Shale effect on neutron porosity, 50-31 to 50-33 Shale effects on compressional and shear velocities, 51-34 Shale factor, 52-21, 52-22 Shale index, 49-38, 49-39 Shale intercalations, 36-6 Shale-outs, 442, 4439 Shale point, 50-24, 50-34 Shale/sand ratio, 36-4 Shale stringers, extent of, 36-6 Shale transit time, 51-39 Shallow dual laterolog (LLS), 49-19 Shallow-hazard surveys, 18-5 Shallow laterolog (LLS), 49-20 Shallow MICROSFL (MSFL), 49-20, 49-22, 49-28 Shaly (dirty) formations, 494 Shaly sand, 26-31, 50-34, 51-34, 51-35 Shannon Pool field. Wyoming, 46-14 Shaoe factor. 6-57. 26-18. 35-4. 35-5. 35-7. 35-12, 35-16, 37-19, 37-20 Shape functions. 32-5 Sharing arrangements, 41-15 Sharp-edged orifice plates, 13-36, 13-37, i3-45 Sharp-edged valve seat, 5-14, 5-15, 5-20, 5-35, 5-40 Shear bulk modulus, 58-34 Shear-history method, for friction losses in fluids, 55-5, 55-6 Shear modulus. 51-1, 51-4, 51-37, 51-43, 51-44. 51-49 Shear rams, 18-15 Shear rate, in fluids, 55-5 Shear rate, in oilfield emulsions, 19-6 Shear-rate/viscosity relations, 474 Shear-thinning fluid, 47-4. 47-9 Shear-wave amplitude, 5 1-46 Shear-wave attenuations, 51-2, 51-6 Shear-wave logging, 51-24 Shear-wave transit (travel) times, 5 1-5, 51-15, 51-24, 51-25 to 51-27, 51-30, 51-31, 51-35. 51-43 Shear-wave velocities, 51-2, 514 to 51-9, 51-12 to 51-14, 51-24, 51-25, 51-28, 51-30, 51-34, 51-35, 51-37, 51-38, 51-43 Shear waves, 51-2, 51-3, 51-12 to 51-14, 51-24, 51-25, 51-27, 51-30, 51-35, 5144 Shearing stress, 22-l. 22-13 Sheave friction, 18-17 Shedding, 13-48 Shelf carbonates, 36-6 Shell breccia, 29-8, 29-9 Shell nroun. 46-13 Shell oil Co., 16-12, 46-4, 46.15, 46-16, 46-18, 46-24, 46-25 Shipper’s ton, l-70 Ships and ship-shaped vessels, 18-5, 18-7, 18-13, 18-21, 18-34, 18-36 Shock load, IO-28 Shock mobility ratio, 47-1
HANDBOOK
Shoestring sands, 29-4, 29-9 Shop-welded tanks, 11-1, 11-5, 11-9 Shoreline sandstone, 36-4 Short or net ton, l-70 Short-cycle units, 14-10, 14-13. 14-17 Short-duration cycling, electric submersible pump (ESP), 7-15 Short lateral, 49-l 1 Short normal, 49-11, 49-14, 49-26, 49-27, 49-29 to 49-3 1 Short-normal resistivity. 53-2, 53-4 Short-normal resistivitv log. 51-26. 51-46 Short-spaced acoustic logs: 5 1-24 Short-thread casmg, 2-5, 2-7, 2-9, 2-l 1, 2-13, 2-15, 2-17, 2-19. 2-29, 2-57, 2-64 Shoulder-bed corrections, 49-l I, 49-21 Shrinkage, by liquid recovery, 39-23 definition, 22-21 factors, 22-20, 44-3 of liquid, 32-10, 32-15, 33-14 of oils, 19-7, 37-1, 37-6. 37-22, 37-23. 43-l test, 39-6 Shrouded configuration application, electric submersible pump (ESP), 7-1 to 7-3 Shuttle ball, 13-48 Shuttle tankers, 18-36 SL angle unit, 58-5 base quantities and units, 58-3, 58-9. 58-10, 58-21, 58-23 bending moment, 58-5, 58-34 derived units. 58-2. 58-4. 58-10. 58-11. 58-2 1, 58-23 energy unit, 58-5, 58-11, 58-23, 58-24. 58-32 international system of units, 58-2 to 58-20 metric system of units, 17-7, 58-l to 58-20 non-S1 metric units. 58-10 prefixes, 58-4. 58-12, 58-13 to 58-20 pressure unit, 58-5, 58-l 1, 58-23 to 58-25, 58-28, 58-29 stress unit, 58-5, 58-11, 58-23, 58-34 supplemental units, 58-2, 58-3 temperature units, 58-5, 58-23, 58-24, 58-28 time units, 58-5, 58-22, 58-23, 58-27 torque units, 58-5. 58-34, 58-38 unit prefixes, 58-3 unit symbols, 58-3, 58-4, 58-15 to 58-20, 58-22 units, 58-9 to 58-11, 58-26 to 58-38 volume units, 58-5, 58-23 Side-pocket mandrel, 3-35. 5-2, 5-53 Side-scan sonar, 18-5 Side-static method of gas metering, 13-37 Side-well producing cuts, 4424, 4425 Sidewall cores, 26-20, 26-21 Sidewall epithermal neutron device, 50-20 Sidewall neutron logs, 51-33 Sidewall neutron porosity, 51-19 Sidewall-pad tool, 49-22 Sidewall vs. conventional core analysis, comparative data, 27-8 Sidum steam-injection pilot, Arkansas, 46-26 Sieve analysis, 56-3, 56-6, 56-7 Siggins field, Illinois, 47-9 Signal Oil Co., 46-22, 46-23 Significant digits, 58-6, 58-9 Silica, 19-5, 24-4 Silica flour, 46-19 Silica gel beads, 14-21 Silicate-control agents, 54-7
SUBJECT INDEX
Silicon-controlled rectifiers @CR’s), 18-45 Silicone, as surface tension reducer, 12-13 Silicone-controlled rectifier relays, 7-6 Silver. 50-12 Silverdale field, Alberta, Canada, 46-18, 46-2 1 Simple harmonic motion, 51-2, 51-3 Simple interest, 41-25 Simpson’s rule, 34-24, 34-26. 40-4, 40-5 Simulated pressure depletion, 39-7 to 39-10 Simulation and simulator studies, 37-2 I, 37-22. 40-l Simulation models, consideration in applications, fluid- and rock-description data, 48-8, 48-9 history matching, 48-9 model grid selection, 48-7. 48-8 of complex reservoir, 443 1, 4432 type selection. 48-7 Simulation steps, 36-10 Simulation technology, 48-13 to 48-17 Simultaneous formulatmns, 48-14 Sinclair, 47-22 Singapore, 12-39 Smgle-actmg downhole unit. 6-10, 6-20 Singleacting pump, 6-8 to 6-10, 6-18 to 6-20 Single- and two-phase inflow-performancerelationship (IPR) equation, 34-33, 34-34 Single-carbon-number (SCN) groups, 39-1 I Single-component phase diagrams, 23-1, 23-2 Single-contact miscibility, 48-5 to 48-7 Single-control line valve, 3-27, 3-29 Single-cylinder engines, IO-15 Single-elenlent fuses, IO-28 Single-element simulation, 48-7 Single-element unbalanced gas-lift valve. 5-12 to 5-15 Single-horsepower rating, lo-25 Single-pattern simulation studies, 48-8 Smgle-payment present-worth factor, 41-25 Single-phase flow, 28-2, 34-2, 34-3, 34-31, 34-33, 34-36. 34-38, 3445 Single-phase fluid, constant compressibility, 35-3 Single-phase motors, IO-2 1 Single-phase transformer, 7-6, 7-7, 10-30, 19-25 Single-phase turbulent flow, 34-37 Single-piece jacket, 18-23 Single-point mooring @PM). 18-2. 18-34 Single-ported valves. 13-55, 13-57 Single satellite wells, 18-31, 18-32 Single-real pumps, 6-39 Single-seated valve. 13-55 Single-shot surveys, 53-3 Single-stage desalting, 19-26 Smgle-tubing-string completions, 3-13 Single-welded butt joints, 12-40 Single-well coning studies. 48-14 Single-well depletion reservoir, 35-1 Single-well power umt, 6-60, 6-61 Single-well systems. 6-60 to 6-63 Single-wing well manifold, 16-l I, 16-12 Singleton field, Nebraska, 4440, 47-22 Sinking fund. 41-16, 41-21. 41-22 Sinking fund, table, l-65 Sinusoidal alternating-current field. 19-13 Siphon breaker, 6-62 Siphon strings, 33-21 Site conditions and considerations offshore, expected environment, 18-4 introduction, 18-3 logisbcs. 18-4. 18-5 seismic and other location studies. 18-5 water depth, 18-4
63
Site survey offshore, 18-5 Six-pole induction motor, lo-23 Six-spot pattern, 46-17 Sizes, of casing hanger, 3-6 of casing head, 3-7 of meter and meter run, 13-36 of separator, estimating, 12-21 to 12-2.5 of tubing hanger, 3-9 of tubing heads, 3-8 Sizing and capacities of separators, capacities of spherical separators, 12-30, 12-31 capacity curves for vertical and horizontal separators, 12-27 to 12-29 computer sizing of separators, 12-25 to 12-27 equation for gas capacity, 12-23 equation for sizing, 12-23 to 12-25 gas velocity, maximum, 12-22 horizontal separator sizing, 12-30 vertical separator sizing, 12-29 Sizing, curves, 13-53 equations for plate coalescers, 15-24 instructions, ultrahigh-slip motor, lo-22 of waterflood plants, 44-45 oil and gas separators, 12-25 to 12-27, 12-32 pumping units, IO-7 Skewness, definition, 26-2 Skim piles, 15-23, 15-26, 15-27, 15-30 Skim tanks and vessels, 15-23, 19-28 Skimming, 19-23 Skin-effect correction, IL, 49-17 Skin effects, 30-10, 30.14, 32-5, 354, 35-7, 35-l 1. 35-14, 35.15,.35-19, 40.27, 49-16 Skin factor. 33-11, 37-20 Skirt piles, 18-3, 18.22, 18-23 Sleeve bearings, 13-48 Slide-rail motor mounts. lo-19 Sliding-sleeve valve, 3-35 Slim-hole coupling, 9-5 Slim-hole-coupling derating factor, 9-5, 9-8 Slim-tube displacement tests, 39- 16 Slim-tube displacements, 48-9 Slip joints, 18-13, 18-20 Slip of motor, 10-23, lo-24 Slip-on socket connection, 3-3 Slip-type tubing hanger, 3-39 Slip velocity, 34-27, 34-38 Slip-weld casing hanger, 3-6 Slipform methods, of gravity platform construction, 18-23 Slippage effect on energy losses, gas-lift wells, 34-37 Slippage-loss equation, 8-5 Slippage, past pump plunger, 8-4 to 8-6 Slocum field, Texas, 46-15, 46-18, 46-26, 46-27 Slope of backpressure curve, 33-5 Slope of buildup curve, 30-10, 30-12 Sloping-sided structure, 18-42 Sloss field MP pilot, Nebraska, 47-18 Sloss field. Nebraska, 46-14, 46-15, 46-18, 46-2 I, 46-30, 46-33 Slow-speed engines, IO-14 to lo-19 Slowing-down length. 50-l 1, 50-19 to 50-2 I. 50-29 to 50-32 Slowness time coherence, 51-25 Sludge, 19-11, 19-12, 19-32 Sludge tank, 4447 Sludgmg of oil, IO-13 Slug flow, 34-36 to 34-40 Slug-mtst transitton flow, 34-36, 34-37, 34-40 Slug-stze retention ratio, 47-17
Slugging, 12-23, 12-35, 12-38, 39-26 Slugs of well fluids, 12-l. 12-20, 12-32 Smackover field, Arkansas, 46-15, 46-24 to 46-26 “Smart” end devices. 16-2 Smectite-rich clay, 52-21 Smoke point, 21-7, 21-9 Snap action, control mode, 13-49, 13-51 to 13-53, 13-56 Snell’s law, 51-3, 51-12 Sniffer, 52-6 Soaking, in steam stimulation, 46-9 Soap-type gels, 55-5 Soave modification of Redlich-Kwong equation, 20-8, 23-13 Sot. of Automotive Engineers (SAE), lo-12 Sot. of Petroleum Engineers (SPE), joint committee member on reserve definitions, 40-2 SPE letter and computer symbols std., 59-2 to 59-70 SPE metric unit standards, 58-21 to 58-39 SPE papers on relative permeability, 28-12 SPE-preferred metric unit. 58-21, 58-24 to 58-38 SPE Reprint Series, 44-36 Sot. of Professional Well Log Analysts (SPWLA), 52-30 Soda ash, 14-22 Sodium aluminate sand-consolidation technique, 46-2 1 Sodium chloride (NaCI), as water contaminant, 24-16 Sodium chloride conversion chart, 49-3 Sodium dodecyl sulfate, 47-7 Sodium hydroxtde, 4440, 4442, 47-18, 54-3 Sodium iodtde (Nal), detector, 50-12 to 50-16, 50-23, 50-35 Soft-packed plungers, 8-6 Soft-start capability. 7-9 Solid-desiccant dehydratton umt, 14-20, 14-22 Solid-head compresston packer, 4-2, 4-8 Solid-head tension packer, 4-2, 4-8 Solid hydrates, 25-1, 25-3, 25-19 Solid-propellant gas generators, 18-16 Solid-state detector, gamma rays, 50-12, 50-14, 50-23, 50-35 Solid-state electrical detector. 52-7 Solid-state electronic components, 16-9 Solid-state electronics, 16-1 Solid-state switchboards, 7-6 Solids in brine, 14-4 Solids wetting, 19-9, 19-10 Soluble-sulfide analyzer, 52-7 Solubility, definition, 45-1 of bentonite in mud-removal acid, 54-4 of CO, in water, 25-15 of methane in water, 25-16 of natural gas in water, 25-17 of propane in water, 25-17 of silica in mud-removal acid, 54-4 of water in refrigerants, 14-10 of water in various hydrocarbons, 25-16 Solubilization parameter or ratio, 47-13, 47.14, 47-20 Solutes concentration in aqueous phase, 25-16 Solution cavtties, 26-6 Solution gas, definition, 12-3 in oil reservoirs, 40-6, 40-13 increases as temperature decreases, 22-10 release of, 22-2 1 Solution-gas drive, definition, 22-20, 40-8 Solution-gas-drive process. 42-5
64
Solution-gas-drive reservoirs, basic data required, 37-3 to 37-5 calculation of reservoir pressure, 35-8 comparison of Tarner’s and Tracy’s methods. 37-10 definitions, 37-l insights from simulator studies, 37-22 introduction, 37-l material-balance calculations using Muskat and Taylor’s method, 37-10 to 37-13 material-balance calculations using Tracy’s method. 37-7 to 37-10 material-balance equation, 37-5, 37-6 material-balance equation as a straight line. 37-6. 37-7 models. types used, 37-2 nomenclature. 37-26, 37-27 nonideal behavior of, 35-3 performances. 37-l) 37-2 production rate and time calculations, 37-17 to 37-21 references, 37-27 sensitivity of material-balance results, 37-13 to 37-17 single empirical IPR equation for, 34-3 I tank-type material balance. basic assumptions of, 37-2, 37-3 volatile-oil-reservoir performance predictions, 37-22 to 37-26 Solution-gas production rate, 37-l I Solution GOR, definition, 22-l. 22-21, 37-14 to 37-18, 37-21, 37-22, 40-6, 40-8, 40-9, 40-13, 46-34, 46-36 Solution GOR for saturated oils, Lasater correlation, 22-9 Standing correlation, 22-9 Vasquez and Beggs correlation. 22-9 Solution-mined caverns, 11-13 Solution porosity, 29-8 Solutron techniques for math models. 48-16, 48-17 Solvent breakthrough, 45-7 Solvent extraction, 12-16 Solvent extraction and distillation, 27-8 Solvent-extraction effect. 46-4, 46-5 Solvent override. 48- I2 Solvent slug, 45-2 Sondes, 49-l Sonic fluid-level tests, 40-27 Sonic level control. 16-5 Sonic log and logging, 44-3, 49-15, 49-16, 49-25 to 49-27. 52-20, 52-27, 58-25 Sonic meters, 13-49. 13-50 Sonolog, 32-6 Sonoloy. 30-7 Sour corrosion, 3-36. 4-4 Sour crude. I I-IO Sour-crude tanks, I l-6 Sour gas. 5-2, 10-16, 14-7. 14-21, 18-47 Sour-water strrpper correlations, 25-17, 25-18 Sour-water systems, 25-16 Source of hydrocarbon prospects, 57-8 Source rock, definition. 24-19 South America. 18-7 South Belridge tirellood. California. 46-14, to 46.16. 46-18 South Oklahoma field, 46-15, 46-16 South Pass 27 field. Louisiana, 36-4 South Sunshine field. Wyoming. 24-18 Southeast Texas field, 47-22 S.P. PacksTM. 19-12, 19-19 Space, Sl units for, 58-26, 58-27 Spacer fluids, 56-4 Spacing, defhution, 49-12 Spacing-factor gradient, 5-45
PETROLEUM
Spacing factor, mtermutent pressure gradient, 5-42, 5-43 Spacing-load design, 5-48 Spacing pressure differential, 5-29 Spain, 58-20 Sparker, 18-5 Spatial gradient, 48-10 Spatial truncation error, 48-7, 48-9 to 48-12 Special alloy rods, 9-8 Special-service structures, 18-25 Specific conductivity. 39-20 Specific entropy. 58-28 Specific fuel consumption, 58-33 Specific gravities of fluid columns, 6-22, 6-23 Specific gravity (relative density), 204, 20-10 Specific-gravity factor, 13-3, 33-14 Specific gravity, increase with pressure, saltwater, 24-15 of gas mixtures, 20-4 of natural-gas mixtures, 17-7 of salt soluuons, 24-14 vs. temperature for crude oils, 19-8 Specrfic heat capacity, 58-28 Specific heat ratio. 13-8. 13-13, 14-10, 39-24 Specific heats, of mid-continent liquid oils, 21-6 Specdic-isopermeability map, 39-22 Specnic permeability, 28-l. 28-2, 28-13, 43-3. 43-5 Specific productwity index (PI), 30-l I, 32-4, 58-38 Specific volume, gascondensate system, 21-16, 21-17 of oil. 224. 22-5 of total fluids, 46-7 units and conversions, 58-29 vs. molality. 24-15 Specification of reservoir rock and fluid description data. 48-8 Specifications of coatings, Il.4 Specifications of diesel fuel, IO-16 Spectral fatigue analysis, 18-27, 18-28 Spectral gamma ray device, 50-15, 50-16, 50-24 Spectral gamma ray log, 50-25 Spectrographic technique, qualitative emission, 24-5 Spectroscopic gamma ray detection, 50-12 Spectroscopic-quality gamma ray detectors, SO-IS Speculative interest rate. 41-17, 41-21, 41-24 Speculative nominal interest rate, 41-22 Speculative nominal rate of return, 41-18, 41-22, 41-24 Speculative rate of return, 41-21 Speed factor, ultrahigh-slip motor, IO-22 Speed reducer, IO-5 Speed/torque curves. IO-24 Speed variation of engines. 10-14, 10-17, IO-22 Speed variation of motor, IO-24 Spending time of acids, 54-4. 54-5, 54-8, 54-11 Spent acid, 54-3 to 54-7. 54-9, 54-l I Sperry Sun BHP gauge, 304 Spheres and spheroids. measurement and calibration. 17-3 Spherical-cell model. 25-8 Spherical separator. 12-I. 12-16 to 12-18, 12-21. 12-30 to 12-32 Spherical-shell equations. 12-38 Spherical three-phase oil/gas/water separator. 12-5
ENGINEERING
HANDBOOK
Spherically focused log (SFL), 49-15, 49.18. 49.20, 49-27 Spiking, 5 l-24 Spindletop dome. Texas, 18. I, 24-7 Splash-proof motor, lo-26 Splash zone, 3-36 Split detector, 53-18, 53-19 Spontaneous ignition 46-2, 46-19. 46-20 Spontaneous potential (SP). 49. I baseline shift, 49-10 current path, 49-8 curve, 46-26, 49-l I, 49.15, 49.19. 49-25. 49-38, 49-39, 51-16. 51-17, 51-22 to 51-24, 51-32, 51-46 deflections, factors influencing shape and amplitude, 49-9 effect of interstitial shales, 49-8 effect of invasion. 49-8, 49-10 geometric effect. 49-9 in hard formations, 49-10 in soft formations, 49-10 influence of mud resistivrty and hole diameter, 49-9 origin, 49-7 phenomena in highly resistive formations, 49-10 pseudostatic, 49-9, 49-10, 49-28 to 49-30 R, determination from, 49-8 static. 49-9 to 49. I I, 49-28 to 49-30 Spool adapter flange, 3-9 Spraberry tield, Texas, 40-2 Spray zone, 3-36 Spread-mooring patterns or system, 18-9 Spreader or spreader plate, 6-58, 19-13. 19-18 to 19-20, 19-23 to 19-25, 19-29 Spreader bar, 7-12 Spring compression regulator, 13-54 Spring-loaded gas-lift valves. 5-17, 5-19 to 5-2 11 5-42 Spring-loaded regulator, 13-54, 13-55, 13-57 Spring-loaded valves. 6-49. 6-50. 13-55 to 13-57 Spring-return fail-safe actuators. 18-15 Spudding the well, 18-18 spurt loss, 55-4 Square roots of certain fractions, table, l-13 Square roots of numbers, table, l-2. l-1 I to I-13 Squares of numbers, table, I-I to l-6 Squeeze cement job, 56-4 Squeeze cementing, 5 I-40 Squeeze gravel packing, 56-8 Squirrel-cage rotor. 7-3 Stability analyses, 48-l Stability of BHP gauges, 30-5 to 30-7 Stabilization of separated fluids, 12-2 I, 12-33, 12-35 Stabilization period of wells. 32. I5 Stabilization process and unit, 12-33. 12-35. 12-42, 14-14, 14-15, 39-27 Stabilized PI, 34-30 to 34-35 Stabilizer, 14-5, 14-7, 14-8, 14-l I, 14.14, 14-15, 14-17, 54-9. 55-6 Stable emulsions, 19-2, 19-4 to 19-6 Stable isotopes, sample for analysis, 26-4 Stage-compression ratio. 39-24 Stage-pressure ratio. 12-33 Stage separation. 12-32 to 12-35. 14-14, 14-15 Stage separator, 12-1, 12-17, 12-19 Staggered line drive. 4413 to 44-16, 44-22. 44-34. 4436 Stainless steel. 30-4. 56-7 Stainless-steel filaments. 12-12 Stainless-steel pipe, 15-l I
SUBJECT
INDEX
Standard
conditions.
58.24,
definition,
Steady-state
22-21.
Standard
deviation,
Standard
distribution
of residuals.
Standard
of weights
Standards
49. I 1
of.
and
measures.
l-68
for
mud
logging,
Standing
and
Katz
charts,
Standing
correlations.
22.13.
22-5.
Standing
5-50
6-49.
valve
22-8
6-51.
puller.
8-2.
equations,
diagram.
to 22-l
for spike.
(ESP),
generators. injection.
pump
test
pressure,
BHP.
Static
drainage-area
Static
elastic
of. pressure.
constants,
Static
electricity. error,
fluids.
5-28,
5-37.
5-45.
equations.
S-17
to 5-19.
5-23 Static
geothermal
Stattc
InJectton-gas
surface
pressure.
Static
inJection-gas
pressure
temperature,
5-23
5-37 at depth.
5-3
to
5-6 fluid
gradient.
5-23.
5-25.
5-33,
5-48 5-46,
fluid
gradient
traverse.
5-45.
5-49
Static-load
5-33.
fluid
traverse,
5-25.
5-28.
5-29.
5-45
prehaure.
downstream
taps.
13-30
to
pressure
from
partial
buildup,
30-9,
pressure.
mean
taps.
pressure.
of up-and
13-33. upstream
taps,
13-26
to
self
potential
definition.
49-9
determination
Static-type
49-10,
R,,.,
of
stress.
49-28
49-10.
gas separator. level.
Station-keeping 18.11.
49-l
I
18-17
voltage
7-4,
46-5,
recovery.
18-16,
18-21. rod
18-S
18-24,
pump,
Stationary
methods. metering
stimulation,
mechanical
StatistIcal
mechanics
8-3.
approach,
8-4.
8-8,
Steady-state
conductivity.
Steady-state
electrical
Steady-state
flow.
25-2
Steady-state
in,jectivity,
Steady-state
methods
measurement. radial
46-l.
ratio.
39-2 I
39-20
32-5. 44-33,
of
28-3 flow.
43-3,
43-4
44-34
relative-permeability to 2X-7. 34-31
28-14
6-60
Storage
of
Storage
pressure
Storage
size,
sucker
46-3,
46-4.
46-22
I l-l,
I l-4 I l-l 13-57 extrapolation, relationship,
front
Steamflood
pmjects.
in nine-spot
pattern,
46-23
48. I2
to 46-28
operations.
Steel
gravity
oil-storage
Steel
gravity
structure.
Steel
island.
I8- I
Steel
jackets,
18-2.
structure.
18-2
18-2
elastomers.
allowable
handling.
9-10
connections,
failures.
9-8.
rod
grades,
rod
storage,
9-9
9-5,
9-2
and
service
factor,
9-8
and
9-10
travel,
9-10
Step
length,
dipmeter.
Step
profile
transit
Canada,
53-10.
plots,
53-l
I
51-20 IO-2 I
26-4
to 26-6
24-19
analysis.
calculation,
Stile5
method.
analyses.
IS-26 44-7.
40-19.
18.25.
effect,
9-8
factor.
9-5
conversions.
Stress
relaxation,
Stress,
Sl unit
to
in casing,
44-7
55-4.
39-14
definition.
32-6. 22-21
32-7
2-35
faults.
I.
58-23,
hanger,
Stripper
rubber,
Stripper
wells.
Strongly
impliclt
53-7
3-9 8-6 procedure
24-9.
24-18.
bearings.
Structural
casing,
18-18.
Structural
closure,
29-l.
Structural
con1ours,
48-16
44-45
10-5,
IO-12
IX-19 29-5,
29-6
39-22
process.
offshore,
criteria 18-2; plan.
analysw.
l*-25 18-25.
18-26
IX-26 and
Structural
drawings.
Structural
engineer.
Structural-frame
(SIP),
4444.
10-4.
analysis.
transportation
29-9
3-39
Structural
fatigue
55-5
to 2-37
29-3,
environmental
fracturing.
58-l
5 l-2
of a formation,
in-situ
measurement.
pipe,
2-46
55-4
oil.
riser
IO-6
ratio.
Stock-tank
for
58-5.
diagram.
Stimulation
Stock-tank
2-36
9- I3
2% I3
Structural-design
18-25
44-S 40-20.
39-9.
in
strings,
9-I I.
for,
factor,
field-development
results.
casing
recommended
41-12
gas.
propagation
diagram.
coFts.
Stimulation
to 46-2X
51-7
in suspended
ranges
44-2
58-7
in acoustic-wave 51-6.
29-8.
46-26
Stress-concentration
Stimulation
Stock-tank
53. IO.
18-27
Stress-concentration
Strontium,
53-12
porowneter.
Stiles
Texas,
Stress
Stripper
5-28
time,
transformer.
diagmm,
45-10
field,
Ranch
Strike-slip
5-19.
patterns,
to 29-S.
models,
Street
Strike
Saskatchewan,
5-15,
Stereographic
44-16
Stretch,
18-2
field,
29-3
in tubing.
loading,
dipmeter
traps,
Stretch
9-S
template,
from 53-14
Stress/strain
pulling,
44-29
58-34
to 9-4
9-10
running
44-7.
18-17
01; 9-I calculations,
39-19
44-15.
Stress
9-2
to 45-10,
44-2
Stress-range
coupling
45-7
Streamlines.
Stress,
9-4
9-2
and
ratio,
rocks,
loading,
30-7
Stratigraphic
Stress,
18-13
rods.
13-36
30-7
29-9
42-3.
reservoirs.
53-12,
Stress
18-26
12-25. 30-5.
29-5.
36-5,
I, 40-32
45-13
Streamtube
25-l
6-48
sucker
29-4.
Stratigraphy. to 46-28
12-22.
resistor,
Ime,
Stratigraphy
Steamflood
Steel-laminated
vanes,
40-3 39-25
transducers,
Strain-sensitive
Stratified
46-12
I l-2
Straight-line
45.12.
to 46-4.
12
I l-3
Straight-hne
Stratification
46-l
I I
I l-2
chokes.
46-28
46. I
losses.
(non-API),
46-23
Steamtlood,
9-14
I I-12
I l-2
Stratification.
46-12
9-13,
I l-2
46-27,
Steamdrive,
Steamflooding
46-22
9-10,
I l-2
I l-2.
Strand
steam,
rods.
of products,
evaporation
flat-sided
Storm
18-7
types,
fixed-roof.
46-22. equilibrium.
Stiff
4433 model,
contributing
46-22
Steam/water
Stevens
adsorption
techmques.
32-4,
46-18,
operations,
Valley.
Steam/tar
offshore,
faciliti&.
Strain-gauge
Beach.
Stiffness
analog
46-13.
51-2.5.
16-4
capacity
welded-steel.
46-22
of gas and
Stepdown 32-13
25-5
Steady-state
46-7.
15-18.
32-15
Storage
pipe.
51-32
28-8
theory. for
46-15.
46-40
Huntington
Stern
40-6,
to 51-14,
Storage
floatmg.
coinjection
to
18-43
installation,
Statistical
46-14,
12-22. 19-15
wells.
field-welded.
46-18
6-57.
controller,
Straightening
Steam
Steelman 18-2.
&IO Stationary-fluid
46-12
46-5 splitting.
Steel
acre-ft.
19.14, 51-12
bolted-steel,
I.
mechanisms
Steam
unloading
7-5
IO-29
systems.
Stationary-barrel
Steady-state
quality,
predictive
(SP),
of.
determination
Static
Steam
manufacture
13-29
Static
46-22 (table),
care
down
13-34
per
51-47
cone-bottom,
46-S.
propertles
waves.
Storage-tank
46-27
placement.
application.
30-10 stream
46-19
24-5
46-l
Steam
Steel
13-x
Static
46-24,
Steaming.
Static-load
48-5
48-17
steamfloods.
Steam
ParIs
34-3 balance
Static-load
(SOR),
ratio
to,
5-48
Static-force
Steam/oil
Steam-stimulation 5-25.
48-2.
56-2
model.
30-9
51-4
I I- 13
level.
19-28.
46. L9. 46-20 42-6, rate.
Steam
to 34-9
13-50
Static-fluid
46-15
I. 48-13.
6-56. 15.26.
Slobcocked
46-24
46-22
34-3
in place
law,
51-27.
injection,
Steam-injection
3-I
calculation
Static
7- I5
46-5,
water.
Steam-InJection
46-23.
ESP.
and
Stokes’
Stoneley
46-24
48-l
generation
Steam
submersible
oil
Stopcock
or floods,
48-10.
Steam
15-3 I
chart.
Static-body
flooding
to 28-7
46-23,
46-4.
8-4
10-2X
Stock-tank
15-21.
48-12
46-l. drive.
Steam-generation
IO-19
electric
Static
Static
distillation.
Steam
6-31.
7- 14
Startup-spikes
5-46.
6-3.
motors.
engines.
Startup
Static
Steam
19-28
37-21
for
of a prqject,
Static
46-9
models.
displacement.
Steam
I,
24. I9
contactor
Startup
Static
Steam-cheat Steam
28-4
28-4
times.
Steam-distillatmn
to 5-53.
6-48.
Standing’s
measurements.
to 48-8.
valve.
6-32.
Starters
52-30 20-9
methods,
28-3,
Steam-breakthrough
22-14
Standing
Static
procedure.
saturation lateral,
Starter
relative-permeability
experimental
table,
I-61
definitmn
apparatus.
40-8
Steady-xtate
50-5
Standard
Star
relative-permeability
28-4
5X-25
launch.
18-26.
15-31 18-Z
analysis.
I X-22
18-27
66
Structural maps, 41-8 Structural nose, 29-3, 29-4 Structural pinchouts. 44-39 Structural traps. 29-l to 29-3 Structure *a,, 44-38 Structure map, West Heidelberg field, 46-28. 46-30 Structure. principal factor in gravitational segregation, 442 Structure selection offshore. concrete gravity, IS-25 guyed towers, 18-25 template/jackets. IS-25 tension-leg platform, 18-25 Structures, offshore. background and philosophy, 18-22 classification of, 18-22 to 18-24 dcaign process of, 18-25 to IS-27 guyed towers, 18-24 selection of, 18-25 special services. 18.25 r&ion-leg platform. 18-24. I X-25 Strudel scour, 18-43 Studded adapter flange, 3-9 Studded flanged outlets. 3-3 Studded flanges, 3-8 Stymie condition, 5-54 Sub-bottom profiler. 18-5 Subleases, 41-15. 57-7 Subhmation curves. 23-l. 23-2 Submarine cables, 18-44. 18-45 Submarines. 3.38 Submerged Lands Act of 1953. 57-l I Submerged zone, 3-36 Submersible electric motor, 7-l. 7-3. 7-4 Submersible electrically driven pumps, I l-14 Submersible pumps, 7-l to 7-17. 44-42 Submersible rig. 18-2. 18-S. 18-6 Subordinate phase. 446 Subscript symbols in alphabetical order, 59-63 to 59-70 Subsea applications, fixed platform drilling. 3-38 floating drilling vessels, 3-39 SPPEiOCS equipment, 3-39 Subsea completion system. IS-3 Subsea drilling system. IS-IO Subsea hydraulic power unit, 18-52 Subsea (seafloor) pipelines, 18-29, 18-30, 18-35, 18-36 Subsea satellite wells, 18-33 Subsea tree, 18-31, 18-32 Subsea valve actuator. 18-50, 18-5 1 Subsea well completions, control lines, 18-33. 18-34 flowlines, 18-33. 18-34 introduction, I E-30. 18-3 1 manifolds. 18-32 multiple templates. 18-32 single satellite wells. 18-31 well servicing. 18-34 well workovers, 18-34 wset vs. dry, 18-31 Subaea wellhead installation. 6-6. 6-7 Subsea wells. 18-3. 18-14, 18-31. 18-34 to 18-38. I X-48 Subsurface completions. 3-26 Subsurface-controlled subsurface safety valves (SSCSV’s). 3-29 Subsurface tlowing pressure. calculation, 33-18 SUbSUr~dCC mapping, 40. I Subsurface~pressure surveys. 42-4 Subsurface pressures. calculation, 33-13 Subsurface pump. 9. I, 9-I 3 Subwrfxe-pump bores. X-l Subsurface-pump woke length, Y-12
PETROLEUM
Subsurface safetv valves (SSSV’s). 3-26. 3-27, 3-31, j-33, 3-34. 6-48 Subsurface saltwater, 44-42 Subsurface shut-m pressure, calculation, 33-19 Subsurface sucker-rod pumps, 8-l to S-10 Subsurface waters, 24-3. 24-19 Successive overrelation (SOR), 48-16 Sucker-rod fxlure, lo-29 Sucker-rod life, IO-17 Sucker Rod Pumping Research Inc., 8.10 Sucker-rod pumps, 6-8, 8-1, 8-10 Sucker-rod string. 8-8, 8-10, 10-1, 10-5, IO-6 Sucker rods. allowable stress and range of stress, 9-8 chemical and mechanical properties, 9-4 chemistries of. 9-5 couplings and subcouplings, 9-3, 9-4 fiberglass, 9-10 to 9-14 general dimension. 9-2. 9-3 introduction, 9-I joint circumferential displacement values, 9-10 mcchamcal properties, 9-5 pin failures, 9-9 rcfcrences. 9-14 rod and pump data, 9-6, 9-7 steel. 9-l to 9-10 storage, 9. IO tolerances, 9-3 Suction gradlent, 6-29 Suction pipmg. 15-17 Sukkar and Cornell’s method, 34.9 to 34-24 Sukkar-Cornell integral f[lr BHP calculation, 34-10 to 34-22 Sulfate-reducmg bacteria (SRB), 44-41, 44-43, 4444 Sulfide stress crackmg, 3-35, 3-36 Sulfonates, 19-10, 47-16 Sulfur, 3-3. 10-16. 19-28, 24-16, 46-22 Sulfur dioxide. 14-17. 14-22 Sulfur “il. I l-6 Sulfur/oxide ran”, 52-7 Sulfuric acid, 1 l-6 Summation-of-tluids method, “orositv. 27-1 Sun Oil Co.. 46-15, 46-18. 46-29 to*46-32 Supercompressibility factor, 13-8, 22-20, ~33.13 Supercritical CO*, 45-5 Supercritical-tluid drive, 45-5, 45-6 Superficial velocitv of gas. 34-46 Superheated stea, 46-j Superposition, 35.8, 35.9, 40-12 Suber&“ry control and data acquisition (SCADA), 16-l. 16-2, 16-6 to 16-10, 16-12 Suplacu de Barcau field, Romania, 46-4, 46-1.5. 46-18. 46-28, 46-29 Surface-active agents, addme to oil. 56-2 in coitrolling stability of emulsions, 19-l in drilling fluids, 445 Surface-active agents in waterflooding. interfacial-tenTinn reduction, 44-40 mohilitv Improvement. 44-39. 4440 rock-&ttab~lity alteration. 44-40 Surface-active chemicals, 24-2 Surface area of crude. evaporation from, 1 I-12 Surface area of fracture. 55-2, 55-X Surface area, specific, 28-8 Surface casing. 3-3 Surface closmg pressure, gas-lift valves, 5-44 to 5-47 Surface control valve. 18-50 Surface-controlled subsurface safety valves (SCSSV‘s). 3-29. 18-47. 18-48 Surface-driven pumps. 4442
ENGINEERING
HANDBOOK
Surface environment, 36-2 Surface equipment, hydraulic pumping, control manifolds, 6.54 fluid controls, 6-51 lubricators, 6-54 power-fluid systems, 6-54 to 6-57 power-oil tank and accessories, 6-57 to 6-59 pumps, 6-49 to 6-54 single-well systems, 6-60 to 6-63 Surface extractmn efticiency, 52-18 Surface facilities, design and operating program for, 39-23 for closed power-fluid system, 6-59 for open power-fluid system, 6-58 for saltwater disposal and waterflooding, 15-l to 15-33 formulating policy for. 40-l Surface-flowline hackpressure, 5-54 Surface-gas gravity td well-fluid gravity ratio, 21-17 Surface geothermal temperature, 5-48 Surface injection-gas pressure, 5-44 Surface kick-off injection-gas pressure, 5-46, 5-48 Surface-line heat losses, 46-4 Surface opening pressures, gas-lift valve, 5-39 Surface preparation for coatings. I l-5 Surface production equipment, 12-2 Surface production facilities, 36-2 Surface bumping unit, 9-1, 9-3, 9-13 Surface pumps. 6-49 to 6-51 Surface-recording BHP gauges, 30.4. 30.5 Surface safety valves (SSV’s), 3-19 to 3.21, 3-27, 3-31, 3-33. 3-34. 3-39. 18-47. 18-48 Surface seismic shear surveys, 5 I-28 Surface separation equipment, 40-24 Surface steam generators, 46-4, 46-19 Surface tension, 19-14, 22-16, 22-17, 22-19, 22-21, 24-16. 47-8, 54-6 to 54-8, 58-35. 58-38 Surface transfer pumps, 19-28 Surface unloading flowing wellhead temperature, 5-46. 5-48 Surfactant absorption on metal oxide surface. 47-15 Surfactant as foaming agent, 55-6 Surfactant breakthrough times, 47-17 Surfactantlbrineioil phase behavior. 47-1 I to 47-13 Surfactant chemistry, 47-7 Surfactantidivalent comolexes. 47-15 Surfactant flooding, 48-j Surfactantipolymer processes, 23.7 Surfactant ietdntion; 47-10, 47-15 to 47-17 Surfactant slug, 48-5 Surfactant systems. 23-8 Surfactants, adsorption of. 47-8 chemistry of. 47-7 classiticatlon of, 47-7 definition of, 54.6 in interfacial-tension reduction, 44-40 in mud removal. 56-l in water blocks and emulsion removal. 56-2 micellaripolymer. 47-7 molecular structures. 47-7 reducing acid reaction rate. 54-8 solutions, 47-11 surface tension of. 47-8 to avoid emulsification. 54-9, 54-10 Surge tank, 24-3, 44-47 Surging, applicability of horizontal separator, 12-35 in gas-lift installations. 5-I. S-22, 5.24, 5-38 in rod pumps, X-4
67
SUBJECT INDEX
Surging flow. 13-52, 13-53 Suspended solids, 15-18, 19-15, 24-5. 44-36. 44-45 Swab cups or noses, 6-47 Swabbing. 52-17, 52-18 Sweden. 12-39 Sweep after breakthrough. 44-29 Sweep efficiency. 39-18, 46- 14 Sweep efficiency at breakthrough, 4419, 44-20 Sweepout-pattern efficiency, 4423 to 44-25, 44-28 Sweet corrosion, 3-35, 4-4, 4-5, 9-8 Sweet gas, 11-10, 14-21, 14-22 Sweet natural-gas systems method, for estimatmg initial hydrate formation, 25-5 Sweetening by ethanolamines, 14-2 1, 14-22 Swelling clays, 26-18 Swelling tests. 48-9 Switchboard. electric submersible pump (ESP), 7-5 to 7-7, 7-12 Switchboard-motor controller. 7-8 Switches for control of oilfield motors, LO-27 Switching valves, 13-56 Switzerland. 12-39 Symbol subscript definitions in alphabetical order. 59-52 to 59-62 Symbol subscripts in alphabetical order, 59-63 to 59-70 Symbols in alphabetical order, SPE standard, 59-2 to 59-17 Symmetrical folds, 29-2 Syngenetic interstitial water. definition. 24-18 Syntactic foam, 1X-15 Synthetic polymers in acidizing, 54-8 System. definition. 22-2 1 Systeme International d’Unit&. 58-2 T Tadpole plot, 53-10. 53-12 Tadpole symbol or structure, 47-7 Tailgate booster, 7-2 Tailing. 9-10 “Taint,” computer subordinate routme, 17-6 Tandem labyrinth path model, 7-l 1 Tandem pumps, 6-7, 6-8 Tangential method of calculating dtrecttonal surveys, 53-5. 53-6 Tangible cost. 41-I 1. 41-13 Tangible property, 57-l I Tank battery, connections, II-9 consolidation. 16-1, 16-2 for hydrogen-sulfide crude storage. I I-10 installation and hookup, 11-Y maintenance and operation, 11-10, 11-l 1 Tank bottoms, 19-32 Tank calibration. 17-3 Tank cars. measurement and calibration, 17-3 Tank corroston protection, cathodic protection, 11-6 coatings specifications, I l-4 to 11-6 Tank dimensions, 114, 11-5 Tank gauging, 17-3, 174 Tank grades, 11-I 1 Tank pressures. evaporation loss from, 11-12 Tank-type depletion performance, 37-10 Tank-type material balance, 37-2, 37-4, 37-19, 37-21 Tank-type models. 37-2, 37-4, 37-5, 37-l I, 37-14. 37-17 Tanker loading operations, 18-36 Tanker mooring devices. IS-2
Tanker mooring systems. 18-43 Tankers. 18-43 Tankers vs. semtsubmersibles. 18-35, 18-36 Tanks, aboveground. nonrefrigerated, emergency ventmg capacity, 11-7, I l-8 means of venting, 1l-8. I l-9 normal ventmg capacity, 1l-7 venting requirements, determination of, I l-6 Tanks, measurement and calibration, 17-3 Tapered valve seat. 5- 15 Tar production history, 46-28 Tar sands, 46-3, 46-31 Tar Springs sand reservoir, Illinois, 40-32, 40-33 Tamer method. 37-10. 40-9, 40-10 Tax consequences related to conveyances, 41-15. 41-16 Taxation, 57. I1 Taylor method, 37-10 to 37-13 Taylor series expansions, 48. IO Tectonic stresses, 55-l Teflon@ seal rings, 2-1, 2-38. 4-5 Telemetry. 3-18, 3-27, 18-45. 51-27 Telemetry system, 53-1, 53-2 Tell-tale screen, 56-8 Temperature, actual, 31-2 to 314 average annual, U.S., 31-3 gradient, effect of cement behind casing, 31-6 ideal curves of flutd migrating through casing hole, 31-5 in wells, 31-l to 31-7 logs. 31-l mean surface, 31-3 radial differential log, 3 1-7 static bottomhole. 31-6 surveys. 31-l to 31-7, 42-4 Temperature-base factor, 13-3, 13-12 Temperature controls, 12-40 Temperature conversion chart, 58-39 Temperature conversion tolerance requirements, 58-7 Temperature correction factor (coefficient). 5-6. 5-7, 30-2, 30-3 Temperature data log, 52-23 Temperature dependence of compressionaland shear-wave velocities. 51-8 Temperature dtstribution. in annular completion, 46-6 in Marx-Langenheim model, 46-7 Temperature effect of tubmg string, 4-Y. 4-10 Temperature. effect on acid reaction rate. 54-4 effect on BHP gauges, 30-2, 30-3. 30-5 effect on corrosion inhibition, 54-6 effect on confined bellows-charged dome pressure, 5-6 to 5-8 effect on elastic-wave velocities, 51-7 Temperature gradient. 33-18, 58-28 Temperature log, 46-26, 49-25 Temperature measurement, 16-7 Temperature. method of measuring of petroleum and petroleum products, 17-5 Temperature of crude, evaporation loss, 11-12 Temperature, of liquid hydrocarbons. 17-5 Temperature profiles. 4-6. 4-7 Temperature ranges, of gas-condensate reservoirs, 39-2 Temperature rating of insulations, IO-26 Temperature txe of motor. IO-25 Temperature sensors, IO-29 Temperature. SI unit for, 58-5, 58-23, 58-24. 58-28 Temperature transition zone, 52-22 Temperature vs. pressure drop. 14-2
Template/jacket, 18-22. 18-23. IS-25 Ten Section field, California. 34-35 Tendon system, 18-25 Tenneco Oil Co., 46-14, 46-18 Tensile load, 18-22 Tensile strength, 3-3. 9-4. 9-5. 9-8, Y-12, 1 l-9, 18-49. 30-4. 55-l Tensile strength, API casing and liner casing, 2-2 API tubing, 2-37 line pipe. 2-46 of construction materials. 12-41 Tensiometer, 24-16 Tension-leg platform (TLP). 18-2. 18-3, 18-24, 18-25. 18-44 Tension packer. 4-2. 4-3 Tension tests of round-thread casing jomts. 2-60 Tension-type tubing hanger. 3-16 Tensional forces, 29-2, 29-3 Tensioner-line angle, 18-17 Tensioning unit, 18-13 Tensleep sand reservoir. Wyoming, 40-19 Terminology in conversion and rounding practices, 58-8, 58-9 Ternary-phase diagrams, 23-4 to 23-6, 23-8, 23-13, 47-l 1 Tertiary oil recovery. 24-2, 24-3 Tertiary polymer floods. 47-6. 47-10 Tertiary recovery, wet combustion, 46-30. 46-33 Test pressures. extra-strong threaded line pipe, 2-50 extreme-line casing, 2-62 internal-joint tubing, 2-62 plain-end line pipe, 2-50 to 2-53, 2-62 threaded line pipe, 2-47, 2-62. 2-63 wellhead equipment. 3-1, 3-2 Test procedures, gas-condensate reservoir. 39-5 Test-rack closing pressure, 5-6. 5-17, 5-18. 5-20 Test-rack opening pressure, 5-6 to 5-8. 5-16 to 5-18, 5-21, 5-22, 5-29. 5-31 to 5-37, 5-46, 5-47. 5-49 to 5-51 Test separator. 12-17, 32-6 Tester setting temperature, S-46. 5-49 Testing crude oil, 17-I to 17-8 Testing natural gas fluids. 17-7 Tetrabromoethane. 52-20 Tetraethylene glycols (TRG), Id- 18 Texaco, 464. 46-15, 46-18 Texas, 16-12. 16.13. 18-2. 19.15. 21-2, 214, 21-S. 24-3, 24-7, 24-S. 24-10, 24.20, 24-21. 26-7. 29-3. 29-4, 29-7, 29-8, 32-l. 32-2. 33-l. 33-21, 36-l. 36-2, 36-6. 39-3, 39-20 to 39-22. 39-25. 40-19, 40-23, 40-33. 40-34. 41-4, 44-14, 44-36, 4437, 44-40, 44-42. 44-46, 46-3, 46-4, 46-15. 46-18, 46-26 to 46-32. 47-3. 47-7. 47-22. 49-l 1, 49-3 I, 58-20 Texas allowable rule. 32-l Texas gulf coast, 27-6 to 27-8 Texas Railroad Commission. 32-l. 32-2, 32-15, 33-15 Texture of foams. 47-8 Texture of rock, 51-8 to 51-l 1 Thallium, 50. I3 Thaw settlements, 18-41 Theoretical considerations of multiphase flow, 34-36, 34-37 Theoretical considerations of thermal recovery, surface-hne heat losses. 46-4 wellbore heat losses, 46-5 Theorettcal models, 51-S Theoretical productivtty index. 32-4
6X
Theories of emulsions. color. 1’1-5 definition of an emulsion, 19-l. 19-2 effect on viscosity of fluids. 19-6 emulsifying agents, 19-3 to 19-5 how emulsions form, 19-2. 19-3 prevention of, 19-5 stability of, 19-5, 19-6 Theory of elastic-wave propagation in rocks. 51.49, 51-50 Theory of elasticity. bulk modulus, 51-l. 51-2 elastic parameters, relationships among. 51-2 Poisson’s ratio. 51-2 shear modulus. 51-I Young’s modulus, 5 Ill Thermal-absorption cross section, 50-10, 50-22 Thermal ammeter, IO-33 Thermal analysis, 18-41 Thermal breathing, 11-6 Thermal conductance, conversion of units, table. 1-79 Thermal conductivity, conversion of units, table. 1~79 detector (TCD). 52-4 to 52-6. 52-l 1 of a gas. 3 l-2 of a material over a depth increment, 52-22 of adjacent formation, 31-7 of cement, 46-b of common sediments, 3 l-4 of geological strata. 3 l-2 of insulating materials. 46-4 of- Kern River oil sands. 46-39 of mineral oils in motors, 7-3 of refrigerants. 14-l 1 overburden, 46-7 units and conversion factors, 58-34 variation with brine saturation, 46-37 Thermal contractum of liquid, 22-2 I Thermal cracking, 46-12, 46-15. 46-16 Thermal detectors, 50-20, 50-21 Thermal-diffusion coefficient. 50-l 1 Thermal diffusivity, 46-5, 46-7. 46-10 Thermal efficiency, 46-8, 46-Y, 46. I4 Thermal energy neutron. 50.11, 50.17. 50-36 Thermal-expansion coefficients, 17-5, 17-6 Thermal-exoansion factor. 13-8 Thermal expansion of hydrocarbon liquids, 22-3, 22-5 Thermal flooding, 40-4 Thermal inbreathing, I l-6. 11-7 Thermal lag, 31-I. 31-2 Thermal model, 484 to 48-7, 48-14 Thermal neutron absorption, 50-4, 50-2 1 Thermal neutron detectors, 50-15 Thermal neutron porosity device, 50-12. 50.20. 50.30, 50-32 Thermal overload relay, IO-29 Thermal packers, 46-19 Thermal porosity device, 50-2 I, 50-28, 50-32 Thermal properties, chemical kinetics, 46-37 oil viscosities, 46-3 I, 46-34. 46-35 pore-volume compressibility, 46-37 relative-permeability curve, 46-34, 46-37 steam properties, 4640 thermal conductivity, 46-37 vaporization equilibrium. 46-37 Thermal recovery, analytical models for steam injection, 46-7 to 46-l I case histories, 46-22 to 46-3 I current status, 46-3, 46-4 field facilities, 46-19, 46-20
PETROLEUM
field prolects, 46-13 to 46. I7 general references, 46-45. 46-46 geographical dtstribution of projects. 46-3 historical development. 46-3 in-situ combustion, three forms of, 46-l to 46-3 mtroductton to. 46-I laboratory experimentation, 46-12, 46-13 monitoring and coring programs, 46-20, 46-2 I nomenclature, 46-40, 46-41 numerical simulation, 46-I I, 46- 12 oil recovery, 46-14. 46-15 operational problems and remedies, 46-2 I, 46-22 proJect design, 46-17 to 46-19 references, 46-43 to 46-45 reservoirs amenable to. 46-3, 46-4 steam injection processes, two forms of, 46-l theoretical considerations, 46-4 to 46-7 thermal properties, 46-3 I to 46-40 well completion, 46-19 Thermal resistance. 58-34 Thermal strength stabilizing agent, 46-19 Thermal stress. 46-19 Thermal trip capabibty of circuit breakers, IO-28 Thermal venting capacity of tanks, 11-7 Thermalization. SO-22 Thermaiytic Hydrocarbon Analyzer (THA). 52-10, 52-l 1 Thermistor. 16-7, 3 l-2 Thermocouple-amplifier transducers. 46-21 Thermocouples. 16-7, 31-2, 51-5 Thermodynamic equilibrium, 23-12 Thermodynamic temperature, 58-10, 58-23 Thermogenic hydrates, 25-18 Thermometers. differential, 31-2. 31-5 electrical surface-recording, 31-2. 3 l-5 in gas, 31-2 self-contamed, 3 l-l, 31-Z time response. 3 l-2 Thermometry. l-68, l-69, 31-2 to 31-7 Thermoplastic line pipe. 15-10 Thermoset restns, 9-12 Thermosetting resin line pipe, 15-10 Thermosiphon. 19-2 I Thickening agents, 55-5 Thief hatch, 11-9, II-l], 11-13 Thief sampler, 17-1, 17-2 Thin-bed corrections, induction log, 49-17 Thin-film epoxy system, 15-10 Thu-film strain-gauge transducer, 30-7 Thmnest reservoir, fireflood. 46-29 Thtosulfates, 14-22 “Third for a quarter” transaction, 41-15 l3-spot pattern. 46-17, 47-18, 46-26 Thodos gas-viscosity method, 20-9, 20-15 Thorium. 50-2 to 50-4. 50-15, 50-16, 50.24 to 50-27, 50-34. 50-35 Thread galling, 9-9 Thread limitations, wellhead equipment, 3-1, 3-2 Thread pressure rating for casing, line pipe, and tubing, 3-3, 3-4 Threaded adapter flange, 3-9, 3-l 1 Threaded flanges, 3-8. 3-17 Threaded line pipe. 246 to 2-49 Threading and’machining dimensions, 2-63, 2-64, 2-67. 2-68 Threading data, API, 2-64 to 2-72 3-D Log’“. 51-18 3D seismic techniques, 36-I) 36.8, 36.9 3D simulator, 36-10 3D velocity log, 51-44 3D vertical mtgration, 36-9 Three-phase autotransformer, 7-6
LNGINEERING
HANDBOOK
Three-phase critical point. 25-15 Three-phase tlow. 28-9 Three-phase induction motors. 10.20, 10.31, IO-35 Three-phase numerical simulators, 46-7 Three-phase relative mobility, 28-9 Three-phase relative permeability, 28-12 Three-phase saturation condittons. 28-B. 28-9 Three-phase saturation trajectory, 28-7 Three-phase separator, 12-4. 12-5. 12.14. 12-15, 12-19. 12-21, 15.21. 16-7. 16-8 Three-phase standard transformer, 7-6 Three-phase transformer. IO-30 Three-phase voltage, IO-23 Three-phase well tester. horizontal skidmounted, 12-4, 12-21 with batch-type meters, 32-9 with oil-volume meter and PD meter, 32-8 with PD meters, 32-7 Three-point rule, 41llO Three-stage separation, 12-33, 12-34 Three-tube pump, 8-8, 8-9 Three-way bypass valve. 14-S. 14-6 Three-way engine valves. 6-9 Threshold energy, 50-7, 50-9 Threshold pressure, 28-6 Throat annulus. jet pump, 6-38. 6-40, 641. 6-46 Throat-diffuser loss coefficient, 6-37 Throat of jet pump, b-32, 6-34 to 6-37. 6-39 to 6-42. 6-46. 6-47 Throttling discharge of liquid. 12-42 Through-flowline (TFL) completions, 5-2 Through-flowline (TFL) installations. b-2. 6-6, 6-7. 6-34 Through-flowline (TFL) well servicmg, 18-34 Thrust fault, 29-3 Tia Juana Este field. Venezuela. 46-4. 46-15, 46-18 Tickell diagram, 24-19 Tie lines, 23-5, 23-9, 23-10. 45-5 Tier and rate structure, windfall profit tax, 41-15 Time-average equation. 5 I-30, 5 I-33 to 51-35. 51-50 Time-clock tab, IO-28 Time-cycle control. 5-41 to 5.44, 5-54 Time-cycle controller, 5-38, 5-40, 5-4X, 5-53, 5-55, 14.11. 14-20, 16.3, 164. 16-11 Time-cycle-operated controller, adjustment of. 5-55 Time designation, Sl metric system, 5822 Time lag of a process, 13-52. 13-53 Time-lapse techmque, 50-36 Time of injection operations, 42-2 Time-rate performance, 45. I2 Time, SI units for. 5X-5. 58.22. 58-23. 58-27 Time truncation error, 48-10 Time value of money, 41-3 Title examination, 57-9 Titled polar scan displays. 51-28 Tixier relation, 26-29 Tolerance, definition. 58-9 Tolerances, of buttress-thread casing coupling, 2-29 of external-upset tubing coupling, 243 of integral-joint tubing upset, 2.45 of line-pipe lengths. 2-47 of nonupset tubing coupling, 2-42 of ring-joint gaskets, 3-28, 3-30, 3-32 of round-thread casing coupling, 2-28 of sucker and pony rods. 9-3, 9-l 1 Toluene, 17-2, 17-5, 24-18, 26-22 Ton as a umt, l-70
SUBJECT
69
INDEX
Tool characteristxs. acoustic logging. 5 1-l 5 Tool-face angle, 53-1 Tool for long-spacing acoustic logging. 51-21 to 51-23 Tool span. conventional acoustic logging. 51-16 Tools available for directional surveys, 53-3, 53-4 Tooth efficiency, 52-25 Top-seating holddown. 8-3 Topworka (motor), 13-49 TorIspherical head equations. 12-38 Tornado chart>. 49-28 Torpeda sandstone. 28-10, 46-5 Torque. engine, IO-17 Torque factors, 10-6, IO-7 Torque mode of motors, IO-20 to 10-22, 10-25, 10-31, :O-32 Torque of motor, LO-25 Torque reductions, IO-24 Torque, SI umt for, 58-5, 58-34, 58-38 Torsion. 29-2, 29-9 Torsion modulus, 51-l Torsional waves. 5 1-2 Tortuosity, 26-28, 26-29, 26-31. 2X-6 Total dissolved solids (TDS), 15-29, 24-5. 24-l to 24-13. 24-20, 44-44, 47-2. 47-3 Total dvnamic head (TDH), 7-10 Total (&o-phase) FVF. 6-47. 6-48, 22-l, 22.13. 22.14. 22-20 Total-gas analysis. 52-3 Total-gas analyzer. 52-9 Total-gas detector, 52-5 Total liauid saturation. 40. IO Total po’rosity. 26-2. 26-3. 26-7 Total solids. M-45 Total water. definition of. 27-8 Totally enclosed fan cooled (TEFC) motor, IO-26 Totally enclosed nonventilated (TENV) motor, IO-26 Tow and launch analysis procedure. 18-27 Toxic concentration of refrigerants. 14-10 Toxic decomposition products of refrieeranta. 14-I 1 Toxicity: 52-20 Trace-element absorption factor. 50-34 Tracer studies. IS-2j Tracers. 26-21, 46-21, 52-26 Tracy’s method, 37-7 to 37-10, 37-21 T&Alaska Pitxline Ssstem. 18-3 Transducer assehbly of’sonic meter, 13-49 Transducer criteria, 30-5 Transducers, 30-6. 30-7. 46-21 Transfer pressure line. 5-48 Transformer voltage drop, lo-33 Transformers. 7-6. 7-l 1, IO-29 to IO-3 I, 10-35. 19-3 I Tranwnt backpressure, 44-35 Tramlent period, 30-l I to 30. I3 Tramlent-pressure test, 36-7 Tranwnt &tine. 35. I 1 Tranrlent well&t analysis. buildup tr\ting, 35-15, 35-16 detern&ation‘of I)~, 35. I6 drawdown test, 35-14, 35-15 Transit time. 51-15 Transit-time integration curves. 51-22 Transit-time log, 51-47, 51-48 Transit-time measurement. 51-14 Transit-time/pressure correlation, 5 l-40 Transition collapse-pre\rure equation, 2-54, 2-55 Transitmn llow (slug-mist), 34-36. 34-37. 34-40 Transition zones, 27-8 Transmonal sediments, 36-3 Transmissibility. 39-19. 48-3, 48-14 to 48-16
Transmission method, 51-11, 51-12. 51-27 Transmission 011, IO-12 Transmission system, 12-10. 12-l I Transmitter of sonic meter, 13-49 Transport coefficient, 28-l. 28-3 Transport energy, 34-46 Transport equations, 28-13. 28-14 Transport properties. umts and conversions, 58-34, 5x-35 Transportation and launch offshore, 18-26 Transportation fatigue. 18-27 Transportation systems offshore. marine terminals, 18-43 pipeline, 18-42. IS-43 tankers, IX-43 Transverse captllary imbibition, 28-12 Transverse dispersion, 28-12, 45-6 Trap, 12-1 Trap classification. 29-l to 29-6 Trapezoidal integration, 34-24 Trapezoidal rule, 33-17, 40-15 Travel time, 51-15 Travel-time measurement. boreholecompensated (BHC) log, 51-16 Travelmg-barrel rod pump, X-4, 8-10 Traveling valve. 19-28 Travcrae wa*es, 5 l-2 Treating crude-oil emulsiona. 19-6 to 19-15 Treating emulsions produced from EOR project\. 19-28 Treatment planning. hydraulic fracturing, 55-9 Treatment plant. 39-24 Tree savers, 55-9 Trespass, 57-2 Triangular diagram, 23-4. 23-5, 23-8. 23-13. 45-2 to 45-7 Triaxial PV-comprewbility technique, 26-8, 26-9 Triethylene glycol (TEG). 14-7. 14-18 to 14-20, 25-19 Triethylenr-glycoliwater mixtures, 39-5 Triggering, 51-16, 51-17 Trigonometric functions, table, l-50 to 1-54 Trimdad. 36-9, 46-3 Trinle ooint. 23-l. 23-2 Triplex’ pumps. 6-1. 6-30. 6-33, 6-45, 6-46, 6-49 to 6-51. 6-60, 6-61, 15.14, 16-11, 55-9 Tripolite, 51.5, 51-6 Tritium, 46-2 I Tritium ion, 50-6 Trix-Liz field, Texas. 46-18 Troubleshooting electrtcal submersible pump (ESP). 7-1, 7-14 to 7-17 Troubleshootmg gutde. 6-28. 6-31 to 6-33, 6-47. 6-51 Troy granite, 51-8 to 51-10 Trube correlation, 20-I I. 20-16 Trube method, 22-l I. 22-12 Trucking charges, al-12 True boiling pomt, 21-7 to 2 l-9 True equdibrium state, 25-3 True mass, dctinition of. I-70 True porosity. SO-20, 50-28 to 50-30 True stratigraphic thickness (TST), 53-10, 53-12, 53-15, 53-16 True vapor pressure, I l-12, 14-13 True vertical depth (TVD). 5-4, 5-6. 18-41, 49-37. 53-3. 53.15, 53-16 True vertical thickness (TVT). 53-10, 53-12. 53-15. 53-16 Truncation, 29-4. 29-S. 29-9 Trustee. definition. 57-3 Tube amplitude mtlo. 51-47. 51-43 Tube-type HZ detector. 52-b. 52-7 Tube wave. Sl-12. 51-47. 51-48 Tubmg. collapse pressure. 2-46
collapse resistance, 2-39, 2-41. 2-43 design factors, 2-38 design safety factors, 2-38, 2-39, 2-45. 2-46 dimensions, 2-42, 2-43. 2-45. 2-58, 2-65. 2-66 elongation, 2-37 equation for calculating performance properties, 2-46, 2-54 to 2-56 external upset, 2-38 to 2-45 gross linear footage from net footage, 2-45 hydrostatic test pressure, 2-62 integral joint, 2-38 to 2-45 internal yield, 2-39. 2-41, 2-43, 2-46 joint strength. 2-61 joint yield strength, 2-39, 2-41, 2-43, 2-46 multiplication factors. 2-45 nonupset coupling, 2-38 to 2-44 performance properties, 2-38 to 2-43 range lengths, 2-37. 2-38 round-thread and form, 2-58, 2-64 round-thread height dnnensions, 2-66 safety factors, 2-38. 2-39, 2-54 to 2-56 selection of weight and grade, 2-39 special joints, 2-38 stretch when freely suspended. 2-46 string of single weight and grade, 2-38 tensile requirements. 2-37. 2-38 thread dimensions, 2-65. 2-66 tolerance, 2-42. 2-43, 2-45 weight, 2-42, 243. 2-45 vIeId strength. 2-37 Tubing/casing annulus, 6-2, 6-4. 6-5. 18-33, 34-27 Tubing cleanliness. 56-3 Tubing constants. 4-10 Tubing hanger bowl, 3-8, 3-13 Tubing hangers, 3-8. 3-l I. 3-14, 3-16, 3-26. 3-37. 3-39 Tubing-head adapter flange, 3-9, 3-11 Tubing-head bowl. 3-8, 3-9. 3-39 Tubing heads, 3-8, 3-11, 3-14, 3-37, 3-39 Tubing installation, 33-2 I Tubing/packer system, advantages, 4-6 combination, 4-l I illustration, 4-9 in completion or workover, 4-10 operational well modes. 4-6 to 4-8 where packers are used, 4-6 Tubing performance curve, 34-50 Tubing plug, 3-35 Tubing-profile calipers, 53-17 to 53-19 Tubing pump. 8-I. 8-4 Tubing response characteristics, ballooning and reverse ballooning. 4-10 buckling effects, 4-10. 4-l I introduction. 4-8. 4-9 piston effect, 4-9 temperature effect, 4-9 Tubing-retrievable subsurface safety valve!, (SSSV’s), 3-27. 3-33 Tubing size vs. constant B. 6-20 Tubing sizes, F, values for, 34-25 Tubing support. electrical submersible pump (ESP), 7-6 Tubing thread<. wellhead equipment, 3-2 Tubing-to-packer connections, 4-1 Tubular goods sizes. 3-S Tungsten carbide. 6-34 Tunisia, 24-18 Turbidity, 44-44 Turbine expansion systems. 14-8 Turbine meters, 13-45. 13-49, 16-6, 16-7. 16.12. 17-4, 17-7. 32-6. 32-12 Turbine-powered propulcion systems. 18-43 Turbine prime mover, 18-45
70
PETROLEUM
Turbo-expander process, 14-X Turbocharged engine. IS-16 Turbopumps, 6-67 Turbulence, 14-2. 14-3 Turbulence and short-circuiting factor, 15-19 Turbulence, energy loss due to, 13-2, 13-3 permanent pressure loss from, 13-2 Turbulent flow regime, 28-13 Turnkey format, 15-32 Two-cycle engines, IO-14 to 10-16, IO-19 Two-dimensional (2D) relief maps, 5 l-28 2- and 3D seismic surveys, comparison, 36-9 2D simulator. 36-10 Two-phase compressibility factor. 39-7. 39-8, 39-10, 39-14 Two-phase flow, 34-33, 34-34, 34-37 Two-phase (total) formation volume factor (FVF), 647, 648. 22-1, 22-13, 22-14, 22-20 Two-phase separators, 12-9, 12-10, 12-17 to 12-19. 12-21. 12-25 Two-phase vertical-flow model, 7-12 Two-phase waterflooding. 47-l Two-phase well tester. with positive displacement (PD) meter, 32-8 with volume meters. 32-9 Two-receiver system, acoustic logging. 51-15. 51-16 Two-stage desalting, 19-26, 19-27 Two-stage separation, 12-33, 12-34, 22-7 Type curve, 35-6 Type II(-) phase, 23-8 Types of injection. 424 Typewritmg recommendations, Sl metric syatcm, 5X-13
U Ultimate chemical analysis, 21-I. 21-2 Ultimate depletion, 42-2 Ultimate gas recovery, 40-24, 40-34 Ultimate &I recovery, 44-37, 47-20 Ultimate recovery, 30-I I, 36-3, 37-3, 37-21, 37-25, 39-10, 39-13, 39-17, 39-20. 39-23. 39-24. 40-l. 40-2. 40-4. 40-S. 40-11. 40-13, 40-15, 40-16, 40-24, 40-26. 40-32. 40.33. 40-37. 40-39. 41-10. 41-I I. 42-2. 42-6. 44-2 to 444, 447, 4431 Ultimate recovery efficiency. 43-3 Ultimate water requirements. 4441 Ultrahigh-slip motors, IO-19 to 10-24. 10-31. IO-32 Ultrasonic level device. 16-5 Ultrasonic tests. 19-30 Ultrasonic thickness indicators. 12-40 Ultraviolet absorption unit, 12-16 Ultraviolet detectors, 3-34 Ultraviolet light, 52-10, 52-l 1 Ultraviolet photographs, 46-21 Ultraviolet radiation, I l-9 Ultraviolet (UV) sensors, 18-47 Umbilicals in subaea control systems, 18-49 Umbrella effect, 43-7 Unbalanced backpressure regulator, 5-13 Unbalanced gas-lift valves. 5-39 Unbalanced pressure regulator, 5-12 Unbalanced. single-element gas-lift valves, 5-12, 5-14. 5-17. 5-19 to 5-22, 5-41 to 5 -44 Unconformity, 29-5, 29-8. 29-9, 49-25. 53-12 Uncrosslmked gels, 55-5 Underbalance method, 56-5 Underbalanced condition, 52-17 to 52-19 Undercurrent loadmg. 7-15
Underllow slurry, 15-19 Underground storage, 11-13, 1 I-14 Undersaturated carbonate reservoir, 44-36 Undersaturated oil, 37-10 Undersaturated oil reservoirs, 40-7, 40-12 Undersaturated reservoir, 37-5, 37-6, 37-9 Undersaturated system, definition, 22-21 Undersaturated systems, oil FVF for, Trube method, 22-l I, 22-12 Vasquez and Beggs method, 22-12, 22-13 Undersaturated systems, oil-viscosity correlations, 22-16 Undervoltage relay, IO-28 Underwriters’ Laboratories Inc., IO-27 Undiscounted future net cash flow. 41-5 Unfavorable mobduy ratio, 28-7 Uniboom. 18-5 Union of Soviet Socialist Republics (USSR), 12.39. 21-2 Umon Oil Co.. 46-15. 47-22 Unit displacement, 43-10, 43-l I Unit displacement efficiency, 42-3, 43-3, 43-5: 43-6, 43-8, 43-9 Unit-of-production basis, 41-16, 41-17, 41-23 Unit of weights and measures, definition of, l-68 Unit operations, 57-7, 57-8 Unit pressure of fluid columns, 6-22, 6-23 Unit-recovery equation, depletion recovery factors, 40-10 to 40-12 depletion-type reservoir, 40-8 dry-gas reservoir, 40-25 Muskat‘s method. 40-9 Tamer’s method. 40-9, 40-10 water-drive reservoir, 40-16 Unit-recovery factor, 40.16, 40.18, 40-19, 40-24 Unit recovery for gas reservoir without water drive. 40-24 Unit response function. 35-8, 35-9 United Geophysical. 51-I United States (U.S.), l-68 to l-71, 9-8, 12-38, 12-39, 17-4, 18-3, 18-18, 18.20, 18-23. 18-25, 18-46, 24-l. 24-2, 24-6, 24-21. 36-2, 39-16, 40-16, 41-12, 44-1, 44-4. 51-l. 52-22, 52-26, 52-30 U.S. areas. core-analysis data from, 27-9 U.S. Beaufort Sea. 18-3 U.S. Bureau of Mines (USBM), l-80, 33-1, 33-3 USBM BHP gauge, 30-I U.S. Bureau of Standards, 21-8 U.S. bushel. l-69, I-70 U.S. Coast Guard jurisdiction, 18-44 U.S. customary umts. 5X-9 U.S. Dept. of Interior, 57-I 1 U.S. DOE, 21-9, 45-l U.S. gallon, 1.69. l-70 Urnted States Geological Survey (USGS), 3-39. 41-9 U.S. Government. 53-5 U.S. gulf coast area. 24-7, 24-8, 24-17 U.S. Metric Board, l-69 U.S. Mineral Management Service, 18-5 U.S. Natural Gas Policy Act of 1978, 57-10 U.S. Navy. 18-4 U.S. oil production by EOR, 46-3 U.S. OCS Orders. 18-46. 18-47 U.S. Prototype Kilogram No. 20. l-69, I-70 U.S. sieve number, 56-6, 56-7 U.S. survey foot, l-69 U.S. system of weights and measures. l-69, I-70 U.S. Tax Reduction Act of 1975, 57-i I U.S. Weather Bureau, 31-2 Unitization agreements, 41-9, 57-8 Unitization. definition of, 57-7
ENGINEERING
HANDBOOK
Unitization of tank batteries, 32-7 Unitized BOP stack, 18-12 Unitized pressure-energized secondary seal, 3-6 Unitorque geometry, IO-4 Units and names to be avoided, 58-5 Units and systems of weights and measures, British and U.S. systems, l-69, I-70 relative density and density, l-80 standards of, l-70, I-71 subdivision of umts. I-70 tables of, l-71 to l-80 the metric system, 1-68. l-69 unit and standard definitions, l-68 Universal rails, motor mounts, IO-19 U. of Houston, 50-15 Unloading and loading sucker rods, 9-10 Unloading daily production rate, 5-23 Unloading flowing-pressure traverse, 5-28, 5-32 Unloading flowing-temperature-at-depth traverse. 5-32 Unloading gas-lift valve, 5-55 Unloadinp gas-lift valve depths, 5-51 Unloading gas-lift valve temperature, 5-46. 5-48 Unloading intermittent-spacing-factor traverse. 5-45. 5-46 Unloading procedure, gas lift, 5-53 to 5-55 Unloading temperature traverse. 5-46 Unrecoverable oil, 44-11 Unsegregated reservoir, 37-5 Unstable properties, sample for determining, 24-4 Unsteady-state methods of relativepernledbihty measurement, 28-3, 28-10, 28-12, 28-14 Upflow filters, 15-20 Upkicking, 6.31 Upset configuration, 9-2 Upstream taps, 13-26 to 13-29, 13-33, 13-34, 13-37 Uranium, 24-16, 50-2 to 50-4, 50-15. 50-16, 50-23 to 50-27, 50.34. 50-35 Urethane jacket, 18-49 Utah, 24-8, 24-20, 24-21. 46-16. 46.30. 46-31. 46-33, 46-34
V V-belt drive, 10-5. lo-12 Vacuum-breaker holes, II - I3 Vacuum deaeration. 15-29 Vacuum distillation, 27-8 Vacuum-line system, 1 I-13 Vacuum models, 46-l 3 VaCUUm relief of storage tanks, 1 l-7 Vacuum units and conversions, 58-29 Validity of simulation results. model assumptions, 48-9, 48-10 spatial truncation errors, 48-10, 48-12 uncertain reservoir-description data. 48-12. 48-13 Valuation, analytical methods for computation of appraisal value. 41-3 to 41-R cash-flow projection preparation, 41-3 check list of data required for evaluation, 41-8, 41-9 fair-market-value determination, 41.2. 41-3 Valuation concepts, accounting method, 41.16. 41.17. 41-22, 41.23 average annual ROR method. 41-23, 41-24 DCF method, 41-17 to 41-20 Hoskold’s method. 41-16. 41-20 to 41-22
iUBJECT
INDEX
Morkill’F method, 41-16. 41-22 Valuation methods. equations, 41-17. 41-18 Valuatmn of oil and gas reserves. concepts of. 41-16 to 41-24 development and operating costs. 41-1 I. 41-12 federal taxes. 41-12 to 41-16 forecast of future production rate. 41-Y to 41-11 general references, 41-37 interest tables and deferment factors, 41-25 to 41-36 nomenclature. 41-36 references, 41-37 types of oil and gas property ownership, 41-I. 41-2 valuation, 41-2 to 41-9 Valve depths, continuous-flow gas-lift installation, 5-32 to 5-35 Valve depths. gas lift, 5-28 Valve mechanics, gas lift, bellows-assembly load rate. 5-16, 5-17 bellows protection, 5-16 constant closing pressure. S-13 crosswer seat. 5-16 inJection-gas volumetric throughput profiles, 5-20, 5-21 introduction. S-12 opening and closing pressures, 5-19 pilot and differential opening njectionpressure-operated valves, S-13. 5-14 port configurations, 5-15 production-pressure factor and valve spread. 5-19. 5-20 purpoacs of valves, 5-12 specifications and stem travel. 5-14, 5-15 static-force balance equations, 5-17 to 5-19 unbalanced single-element valves. 5-12. 5-13 Valve port area, 5-36 Valve port size, gas lift, 5-44 Valve-spacing transfer production pressures. 5-48 Valve specifications and stem travel, 5-14. 5-15 Valve spread. 5-19 Valve surface closing pressure, 5-47 Valve switches, 16-3 Valve-travel increment. 13-54 Valve types. 16-3. 16-4 Valves at wellhead. 3-11 to 3-13 Valves, gas-lift. crossover seats, 5-15 for intermittent lift, S-42. 5-43 injection-pressure operated, 5-12 to 5-14 mechanics, 5-12 to 5-21 mtrogen-charged. 5-16. 5-17 pilot-operated. 5-13 port configuration. 5-15 production-pressure-operated, 5-13 purpose of, 5- 12 unbalanced. single-element, 5-12, 5-13 wireline-retrievable, 5-2 van der Waals’ equation. 20-7 to 20-9, 23-12 van der Waals forces, 47-8 Van Everdingen, Timmerman, and McMahon method. 38-9 to 38-l I Vanadium, 50-23, 50-35 Vane-type compressor, I l- 13 Vane-type mist extractor, 12-S. 12-9. 12-11 Vapor control in storage tanks, I I-12 to II-14 Vapor equivalent of stock-tank liquid, 39-10 Vapor/liquid equtlibrutm (VLE) constant, 14-16 Vapor/liquid equilibrtum ratio, 39-l I. 39-12. 39-15
71
Vaporillquid:hydrute formation condmons. 25-13 Vapor losses. II-II. 11-12 Vapor pressure, 6-36, II-I I, I l-12. 19-8. 20-3. 20-11 to 20-13, 20-16, 20-17 Vapor-pressure curves, for binary mixtures. 23-4 for light hydrocarbons, 23-4 Vapor pressure, empty hydrate, 25-l I of water. 25-15 temperature curves. 14-13 temperature plot, 20-12 Vapor recovery, equipment. 19-32 line valve. 11-I I system. 11-12. II-13 unit. 15-27 Vapor/solid equilibrium constants, 25-7, 25-8 Vapor-solids equilibrium ratio method, 25-5 Vaporization/condensation phenomenon, 46-11 to 46-13 Vaporization (vapor-pressure) curve. 23-l. 23-2 Vaporization equilibrium. of an oil fraction, 46-37 of hydrocarbons. 46-12 Vaporization losses, storage tanks, II-12 Vaporizing ga$ drive, 45-l. 45-2, 45-4, 45-5, 45-13 Vaporizing gas drive simulator, 45-14 Vara as length unit. 58-7, 58-21 Variable-bore rams, 1% I I Variable deck load, 18-7 Variable deck-load capacity, 18-7 Variable Density LogTM (VDL), 51-18, 51-35, 51-41, 51-42, 51-45. 51-46 Variable-density presentation, 5 I-24, 51-25 Variable flowing pressure-gradient method, 5-22 Variable-gradlent design, 5-22 Variable-gradient valve spacing, 5-32 to 5-37 Variable-inductance transducer. 30-6 Variable-reluctance transducer, 30-5 Variable-speed drive, 7-7 to 7-9. 7-12. 7-16 Variables that affect sucker-rod string and pumping-umt loadIn& IO-5 Variance, 38-9 Vasquez and Beggs correlations, 22-7 to 22-13 Velocity, equivalents (table), l-76 in gas lines, 15-7 in liquid lines, 15-2. 15-5 of propagation. 51-2 porosity correlations, 5 l-34 porosity laboratory data. 5 l-6 ratio. compressional to shear wave, 51-35 to 51-38 Velocity meters. derivation of an orifice equation, 13-2. 13-3 energy balance. 13-l. 13-2 forms of meter, 13-2 Vena contracta. 13-3 Venango fields. Pennsylvania. 44-4 Venezuela. 6-24. IO-IS, 12-39. 18-l. 19-2. 21-4, 24-6. 24-9, 24-13, 27-9, 27.20, 46-3. 46-4. 46.15. 46.16, 46.18, 58-20 Vent discharge for tanks, I I-Y Venting atmospheric and low-pressure storage tanks. 1 l-6 to I I-9 Venting capacity of tank<, I I-7 Venting requirements for storage tanks, II-6 Ventura Avenue field. California, 40-12 Ventura field. Californta, 6-24 Venture capital. 57-8 Venturi plug valves, 3-12 Venturi tube, 13-2
Venturi-tube flowmeter. 32-13 Verscntates’“. 44-45 Vertical communication. 4X-10. 48.12 Vertical conformance, 44-5 Vertical coverage. 44-39 Vertical cylindrical vessel. 15-24 Vertical electric grids. 19-26 Vertical emulsion treater?. 19.7, 19.21 to 19-23 Vertical flow downward, 34.28 Vertical-flow system, 26-12. 26-13 Vertical fractures, 44-25. 44-28, 51-28. 51-46 tn 51-48. 55-2, 55-9 Vertical free-water knockout. 19-17 Vertical hydraulic fracture. 35-4 Vertical multiphase flowing-gradient correlation, 6-27, 6-28. 6-30. 6-43, 6-45 Vertical multistage pumps, 1 I-14 Vertical permeability, 37-5, 48-8 Vertical recycling separator. 12-14 Vertical reservoir continuity, 36-4 Vertical saturation distribution. 37-4 Vertical scrubber, 12-38 Vertical sections, directlonal-data presentation, 53-7 Vertical segregation, 37-l Vertical separator, 12-l. 12-7 to 12-9. 12-14, 12-16 to 12-25. 12-27 to 12.30, 12-35, 12-40, 18-28 Vertical-separator sizing, 12-29, 12.30 Vertical settling tank. 19-2 1 Vertical-sided structures. 18-42 Vertical splits of pipe, 53-18, 53-20 Vertical stratification, 39-18 Vertical stresses, 55-l Vertical sweep, 46-14, 46-21. 46.30. 46-3 I Vertical sweep efficiency, 39-17. 39-18. 47-11 47-2 Vertical three-phase oil/gas/water separator. 12-4 Vertical three-phase separator. 19-17 Vertical vessels, 13-53 Vertically fractured reservoirs. 35-4 Vertically fractured reservoirs, shape factors. 35-5 Vessel-motion terminology. 18-7 Vessel response to motion. 18-X Vibrating crystal (quartz) transducer. 30-6. 30-7 Vibratmg wire transducer, 30-5 to 30.7 Vibration, dampening, 16-5 fatigue, IS-34 lackmg in jet pumps, 6-34 of casing in high-current drilling, 18-21 problems in instrumentation for gas measurement, 13-I stresses, 3-1 surface pumps with oil power tluid, 6-55 switch for pumping unit. IO-29 vortex shedding, 18-2 I, 18-22 Vinyl ester, 9-12 Viscosities of gas-condensate (CC) systems, 39-4 Viscosity breaker, 56-8 Viscosity-controlled fluids, 55-4 Viscosity corrections. 6-20 Viscosity correlations. gas. 20-9 Viscosity factor, 20-15. 20-16 Viscosity gradients, 6-69 Viscosity in SI metric system. 58-24, 58-35 Viscosity index. 21-7 Viscosity number, 10-12. IO-13 Viscosity, of brine. 24-16 of dead and live oils, 46-3 I, 46-35. 46-36 of fluids. effect of emulsion on. 19-6 of formation water. 24-16, 24-17 of gas, 20-9, 20-15 of gas-free crude. 6-68. 46-35
72
PETROLEUM
of hydrocarbon of oil
gas.
vs. specific
6-67
Volumetrtc
meters.
Volumetric
methods.
free
of oils.
6-24
of pure
compounds,
of refrigerants. of sodium
15-6
gravity.
(N&I)
profile. ratio
6-24.
6-67
43-6,
for
47-2,
cell.
Viton?
4-5
or fingers, 35
Il.
28-13,
metering,
material
55-6
compresstbility
balance.
40-23,
distribution
recovery
reservon.
Volumetric
37-25.
37-23
Muskat-method
applicability. predictions,
Voltage
drop
40-13
39-26
for
overhead
and buried
cable,
IO-33 Voltage
drop
Voltage
frequency.
in electrrcal
Voltage
gradient,
Volume
correction
factors,
Volume
correction
to 15T.
Volume
correction
to 60°F.
Volume
equivalents.
Volume-limit
systems,
10-21.
IO-32
IO-23
19-25 17-5,
switches,
17-6
17-6 17-5.
table,
water
drive,
37-6,
40-24
37-10
of methane 46-14,
in water.
46-19,
46-30,
39-17.
reserve
recovery,
breaker.
Vortex
chamber,
Vortex
core,
Vortex
tinder.
I l-2,
39-18.
estimation.
oil,
meters,
Volume
of spheres
l-34,
32-8,
32-9.
32-l
6-62.
Vortex-finder
tube.
Vortex
flow
Vortex
meter.
Vortex
retainer.
Vortex
shedding,
tank
25
I2
25-12.
25-13
tluid
25-l
26. I.
12-21
phases.
25-15
12-13 with
hydrates.
I
liqwd
25-l
25-l
1
I to 25-15 with
and vapor
crude
of untreated
oil,
hydrates.
phase,
25-18
011, 12. I3
19-l
in equilibrium
25-12,
with
hydrates,
25-13 m vapor/hydrate
region,
25-13
25-15 occupted
cut,
40-19.
by various
of natural
aqueous
12-2 I
25-l
6-24. 6-42.
44-7,
I to 25-15
I3
S-12. 6-36.
gas in equilibrium
phase.
25
gases.
6-25.
6-27,
6-44.
44-9.
6.47,
44-25.
6-29. 6.56,
4428,
44-32,
44-39
16-7
12-13 1X-2 1, IS-22 13-48
6-36
openings,
25-12
25-10,
in equilibrium
of propane
12-20,
26-h
pore
14-4,
of separated
Water
meter,
region,
liquid.
gases.
suppression,
13-49
25- I6
of molecular
25-14
6-30.
pumps,
brines.
25-1.5
oil,
of natural
12-20
16-6.
with
systems.
effects
25-14,
25-10,
with
26-2
Water-cut
oil,
Water-cut
recovery
I l-2 calculation,
Water-cut
recovery
curve.
offshore
45-10
44-8
Water
depth,
Water
dewpoint
of natural
Water
dewpoint
temperature,
Water-discharge
W table,
for.
for
58-5,
engine
58-23
Guara
Wabasca
installations,
IO-19
WAG
analysis.
Volumetric-average
field.
boiling
point,
2 l-l
I,
beam,
Walnut
density,
balance,
Volumetric
behavior.
of a binary of a pure
component, efficiency, 84,
operattons.
control
6-10,
flow
rates,
Volumetric
gas throughput,
6-24,
6-25,
45-8,
45-9
gas.
18-4 14-4
14-17
valves,
12-39.
5-3,
5-8
gravel
Wash
tank,
19-20
heat capacity,
Volumetric
heat-transfer
coefficient.
Volumetric
liquid-settling
capacity.
Volumetric
material
Volumetric
matertal-balance
Volumetric
metering
pack,
46-7,
balance. vessels.
56-9
porosimeter,
58-35 12-29
40-13 equation, 12-6
48-2
Water
field,
Texas,
16-12,
41-9,
41-12
timer,
26-4
to
ratio
(WAR).
46-28.
analyses,
46-16,
46-17,
24-18.
55-7 55-6
24-19
18-49 fluids,
45-S.
48-6
40-18.
38-8
Water-drive
equations, oil
38-12,
38-13,
38-16
reservoirs.
references,
38-20
introduction,
38-l
mathematical
analysis,
38-l
nomenclature,
38-17.
38-18
efficiency
of.
to 38-16
40. I6
38-20
factor.
35-5
Water-drive
sand fields,
Water-drive
unit
Water-dump
valve,
Water-external
(WAG),
fracturing
55-5.
46-2,
39-16,
40-14.
40-6
Water-drive
shape
46-30
Water-based
55-6.
23-10
16-S
fluids,
gels,
IO. 44-25
references,
Water-based foams,
44
recovery
Water-alternating-gas
46-10
40-34,
general
51-33
46-19.
5-16
Volumetric
40-24.
constant,
57-6
39-15.
40-12.
behavior.
55-8
disposal,
36-3,
40-7.
Water-drive
56-S
Wasson
36-2.
40-6.
Water-drive
pipe,
Water/air
to
drive,
39-24.
49-7
Wash-down
Watch-dog
34-27
Water
28-10
IS-30
IO-4
Wash
Waste
displacement, disposal,
to
clause,
Washouts,
43-3,
28-3,
48-6
26-6
37-3
10-9,
45-8,
Water Water
devices,
Washburn-Bunting
23-2
Volumetric
5-15.
4438
23-3
calculations, 6-67.
34-27
40-10,
mixture,
IO-2
shells,
Warranty
Volumetric-average
24-13
46-34
(water-alternating-gas),
Wall-resistivity
40-I
21-12 Volumetric
Venezuela,
tar sand,
Walking
26-3
Volumetric
5-10,
25-16
6-63.
pattern,
jet
Vugular
W.
SI unit
Volumeters,
6-38,
wetght,
saturated.
6-63
6-62,
I
by hundredths,
I-35
Volume,
Volumetric
I,
19-29
Volume
Volumetric
48-9
gas in equilibrium
phase,
57-8
19-9
Volume
48-6.
25-l
in vapor
25-14
19-18
12-20,
3. 37-3.
25-12
natural
40-13
unit operations.
Vortex
24-l
25-13
of vapor for
44-34
40-34
32-3.
chart,
of volume
Vugs, for crude
for
24-12,
40-7.
of hydrocarbon-rich
47-17
unit
Vortices.
16-13
content,
of nitrogen
36-3,
technique
Vortex-shedding
17-6
l-73
loss vs. temperature
40-26
efficiency.
47-2,
Voluntary methods.
coning.
of vapor
Volumetric
37-25,
37-26 solvents,
to
40-I
40-9
37-2,
Water
44-7,
44-15,
31-S
37-10,
Water
44-4.
44-14,
of gas in equilibrium 40-24
36-7
sweep,
47-1,
to
compresstbility.
of CO,-rich
46-3 I Volumetric-sweep
method.
Water
of CO,,
25-17
Volumetric
37-26
channeling,
metastable,
effect,
drive,
solubility
25-16. 37-26
39-16.
4412.
Water
of effluent
without
reserves,
Volumetric
Volatile
for
40-24
water
Volumetric
37-25.
44-11,
of gases tn vapor/hydrate with
44.5.
56-2
tn light-hydrocarbon 40-27
40-2 1. 40-22
permeability
Volumetric
vs. actual
26-2 I, 40.19,
25-14
40-23
27-l
37-26
volumetric
factor,
gas in place,
untt
49-38
performance.
performance
40-13
reservotrs,
40-22,
recovery
46-9
breakthrough,
equations,
40-12
esttmates
37-2 I of,
multicomponent-flash
Volume
rdtto.
relationship
of predicted
reservoir
to
40-13
recovery
reservoir,
comparison
40-15
40-6,
reservoirs,
nonassociated-gas
efficiency,
block,
37-6.
40-26
detinttton
49-37.
oil
Volumetric
17-4
Water Water
equilibrnnn.
Volumetric
measurement
34-3 1 to 34-35.
Volatile-oil
40.13,
reservoirs,
reservoir,
reservoirs.
gas FVF,
for thermal
volume.
Volanr”.
45-7,
oil
efficiency,
44-3 I, 47-9
Inflow-performance
(IPR).
drive,
pump
17-3
method.
Vogel‘s
water
gas in oil
volatile-otl
of petroleum
standard.
with
drive,
to 40. I2
Volumetric
39-7
Vocabulary
40-6
gas-cap
undersaturated
19-S.
55-8
hydrocarbons,
Visual
19-7.
48-13
forces.
Viscous
40-S. with
depletron-type
solution
47-4
muds.
dewpoint
saturated
46-35
fingering
reservotrs
40-S
46-34,
VISCOUS
Void
m rcscrvotr. reservoirs
4-6
40-20
I
and chain
relationships.
emulsions.
Vogel
oil
oil
20-9
lo-12
Vtscous
Viscous
45-I
gear
polymers.
temperature
45-8,
temperature,
45-7.
recommendations
46-31,
40-5
40-2 1 to
40-14
tWtOS. 43-5, reducers,
40-S.
oil
55-5
vs. pseudoreduced
relations.
of gas cap,
reservoirs,
44-9.
oil-in-place,
solutions.
24-17 of water,
gas in gas reservoir
40-X
1
chlortde
Water-based
HANDBOOK
53-9
nonassociated-gas
20-8
14-l
13 I
ENGINEERING
40-17
recovery,
40-16
19.20,
microemulsion,
Water
films.
Water
formation
to 40-18
19-30 47-l
1
I l-8 volume
factor,
definition.
22-20 Water
fractional
flow.
44-12,
Water/gas
contact
(WGC),
Water/gas
relative
permeability,
44-13
38-l 28-10
to
SUBJECT
INDEX
Water gradient. 6-29, 6-44 Water-hammer problems. 15-2 Water/hydrocarbon systems, behavior of, 25-1 to 25-28 Water in crude oil by centrifuge method, 17-5 Water in crude oil by dtstillation method. 17-5 Water in effluent oil. 12-15, 12-16 Water-in-oil detectors, 19-3 I Water-in-oil emulsions, 6-27, 19-l. 19-2. 194. 19-7, 19-10, 19-11. 19-13, 19-28, 4440 Water in propane-rich fluid phases. 25-4 Water influx, 37-1, 37-3, 37-5 to 37-7, 38.2, 38-3. 40-6, 40-7, 40.15, 40.24, 40-26 Water influx rates. 38-2. 38-4 to 38-6, 38-8. 38-10. 38-14. 40-18 Water-injection case htstortes. 44-36. 44-37 Water injection, gas-condensate reservoirs, 39-15, 39-16, 39-18, 39-23. 39-24 Water-injection gradient, 3 l-5 Water-injection oil-recovery performance, areal sweep and pattern efficiency. 44-12 to 4425 displacement calculation procedures, 44-7 to 4412 reservoir fractures, effect of, 44-25, 4426 waterflood performance-method selection, 44.31_ 44-32 waterflood performance-prediction methods, 44-26 to 44-3 1 Water-injection pressure maintenance, case histories, 4436. 4437 factors in, 44-2 to 44-5 mtroduction, 44 I nomenclature, 44-41. 44-48 oil-recovery performance predictions, 44-7 to 4432 pilot floods, 4437 to 44-39 references. 4449 to 4452 residual oil determination, 44-5 to 44-7 selection and sizing of waterflood plants, 44-45 to 44-47 surface-active agents in, 44-39 to 4443 water treatmg, 4443 to 4445 well behavior, 4432 to 4436 Water-injection rate, 44-32, 4441 Waterinjection requuements, 18-44 Water-injection operations, 42-5, 42-6, 43-l Water-injection systems, 6-l Water-injection well behavior. 44-32 to 44-36 Water jets or jetting, 19-29, 19-30 Water knockout, 12-1, 12-2 Water legs, 19-20 Water manometer. 13-37 Water of crystallization, 26-21 Water/oil contact (WOC), 38-1, 38-5, 38-9. 404, 40-5. 40-15, 40-34 Water/oil mobility ratio. 447. 44-8, 47-6 Water/oil ratio (WOR). 19-27. 24-20. 28-5, 34-41, 40-18 to 40-20. 44-7, 44-9. 441 I, 44-3 I, 44-32. 4439, 46-33 Water/oil viscosity ratio, 40-18, 44-10 Water permeability, 47-8 Water power fluid, 6-27, 6-29, 6-44, 6-55, 6-56, 6-60, 6-62, 6-63 Water-pressure function, 37-8. 37-10 Water-producing intervals, location of, 31-4, 31-6 Water relative permeability, 28-6, 28 IO. 28.13, 40-18, 40-26, 44-12, 44-40. 46-37, 4638 Water resistivity, 26-3 1 Water retention time, 12-15 Water salinity, 24-3. 24-17, 24-18. 26-18. 26-19, 44-40, 50-3. 50-36
73
Wateri\and discharge, IY-30 Water-saturation data, 399 Water saturation, determining. 26-22 Water-saturation distributions, 44-l 1 Water saturatton from caplliary-pressure data, 26-25 Water-saturation profile. 44. I I Water sheds. 35-16 Water slugs. 14-21 Water source. 44-41 to 4443 Water specific gravity, 6-67 Water-supply wells. 16-14 Water surge tanks. 44-47 Water table, 44-41 Water-temperature bypass control, 13-59 Water treating. dissolved gas, 44-43 microbiological growth, 44-44 minerals, 44-44 sampling. 44-43 Water treatment for steam generation, 46-20 Water-treatment plant. 16-14 Water types, condensate water. 24-18 connate water. 24. I8 dtagenetic water. 24-18 formation water, 24-18 Interstitial water, 24-18 Juvende water, 24-18 meteoric water, 25-18 seawater. 24-18 Water underrun. 48-12 Water-vapor content, 14-3 Water-vapor removal, 14-17 to 14-21 Water viscosity, 44-6, 44-32, 44-33 Water/volatile-gas systems, 25-24 to 25-27 Water wash or washing, 19-7, 19-13, 19-15. 19-18 to 19-22, 19-27 Water-weight factors. 2-I. 2-33, 2-38 Water-wet, 19-9. 44-6 Water-wetting agent, 56-5 Watered-out, 39-15 Waterflood applications. 3-37 Waterflood displacement performance, 44-13 Waterflood oil-recovery predictions, 446 Waterflood performance-prediction methods, 4426 to 44.31 Waterflood plant facilities. 44-47 Waterflood plants, selection and sizing, 4445 to 4441 Waterflood prediction methods, table, 44-29 selection of, 44-31 Waterflood processes, case histories, 4436. 44-37 factors in, 442 to 44-5 introduction. 44-l nomenclature, 44-47. 4448 oil-recovery performance predictions, 447 to 4432 pilot floods, 4437 to 44-39 references, 44-49 to 44-52 restdual oil determinatton, 44-5 to 447 selection and sizing of waterflood plants, 44-45 to 44-47 surfaceactive agents in, 4439 to 44-43 water treating, 4443 to 4445 well behavior, 4432 to 44-36 Waterflood recovery process, 28-8 Waterflood requnements. daily water-injection rates, 44-4 I fresh waters, 44-41. 44-42 makeup water. 44-4 1 salt waters, 44-42. 44-43 ultimate water. 44-4 1 water sources, 4441 Waterflood susceptibility data, 45-8 Waterflood sweep eflicienctes, 4439
Waterflooding. an imbtbmon process. 28-14 complete. 40-16 factor in, 44-2 to 44-5 history and development, 44-I inJection wells. 34-28 of dissolved-gas reservoirs, 25-19 reservoir simulatton of, 48-4. 48-7, 48-10, 48-13 tests, 44-8 volume of produced water, 24-2 Waterfloods. in chemical tloodmg. 47-9. 47. IO. 47-2 I Waterfrac services. 55-5 Waters produced from. Appalachian area, 24-6. 24-7 California fields, 24-8 Canadian fields, 24. I2 gulf coast fields, 24-8 Illinois fields, 24-9 mid-comment fields. 24-9. 24-10 Rocky Mountain fields, 24-l I Venezuela fields, 24-13 Wave baffle, 19-17. 19-18 Wave equation. 9-3 Wave forces. IX-24 Wave propagation, 51-2. 51-3. 51-12, 51-46 Wave scatter diagrams. 18-26, 18-27 Waves in Arctic. IS-39 Waxes, 39. I Waxing, 6-56 Waxy-based hydrocarbon liquids or heavy ends. 14-6. 14-7 Waxy distillates. 14-5 Weather-related downtime, 18-8 Weight, definition of, l-70 Weight-loaded regulator, 13-54, 13-55 Weight-loss corrosion, 3-36 Wetght of a body, 58-3 Weight on btt (WOB), 18-13, 18.14, 53-1, 53-2. 53-4 Weighted-average deferment factor, 41-21 1 41-23, 41-24 Wetghted loaded valves, 13-55 Wetghts and measures. definition of, 1-68 of buttress-thread casing coupling, 2-29 of concentrations of HCI, 54-2 of external-upset tubing coupling. 2-43 of extra-strong threaded line pipe, 2-50 of integral-joint tubing upset. 2-45 of nonupset tubing coupling, 2-42 of plain-end line pipe, 2-50 to 2-53 of round-thread casing coupling, 2-28 of threaded line pipe. 2-47 Weir or weir box, 19.19, 19.20, 19.23 Weir-tank-type LACT system, I6- I3 Welch field, Texas, 44-30 Weld-neck lme-pipe flange. 3-17, 3-19. 3-23, 3-24 Welded-steel tanks, 1 I-I, 1 l-2, 1 l-9, I l-l I Welded-type seal. 3-9 Welding slag, 5-53 Welex, 49-2. 49-36, 49-37. 51-18 Welge calculations, 44-I I , 44.12 Well completions, consideration in pilot waterflooding, 44-39 offshore, 18-28 steam and firefloods. 46-19. 46-20 Well conditioning. gas-condensate reservoir, 39-5 Well costs and spacing, 39-l Well delwerability. 5-12. 39-l Well-effluent composition. 2 I 16 Well fluids and their characteristics, condensate. 12-3 crude oil, 12-3 impurities and extraneous materials 12-3 natural gas. 12-3 physical and chemical. 12-21 water, 12-3
PETROLEUM
74
Well injectivity. 39-5, 39-6, 39-23 to 39-26, 46-17 Well kick, 18-11 Well killing, 39-25 Well-log analysis, 37-3 Well logging, letter and computer symbols, 59-2 to 59-51 Well logs, caliner. 53-l casing collar-locator, 53-26 casing inspection, 53-1 dinrn~ter. ‘53- 1 diiectional surveys, 53-1 in interpretation of paleoenvironments, 36-3 measurement while drilling (MWD), 53-1 to 53-3 references, 53-26 Well-pattern geometry, 39-1 Well-performance equations, diffusivitv. 35-I. 35-2 gas well,‘%9 to 35-14 multiphase flow, 35-2 nomenclature, 35-20 oil well, 35-2 to 35-9 references, 35-21 transient well-test analysis, 35-14 to 35-20 Well preparation for sand control. cement bond, 56-4 cleanliness. 56-3. 56-4 uerforation cleanine. 56-5 perforations. 56-4,“56-5 Well-pressure performance, closed reservoir. 35-2 Well productivity, 39-5, 39-6, 39-13, 39-23 to 39-26. 46.17. 46-21. 56-3. 564 Well re-entry workbver, 18-33 Well servicing, 18-28, 18-29, 18-34 Well spacing,-39-13, 41-11 Well stimulation, 7-16, 56-1 Well-test control logic, 16-12 Well tester, 32-7 to 32-10 Well testing, 39-24, 39-25 Well-testing procedures, 32-15 Well tests and sampling gas-condensate (CC) reservoirs, field sampling and test procedures, 39-5, 39-6 well conditioning, 39-5 Well-workover equipment, 18-28 Well workovers, 18-28, 18-29, 18-34, 4439 Wellbore cleanup by acidizing, 54-8 Wellbore deviation. 56-3 Wellbore fluid expansion, 35-6 Wellbore heat losses, calculations including pressure changes, 46-6, 46-7 hot water, 46-6 model treating, 46-7 overall heat-transfer coefficient. 46-6 recent developments, 46-l saturated steam, 46-5, 46-6 superheated steam, 46-5 Wellbore hydraulics, flow through chokes, 3445 to 34-49 injection wells, 34-28 to 34-30 liquid loading in wells, 34-46, 34-50 metric conversion for key equations, 34-51 to 34-55 multinhase flow. 34-35 to 34-45 nome;lclature. 34-50, 34-51 oil wells, inflow performance, 34-30 to 34-35 producing gas wells, 34-3 to 34-28 references, 34-55, 34-56 theoretical basis, 34-1 to 34-3 Wellbore problems, 34-3 Wellbore-storage effect, 30-14, 35-4, 35-6, 35-7. 35-12. 35-15 Wellbore variables, influence on focused electrode logs, 49-21, 49-22 Wellhead assembly, 3-2, 3-3
Wellhead choke, 34-45 Wellhead control valve, 6-51, 6-59 Wellhead corroston aspects, 3-35 Wellhead corrosion protection methods, 3-36 Wellhead equipment and Bow-control devices, API flanged or clamped types, 3-1 to 3-18 corrosion. 3-35. 3-36 general references, 3-40 independent screwed wellhead, 3-39 introduction. 3-l other control devices, 3-34, 3-35 references, 3-40 safety shut-in systems, 3-18 to 3-34 special application, 3-36 to 3-39 Wellhead sampling, 24-3, 24-4 Wellhead support, electrical submersible pump (ESP), 7-6 Well’s inflow performance, 7-8 to 7-10, 7-12 Wells required, gas-condensate (CC) reservoirs, 39-26 Wellsite data-acquisition system, 5 1-25 Wellsite log analysis, in real time, 49-36 in replay time, 49-37, 49-38 West Edmond field, 40-2 West Heidelberg field, Mississippi, 46-28, 46-30 West Newport field, California, 46-16, 46-18 West Panhandle field, Texas, 34-46 West Texas area, 27-16, 27-17 West Virginia, 21-2, 24-6, 24-7 Wet combustion, 46-2, 46-3. 46-14, 46-17 to 46-19. 46-22, 46-30, 4633 reverse, 46-3 1 Wet gas, 5-2, 10-16, 39-1, 39-10, 39-11. 39-13, 39-18 to 39-20, 39-23, 39-24 Wet vs. dry subsea completions, 18-31 Wettability, 28-10 to 28-13, 44-5, 446, 4.427, 4439 Wettability reversal, 47-19 Wetting aeents. 42-2 Wetting it&iscible fluids, 28-3, 28-5, 28-6 Wetting phase, 47-9 Wetting -phase relative pernreability, 28-12 Wetting-phase saturation, 26-27, 28-6 Weyburn field, Saskatchewan, Canada, 51-32 Weymouth equation, 15-7 to 15-9 Wheatstone bridge circuit, 52-3 Whittier field, California, 44-40, 47-21, 47-22 Whole-core analysis, 27-1, 27-8 Whole-core measurement of permeability, 26-17, 26-18 Whole cores, 26-2, 26-7 Wichert and Aziz’s chart, 20-15 Wilmington field, California, 6-24, 44-39 Windfall Profits Tax (WPT), 41-1, 41-4, 41-12, 41-15 Winding-insulation materials, lo-26 Winkleman Dome field, Wyoming, 46-15, 46-18 Winsor microemulsion systems, 47-12 Wire-mesh filters, 39-26 Wire rope guidelines, 18-14 Wire-wrapped screens, 56-7. 56-8 Wireline cores, 26-2 Wireline equipment, 49-1 Wireline formation tester. 49-l Wireline logging, 50-I Wireline logging operations (schematic), 49-2 Wireline lubricator, 18-34 Wireline operations, 6-2, 6-48 Wireline-retrievable gas-lift equipment, 5-2, 5-16, 5-26, 5-50, 5-53 Wireline-retrievable standing valve, 6-3, 6-48
ENGINEERING
HANDBOOK
Wireline-retrievable subsurface safety valves (SSSV’s), 3-27, 3-33, 6-48, 6-49 Wireline tensile strengths. 30-4 Wireline unit, 18-28 Wireline well servicing, 18-34 Wiring methods offshore, IS-46 Woodsen Shallow field, Texas, 44-4 Woodson field, Texas, 46-3 Work eauivalents. table. 1-77 Work, init in SI metric’system, 58-23, 58-24, 58-32 Working barrel. lo- 1 Working fluid level, 5-5 I Working interest, 41-1 to 41-4, 41-9, 41-13. 41-15, 41-35, 57-5, 57-7, 57-9, 57-10 Working-interest fraction (WI), 4 1-2 Working pressure, wellhead equipment, 3-I to 3-5, 3-7, 3-8, 3-12 to 3-25, 3-27. 3-38 Workover fluld, 5-2 Workover-fluid invasion. 54. I 1 Workover operations, 8-8, 30-8, 39-24 to 39-26, 56-4 Workover rigs, 56-3 Wormhole effect in acidiztng, 54-8, 54-10 Woven wire mesh. 19-14 Wrap-around tubing hanger, 3-8 Wye-delta transformer, IO-30 Wye-wye transformer, IO-30 Wyllie time-average equation, 5 1-29 Wvllie’s eauation. 26-20 Wyoming. ‘21-4, 23-7, 24-8, 24-11, 24-18, 24-20, 39-16, 40.19, 40-23, 44-42. 46-3, 46-14, 46-15, 46-18
X-plot wellsite analysis, 49-37 X-ray absorbers, 28-4 X-ray crystallography, 25-5 X-ray diffraction, 25-6, 5 1-5 X-ray-diffraction analysts, 54-9, 56-3 X-ray shadowgraph, 44-17, 4419 to 44-2 I, 4425, 4434 X-Y recording mode, 51-18 Xanthan gum, 47-3 Y Y method, adjustment procedure for material-balance equation, 40-6 Yardsticks, 32-l. 32-3, 42-6 Yates field, Texas, 40-2 Year-end compound-interest factors, 41-20 to 41-22 Yield wint. 58-34 Yield-point collapse pressure, 2-54 Yield point of construction materials, 1241 Yield strength, collapse-pressure equation, 2-54 of API body and bonnet members, 3-3 of API casing and liner casing, 2-2 of API tubing, 2-37, 2-61 of elastic material, 58-2 of line nine. 2-46. 2-56. 2-63 of pipebbdy, 2-2, 2-4, 2-6, 2-8, 2-10, 2-12, 2-14, 2-16, 2-18, 2-32 of pipe material, 18-17 of sucker rods, 9-5 Yorba Linda field. California. 46-3. 46-18 Young’s modulus of elasticity’, 2-35, 5 I- I, 51-43, 51.44, 58-34 Z Zeolite ion exchange, 46-20 Zeros, importance of, 58-6 Zinc acetate, 44-42
