Production Mechanism

IFP-SCHOOL

By Khaled Madaoui February 2004

Production Mechanisms

 Natural drive (or primary recovery)  Immiscible fluid injection (or secondary recovery) - Water injection - Gas injection

 Enhanced oil recovery methods (or tertiary recovery) - Miscible process - Chemical process - Thermal process

PRODUCTION MECHANISMS

OIL FIELD DEVELOPMENT -FIELD RATE :3 STEPS or PERIODS 1-Build-up 2-Plateau(or peak) 3-Decline(then 3-Decline (then abandonment) -SEQUENCE of PRODUCTION MECHANISMS(generally MECHANISMS(generally)) 1-Natural depletion 2-Pressure maintenance( maintenance(water water or immiscible gas injection) 3-Enhanced Oil Recovery

Fundamentals of Reservoir Engineering

Typical Oil Reservoir Performance

History

Prediction Np

Build-up

Plateau

Decline

Limiting water cut

Av.Res.Pressure Qwi Plateau life

Qo GOR WOR

Introduction to Reservoir Engineering

Reservoir Engineering Studies OBJECTIVES

A

: Predict Futures Performances from:

set of data

A

set of mathematical relations (to quantify the physical mechanisms)

Some

production history (rates and pressures vs.time)

Role of Reservoir Engineerin Engineering g Department



Propose realistic scenarios of development



Define,for Define ,for each sce scenar nario, io,the the fie field ld pro produc ductio tion n profiles:Rates(oil,gas,cond.,LPG,water profiles:Rates( oil,gas,cond.,LPG,water )vs )vs time

PRODUCTION MECHANISMS Oil Field Development 

OOIP = one unique figure but uncertainties (RV, ø, SWI)



Several possible development scenarios - Each scenario

1 predicted production profile

- Limit number of cases to realistic ones - Prudence, flexibility, adaptability - Recommended scenario = economics (compare NPV ’s)

Typical Oil Field Performances

NP

NP e t a R l i O d l e i F

WATER-CUT

NATURAL DEPLETION (30%)

WATER INJ. (+ 15%)

3rdTYPE IRM (+ 5%) EOR (+ 10%)

Aband. Rate Diagnosis

Time Years

Oil Recovery Methods

• Conventional Methods  

l i O y r d e e v v o o r c e p R m I

Natural Energy Water Injection

«Primary» «Secondary»

• Unconventional Methods 



E.O.R.*

Gas Injection Chemical Processes Thermal Processes

«Tertiary»

Oth ther er «T «Tec echn hnic ics» s» Hor oriz izon onta tall Dr Dril illi ling ng Improved Reservoir Management Frac., Etc.

*Change in Physico-chemical Characteristics

RESERVOIR ENGINEERING STUDIES

QUANTIFY=CALCULATE WELL RATES qoi i=n

FIELD RATES= Qofield=

q oi i=1

t

RESERVES = t=0

Qofield =

( qoi)

for different scenarios

Introduction to Reservoir Engineering

OIL RATE PARAMETERS FROM MACROSCOPIC TO MICROSCOPIC SCALES

Stock Tank

Pwh

flowlines

Separator

mm to cm

~100 m X Km’s

Pr

Pwf

WELL RATE PARAMETERS FOR A GIVEN PRESSURE GRADIENT Pr-Pwf,OIL RATE IS AFFECTED BY:

1- Porous network geometry pore bottleneck sucession(c sucession(concept oncept of absolute absolute permeability permeability )

2- Presence of other fluids water only and/or water+gas (concepts of effective and relative permeability) permeabil ity) keo=f(kabs,Sw,Sg)) keo=f(kabs,Sw,Sg kro=keo/kabs=f(Sw)

3- Fluid viscosity for pressur pressure e gradient and keo fixed, the higher the the lower the rate(concept of mobility)

viscosity,

Oil Well Rate Parameters

OIL RATE qo=PIx(Pr -Pwf ) Pr =f(net withdrawal) Pwf = Pwh+

Ptubing

Pwh= Patm.+ P sep/trait.+ P flowlines Increasing choke size lower Pwf

lower Pwh

increase (Pr -Pwf ) o


Oil Well Rate Parameters 1-PRESSURE GRADIENT = Preservoir - P well flowing 2-PRODUCTIVITY INDEX PI INCLUDES ROCK,FLUID ,WELL PARAMETERS:

PI=f(keoh, visc.,Bo,r e,r w,s,flow regime)

Field and Well Rate Parameters keffective to oil

qoi=

a kakro(Swi+g)h oBo[Lnr e /r w +s-0.75]

n

n

Qo ( field) =

 qoi i=1

x (Pr -Pwf ) = PIx (Pr -Pwf )

=

{PIx(Pr -Pwf )} i=1

n

= (Pr -Pwf )i=1 x (PI)i Minimum value for natural flow

Average reservoir pressure at time t

PRODUCTION MECHANISMS

Production Mechanisms Mechanisms - Initial Conditions Pi at datum Ni



RV    I  S wi  PV  Soi   Boi Boi

G+W

GOC i O+W

WOC i

0

W

W

Swi

100%/Sw

Reservoir perturbations caused by drilling Drilled Well Pressure Gradient Fluid Movement Production Pressure Decline Expansion Capacity Saturation Changes Rock / Fluid Characteristic Changes

Production Mechanisms Possible Status During Development Prod.r Prod.r

Prod.r

Prod.r Gas invaded zone

GOC i

Oil zone

: Sorg, krog : Soi (PCDr.)

Water invaded invaded zone zone : Sorw,krow

WOC i Coning

At

t     

t n

Np = qoi Pr < Pi Saturation changes X phase flow (O, W, G) End saturation

Cumulative Production and Reserves

CUMULATIVE PRODUCTION N p at any TIME t = ORIGINAL OIL IN PLACE minus OIL LEFT IN SWEPT ZONES

( Sor)

minus OIL LEFT IN UNSWEPT ZONES ( Soi) t

Np =

t=0

[

n i=1

qoi ]

Ultimate Reserves



Cumulative production at abandonment conditions or at a fixed date



Abandonment conditions Oil Rate

Minimum Field Economic

- either limiting water cut - or high GOR - or low PReservoir

The individual wells are progressively shut-in as they reach the limiting conditions

Cumulative Production and Reserves

RESERVES AT TIME t = ULTIMATE RESERVES (ESTIMATED) minus CUMULATIVE PRODUCTION at TIME t

Production Mechanisms Status at Abandonment Conditions GI Prod.r Prod.r

Prod.r

Prod.r (high Water Cut, high GOR)

WI

WI

GOC i

Gas flooded zone

: Sorg

Unswept zone

: Soi

Wate Waterr flo flood oded ed zon zone e : Sorw

WOC i Concept of minimum economical rate Concept of efficiencies

Ultimate reserves

= OOIP

- Oil left in swept zones - Oil left in unswept zones = N1 + N2 + N3

Ultimate Reserves Technical Parameters t

Npu =

( qoi) =

n

PI (Pr -Pwf )

PI= 

a kakro(Sg,Swi)h oBo[Lnr e /r w +s-0.75]

=OOIP - OIL LEFT in SWEPT ZONES - OIL LEFT in UNSWEPT ZONES =N1+N2+N3

= PRIMARY+SECONDARY+TERT PRIMARY+SECONDARY+TERTIARY IARY

TECHNICAL PARAMETERS: t,n,Pl parameters,Pr ,Pwf ,Sor ,Ev Sequence of selected production mechanisms

Proven (or Proved) Reserves

Estimated Quantities of Hydrocarbon Recoverable from Known Reservoirs, by Specified Techniques Under Specified Economical Conditions,with an acceptable degree of certainty.

Reserve-Probability Reserve-Probab ility approache-Some Standards Qualitative Judgement

Quantitative Probability

Certainety

0.99

Proved

0.90/0.95

Very Likely

0.90

Likely

0.70

(Proved

Propable) Equally Likely Likely / / Unlikely

0.50

Unlikely

0.30

Very Unlikely

0.10

Proved Excluded

Probable

Possible

0.10/0.05 0.01

Recovery Factors ACCUMULATION :volume of oil or gas originally in place :finite quantity ,but uncertainties RESERVES : recoverabl recoverable e oil or gas-at st.cond.-at time tRECOVERY FACTOR=RESERVES/ACCUMULATION

RF = It is just a RATIO!!!! 10% < RF < 60% for oil fields 50% < RF< 95% for gas fields

Reserves are attached to a geological model, scenario of development,calculation methodology, economics, laws and contracts.


Material Balance (volumes expressed at reservoir conditions) • Principle Conservation of Mass Adjustment of Volumes (at reservoir conditions)

Initial Volume = Remaining Vol. - Vol. Produced + Vol. Entered

• Objectives - Evaluate recovery in natural drive at different reservoir pressures - Determine reservoir pressure versus cumulative production - Estimate initial volumes (OOIP or OGIP) from production history (pressure,production,rock/fluid data)

PRODUTION MECHANISMS

NATURAL DEPLETION (OR PRIMARY RECOVERY)

Natural Depletion Recovery Mechanisms

 Rock and fluid expansion  Solution gas drive  Gas cap expansion  Natural water influx  Gravity drainage  Combination drive

Natural Depletion

IMPLEMENTATION : Just open th the we well

PERFORMANCES

:Reservoir Pressure, Rates (Oil,Gas,Water,or GOR, WOR )

versus time

LIMITATIONS (economical rate)

: - Pr Pressure decline - Limiting water - cut - Limiting Gor


Material Balance (volumes expressed at reservoir conditions) • Principle Conservation of Mass Adjustment of Volumes (at reservoir conditions)

Initial Volume = Remaining Vol. - Vol. Produced + Vol. Entered

• Objectives - Evaluate recovery in natural drive at different reservoir pressures - Determine reservoir pressure versus cumulative production - Estimate initial volumes (OOIP or OGIP) from production history (pressure,production,rock/fluid data)

Natural Depletion - Undersaturated Oil Reservoir Initial Conditions O+W

Pi

W

Pb Ni

W

Natural Depletion - Rock / Rock / Fluid Expansion at initial conditions (to)

at t

Pb   P  Pi 

Pi O

Pressure Cum. Prod.

Np

rock

RV

oil

oil

water

Ni Boi



RV ØS oi  PV

Np

Vw

NiBoi



water

Ni  Np Bo  Vw



RV 

Natural Depletion - Rock / Rock / Fluid Expansion Material Balance Equation 1)

NiBoi

= N  N B  V  RV  i p o w

2)

Vw

=

3)

Vw

=

RV

= =

4)

Bo - Boi =

1), 2), 3), 4)

NiBoi PV  S wi  S w Soi NiBoi C w Vw P  C w S w Pi  P Soi  PV  C f PV P NiBoi C f Pi  P Soi NpBo CoB = oi Pi  P





Cef





= C NB P ef i oi i

P

Co So  C w S w 1  S wi



C f

Rock/fluid expansion – Inactive aquifer-Material balance

Initial Volume = @ Pi NiBoi

Remaining Vo + @P

=

(Ni - Np) Bo

Rock and connate Water expansion

+

(Cr +

Ni Boi SwCw) 1- Swi





average compr. original pore volume p

o

eff

i

oi

i

ceff =(coSo+cwSw+cr )/So=ctotal /So

r

P

Rock/fluids expansion-Performances expansion-Performances and limitations Performances

qo=PIx(Pr -Pwf )

Pi Pr Pwf

GOR= Rsi

Min.Pwf Pb

Limitations:: Limitations

Qo

rapid Pr decline (no pressure support) Qo decline due to(Pr-Pwf)decli to(Pr-Pwf)decline ne Concept of minimum economical rate

Natural Depletion - Saturated Oil Reservoir Initial Conditions O+W

Pi = Pb

W

W

Natural Depletion - Solution Gas Drive Prod.

O+G+W

Prod.

Prod.

- Pr  Pb - Inactive aquifer

W

Swirr

VP = VO + VGL + VW

W

(VP)i = (VP)t at Pi

VP = Voi + Vw

at P

VP = Vo + Vw + Vg

Voi = Vor + Vgl

100%/Sw

Natural Depletion - Solution Gas DriveSaturated oil-Phase diagram e r u s s e r P

Critical point Tres, Pres

t1 t2

Separator

Tc Temperature

Depletion Below Pb

Critical Gas Saturation -

Definition : Sg < Sgc Krg = 0 Use of Kr from displacement process = unreliable P > PSgc : monophasic flow (oil) P < PSgc : diphasic flow ( oil + free gas)

Development of Gas Phase -

Nucleation: supersaturation + nucleation sites (energy) Coalescences: diffusion + supply Formation of an elongated gas channel (or "gas finger") Gas production

Natural Depletion - Solution Gas Drive-Inactive aquifere- Gas liberated in the reservoir (Pwf
Qg = Rp x Qo

Rp = Rs

- At Sgc,part of liberated gas becomes mobile. Diphasic flow.Both solution gas and liberated gas are produced at surface.Production GOR (Rp) increases.

Qg = Rp x Qo

Rp > Rs

Solution Gas Drive possible mechanisms-

Part of the gas liberated in the reservoir below Pb may move up, due to gravity forces-to create a secondary gas-cap or supply an existing one(balance between gravity,capillary and viscous forces) Gas (top reservoir) Gas Oil

(well)

Solution Gas Drive - Material Balance CALCULATION OF FREE GAS VOLUME IN THE RESERVOIR at time t - Total potential gas=N iRsi in standard conditions - Remaining Remaining gas in the reservoir at time time t: (N i-Np)Rs in st.cond. - Gp:cumulative gas production=R p x Np= Gps+ Gpl - Gas balance: NiRsi= (Ni-Np)Rs +Gp+Vgl /Bg in standard conditions - FREE GAS VOLUME IN THE RESERVOIR V gl at time t: Vgl= (NiRsi- (Ni-Np)Rs –Gp)Bg at reservoir cond. - Remark on GOR definitions:solution GOR(R s)-production GOR(Rp)instantaneous instantaneo us GOR(Qg /Qo)-cumulative GOR(Gp /Np)-

Solution Gas Drive - Material Balance

Initial oil volume = remaining oil at P + freed solution gas Ni Boi = (Ni - Np) Bo + [ NiRsi - (Ni - Np) Rs - Gp ] Bg Reservoir performances: P GOR

GOR

Pb Psgc

P Np/N

Solution Gas Drive – Reservoir performancesP GOR

GOR

Qo

Pb

Pres

P Sgc

Sol.+free gas

Qo Rsi

Rs

Np/N or time

Limitations:high production GOR due to production of part of the liberated gas (below Pb ) High GOR(=Qg/Qo)

low Qoil

Gas-cap gas reservoir - Initial ConditionsPi=Pb @ GOCi

m



Ni

GcBgi NiBoi



RV    I  S wi  PV  Soi   Boi Boi

G+W

GOC i O+W

WOC i

0

We~0

We~0

Swi

100%/Sw

Natural Depletion - Gas Cap Expansion Prod.r

m



GcBgi NiBoi

G

Pwf

Prod.r Prod.r G+W

? Possible gas coning

(GOC)i Pi = Pb at GOC

Pwf  Pb

Pwf

O+W Possible water coning

W

(OWC)i W

Natural Depletion Gas Cap Expansion and Active Aquifer O+G Gas

(GOC)i

Gas cap expands Gas invaded zone (Sorg)

(GOC)t

Pr  Pb (OWC)t

Water invaded zone (Sor , Soirr )

Gp



Gps  Gpc  Gpl

(OWC)i

Gas - Cap Expansion - Material Balance Initia Ini tiall oil oil volu volume me = remain remaining ing oil vol at P + gas cap expansion + freed solution gas N Boi = (N - Np) Bo+ [ (G - Gpc) Bgc - G Bgci ] + [ N Rsi - (N - Np) Rs - Gps ] Bg Performances

P GOR

GOR

P

Np/N

Material Balance - Gas Cap Drive

1) Necessity to know evolution of Rsi versus depth (sampling at different depths) 2) While producing, if Kv important, good gas segregation and GOR = ct = RS below bubble point 3) Good gas segregation maintain pressure in the reservoir 4) Recovery can reach high values, up to 40 %OOIP

Natural Depletion - Undersaturated Oil ReservoirActive aquifer1) Many reservoirs are linked to an aquifer >> than the oil (or gas) field itself 10 to 100 times bigger

2) When Pres , water tends to invade the reservoir initially oil (or gas) bearing 3) For an efficient drainage, it is important that this water invade the reservoir regularly

Under saturated oil-Active Aquifer

2 conditions to have an active aquifere:

1)Size(~50 times oil pool size)

2)Permeability(>50-100mD)

Natural Depletion - Undersaturated Oil Reservoir Initial Conditions O+W

Pi

W

Pb Ni

W

Natural Depletion - Undersaturated Oil ReservoirActive aquifer-Status at time tOIL

Oil (+water)

Oil (+water)

We (OWC)t

Pb < Pr < Pi (OWC)i

water invaded zoneSorw-

Soi+Sw i= 1 (Sg=0) W

W

Under saturated oil-Active Aquifer

NpBo = NBoiCe(Pi – P) + We – WpBw

Reservoir Performances P GOR

LIMITATION: HIGH WATER-CUT ~95%

Pr GOR

Np/Ni or time

Material Balance - Calculation of Potential Recovery with Water Entry



For a pressure drop (Pi-Pr )following Np production



Assuming Pr > Pb (for sake of simplicity) a) Oil volume expands b) Water volume expands c) Pore volume decreases d) Aqu quif ife er expands

water entry We

e) Wa Wate terr pr prod oduc ucti tion on Wp

Oil production = a + b + c + d - e NpBo = NBoiCe(Pi – P) + We – WpBw

Natural depletion:Active aquifere and gas-cap drive O+G Gas

(GOC)i

Gas cap expands (Sorg) Gas invaded zone (Sorg)

(GOC)t

Pr  Pb (OWC)t

Water invaded zone (Sorw)

HIGH PRIMARY RECOVERY CAN BE OBTAINED

(OWC)i

Material Balance - Oil Reservoir with Natural Water Flux

Water Production 







Field production does not stop at water breakthrough Qw Field produces very often until watercut ( ) Qo + Qw reaches 98% (economics) Main problem is how to handle water produced (economics) Important for reservoir engineering work to follow water rise with observation wells

Water Influx - Aquifer Fonction (1) Examples 1- Steady State (Schiltius) equation P Oil Water

Paquif = Ct

Qw

dWe dt

Jw (Paq P)

Jw : - The Theor oric ical al va valu lue e for for si simp mple le geometries (radial, linear) - Obtained from history (by material balance)

Water Influx - Aquifer Fonction (2) 2- Unsteady State (Van Everdingen and Hurst) - Radial system - P (at wellbore) is constant - Diffusivit Diffusivity y equation Oil zone

Aquifer is defined by 2 parameters B = Ct r 2 h (td) = K(t) / C r 2

Parameters can be obtained from W e history

predictions of We

Natural Recovery Gas Cap Drive and Water Drive Reservoir

Gravity Drainage

Expansion of a gas-cap (initial or secondary) creates a gas invaded zone where So decreases leading to high oil recovery due to gravity drainage. Gravity drainage is a recovery process in which the gravity force is the main mechanism Delta ro(o/g)sup. à sigma(o/g) gravity forces sup. à capillary forces Gravity drainage must be efficient within an economical time scale good permeability-say sup 100mD-

Gravity drainage-Oil saturation decrease

in the gas invaded zone

LAB. SAMPLE h

Initial GOC

Centrifuge Gas invaded zone

GOC limit

Core displacement Sor1 Sor2

Field

So

Microscopic Oil Displacement by Water and Gas Miscible Gas Injection

Sorg Lean Gas Injection

Sorg (t1)

Sorg (t2)

Sorw

Sorg

Soi Water Injection

Pore Level Mechanisms - Microscopic Efficiency Formation of gas-oil interfaces and oil mobilization GAS

OIL

WATER

Production Mechanisms Mechanisms - Gravity Drainage (1)

•

Driving force is due to the differences of densities between gas and oil - (more or less) ever present phenomenon

Reservoir factors affecting the process: -

high mobility to oil high formation dip.or thick reservoir lack of stratificati stratification on rock fractured rock high density contrasts

Production Mechanisms Mechanisms - Gravity Drainage (2)

Oil recovery up to 70% of O.I.P. Recovery by gravity drainage gas drive because : Gravity drainage

recovery by solution

Gas Oil (well) Gas

Solution gas drive

(well) Oil

Natural Recovery -Generalized material balance Gas Cap Drive and Water Drive Reservoir

Generalised material balance equation O+G

Gas

(GOC)i

Gas cap expands (Sorg) Gas invaded zone (Sorg)

(GOC)t

Pr  Pb (OWC)t

Water invaded zone (Sorw)

Gp



Gps  Gpc  Gpl

(OWC)i

Present oil volume

=

(N N p )Bo 



Original oil volume

–

Freed solution gas

–

Gas cap expansion

–

Net water influx

–

Rock and connate water expansion

–

Injected volumes

N(Boi ) 

(B g )s  N  Rs i   N  N p Rs  G p s  

G  G   B  p c

g c

 G B g i 

We  WpBw    c f  S wi c w  N(Boi ) (1  m)  P   1 S  wi  

W B inj

N 



   G   B   G  G   B 

N p Bo  Rs B g

s

p s

g s

p c

g c

w 

G inj Bg

 G  B gi  W e  W p Bw  W inj Bw  G inj B g  c f  S wi c w  1  m    1  S wi 

 Bo   Boi    Rsi   Rs  B g s   Boi  P 

Natural Depletion Recovery Limitations

Rock/Fluid Expansion 

qo limit due to Pr

(R.F. - 5% OOIP - 10%OOIP)

Solution GasDrive 

high hi gh GO GOR R Sg Sg > Sg Sgc c (R (R.F .F.. - 10% 10% - 20% 20%OO OOIP IP))

Gas Cap Drive 

high GOR

low qo (R.F. ~ 20%OOIP)

Water Drive 

high WOR

GCD + WD

low qo

(R.F. up to 60%OOIP?)

NATURAL GAS RESERVOIRS

- CLASSIFICATION - GAS MATERIAL BALANCE EQUATION

Reservoir Engineering Data

Classification of Natural Gases from Phase Envelope, Reservoir Conditions and Separator Conditions Wet gas E R U S S E R P

Reservoir conditions

C

Condensate gas

Gas + Liquid

Gas

Dew point Separator

TC Tr Reservoir conditions

Dry gas E R U S S E R P

C

PC

C

Gas + Liquid

Gas + Liquid Separator

Gas

Separator

TC

E R U S S E R P

TEMPERATURE

TC

Initial reservoir conditions Depleted Gas reservoir conditions l . o v d i u q i l % 0

TEMPERATURE

Gas Reservoir - classification

Oil

P C

E T A S S N A E G D N O C

n t i o P e l b b u B

Gas

S

A r a G b T n E e d W n o c i r C m r e h t S n A e G d n Y o R i c D r C

t n i o P w e D

Separator

Separator

T

Gas reservoir - some definitions

Expansion factor : E 1 Bg = E Volume de n moles at reservoir conditions Bg = Volume de n moles at standard conditions Po Vo = Z . n . R . To = n . R . To Pi Vi = Zi . n . R . Ti Po Ti Vi Bgi = = Zi x Vo Pi To

Gas material balance - No water entry At reservoir conditions, Initial volume occupied by the gas = volume occupied by the remaining gas at pressure P G Bgi = (G - Gp) Bg Gp = G ( 1 -

Bgi

)

Bg

G : initial accumulation at standard conditions Gp : gas production at standard conditions Bgi =

Pstd Pi

Hence :

Zi T Tstd

Bg =

Gp = G ( 1 -

Pstd Z T P Tstd Zi

P

Pi

Z

)

Gas material balance - No water entry

P Z

xx

xx

xx

xx

Gas produced Gp

Extrapolation gives Extrapolation accumulation

G

Evolution of P versus Gp Z (NO WATER ENTRY)

This assumes that reservoir pressure depletion is the same for all the reservoir.

Gas material balance - water entry

At reservoir conditions : Initial volume occupied by the gas = volume occupied by the remaining gas at pressure P + water volume

G Bgi = (G - Gp) Bg + We or Gp Bg = G (Bg - Bgi) + We

or

Gp = G

(1-

Zi

P

Pi

Z

) +

We Bg

Gas material balance - water entry

• GBgi = (G - Gp)Bg + We - Wp Bw • Trapped gas below water front (SGRW) P Z we  0 active aquifer relatively inactive aquifer we = 0 no aquifer Gas produced

Gp

Be aware of wrong evaluation of gas in place if aqifer action is not detected. Use observation wells.

Gas Reservoirs

No aquifer : High recovery (R = 90%) Aquifer : trapped gas, lower recovery ( R = 70 %and lower) 

If aquifer is moderate, to increase recovery, producing quickly is sometimes a good solution



Necessity of observation wells to monitor water rise



Need for an evaluation of Sgrw (Log - core)

Gas Production : Possible Problems (1)

1- Active (strong) water drive

A S G

WATER

R.F

(60% ?)

Gas Production : Possible Problems (2)

2- Gas trapped (saddle) wells

WATER


RESERVES (or CUMULATIVE PRODUCTION) at ABANDONMENT ECONOMICAL RATE INSUFFICIENT RESERVOIR PRESSURE DECLINE:KEY PARAMETER t

Npu =

qoi) =

( t=0

(Pr-Pwf) DECLINE

t

n

i=1

t=0

n

PI (P (Pr -Pwf )

i=1

when Pwf=minimu Pwf=minimum m value for natural flow Pw

PRODUCTIVITY INDEX DECLINE- because of INCREASE of Sw /SgDECLINE of EFFECTIVE OIL PERMEABILITY (kr effect)


Rock/Fluid Expansion 

qo limit due to Pr

(R.F. - 5% OOIP - 10%OOIP)

Solution GasDrive 

high hi gh GO GOR R Sg Sg > Sg Sgc c (R (R.F .F.. - 10% 10% - 20% 20%OO OOIP IP))

Gas Cap Drive 

high GOR

low qo (R.F. ~ 20%OOIP)

Water Drive 

high WOR

GCD + WD

low qo

(R.F. up to 60%OOIP?)

Natural Depletion Recovery Limitations keffective to oil

qoi=

kro decline

a kakro(Swi+g)h oBo[Lnr e /r w +s-0.75]

n

n

Qo ( field) =

 qoi i=1

x (P (Pr -Pwf ) = PIx ( (P Pr -Pwf )

=

{PIx(Pr -Pwf )} i=1

n

= (Pr -Pwf )i=1 x (PI)i Minimum value for natural flow

Decline of average reservoir pressure

FIELD RATE HOW TO MAINTAIN Qo field? n

n

n

q {PIx(Pr -Pwf )} = (P -P ) x  (PI) Qo ( field) =  = oi r wf i i=1 i=1 i=1

-1-Increase number of producers -2-Improve individual PI (acidisation-frac) -3-Maintain Pr -Water (or gas) injection-4-Install artificial lift : allow Pwf to drop below minimum -5-Do nothing-Qo nothing-Qo field decrease-

Oil Field Development Methodology

PR

Np

Pwf

Min BHFP

QO

Drill more producers or Pressure Maint or Artificial lift Stimulation Do nothing

QO t

by Khaled MADAOUI

Water Injection

• Objectives: - Increase reserves by -reservoir pressure maintenance and -pushing more oil towards producers

• Factors controlling water-flood efficiency - Microscopic efficiency - Macroscopic efficiency - Mobility ratio

• Water injection patterns • Optimum level of pressure maintenance


Water Injection

• Procedure Injection of Water into Specialized Wells Source of Water, Treatment of Water to be Defined

• Timing Water Injection Implemented after Some Period of Natural Drive

• Planning Injection, Locations and Injection Rate to be Optimized

SECONDARY RECOVERY

RESERVOIR PRESSURE MAINTENANCE EFFECTS 1- MAINTAINS WELL ERUPTIVITY 2- STOPS OR REDUCES -WATER ENTRIES -GAS-CAP EXPANSION -GAS LIBERATION at Pr
SECONDARY RECOVERY

RESERVOIR PRESSURE MAINTENANCE MEANS INJECTED FLUIDS:WATER or ASSOCIATED GAS SPECIALIZED WELLS-PERIPHER WELLS-PERIPHERAL AL or PATTERN INSURE VOIDAGE REPLACEMENT (i.e injection rate=production rates at reservoir conditions )

Q fi Bfi=QoBo+QwpBwp+QfgBfg

Pressure Maintenance by Water Injection (in aquifer) and Gas (in Gas Cap) PRODUCTION Water injection

Gas injection

Gas injection

Water injection

SWEEP EFFICIENCIES

INJECTED FLUID WILL BREAK-THROUGH ABANDONMENT CONDITIONS:LIMITING WATER-CUT or LIMITING GOR(gas inj.) ONLY PART OF THE RESERVOIR IS SWEPT Volumetric sweep efficiency < 1 IN SWEPT ZONES,RESIDUAL OIL CANNOT DISPLACED Microscopic-or displacement-efficiency displacement-efficiency < 1

SWEEP EFFICIENCIES-SCHEMATIC REPRESENTATION WATER vs. GAS INJECTION Water injector

Oil producer Gas injector

Oil producer

Soi

Sorw

Sorg

Soi

Factors Controlling Flood Efficiency

Displacement efficiency - Connate water saturation - Relative permeabilities

Areal sweep efficiency - Mobility ratio - Well pattern

Vertical sweep efficiency - Geological model - Contrast in layer - Permeabilities

Microscopic aspects:Displacement aspects:Displacement of Oil by Water Initial state Oil Sat. = Soi

Intermediate

Final state Oil Sat. = Sorw

Water Injection - Displacement Efficiency Efficiency (Pore Scale) Limitations = Capillary Forces

Parameters involved: -

Viscosities: o, w Densities: o, w Interfacial tension: Wettability: Shape and size of pores Rate of displacement: (or grad P) Capillary / Capillary / viscous forces: / w

Affects Kr and saturation (lab scale)

Wat ater er - we wett sy syst stem em : in infl flue uen nce of / v on SOR negligible Oil - Wet system

: SOR when / v

OR = S OR = Residual oil saturation after water injection

Pore Level Mechanisms - Microscope Efficiency 

Competition between viscous and capillary forces capillary number: Nc m E 1.0 , . f f e t n e m e c a l p 0.5 s i d c i p o c s o r c 0.0 i M





U

PORE SIZE DIST'N NARROW AVERAGE WIDE WATER-WET SYSTEMS

10-6

10-4 10-2 Capillary number, Nc

100

Competition between gravity and capillary forces Dombrowski Brownwell number: gk Nb 

Em

for Nb > 10-5

Displacement Efficiency

INTERFACIAL TENSION

CAPILLARY FORCES

LIMITATION OF DISPLACEMENT EFFICIENCY

Microscopic Displacement : Oil by Water (1)

Water drive leaves residual oil in sand because surface films break at restrictions in sand pore channels

Water out Water in

Residual oil

After Courtesy Journal of Petroleum Technology - June, 1958

Microscopic Displacement : Oil by Water (2) Capillary forces cause water to move ahead faster in low permeability pore channel (A) when water is moving slow through high permeability pore channel (B) A

Oil out Water in

B After Courtesy Journal of Petroleum Technology - June, 1958

Microscopic Displacement : Oil by Gas

Gas displaces oil first from high permeability pore channels. chann els. Residual oil occurs in lower permeability pore channels c hannels Residual oil

Gas out Gas in

After Courtesy Journal of Petroleum Technology - June, 1958

Microscopic Displacement

Natural displacement of oil by water in a single pore channel

Oil out Water in Sand

Grains

Microscopic Displacement

Natural displacement of oil by gas in a single pore channel Connate water

Oil out Gas in Sand

Grains


Microscopic Displacement- Effect of Wettability Water Wet

Oil

Water

Oil Wet

Water

Oil

Relative permeability curves Objectives Describe 2 and 3 phase flow performances(only tool !) Predi Pr edict ct re rese serv rvoi oirr per perfo form rman ance ces s - Solution gas drive - Water flood - Immiscible gas inj. - Gas - Cap expansion

Methods:direct lab measurement - 1 - Unsteady - state (room cond.) W - O, O - W, G - O (Swi 0), G - O (Swi  0), G - W -2 -

Steady - state (room cond.) W - O, O - W, G - W, W – G

Provide(w/o):Swi,kro at Swi,Sorw,k rw at (1-Sorw),kr’s vs.Sw

Saturation Functions:kr and Pc 2

1.0

Water - Oil Relative permeability

1 3

w r

k 0.8 d n a o r

k , y 0.6 t i l i b a e m r e 0.4 p e v i t a l e R 0.2

R E T A W E L B I C U D E R R I

L I O L A U D I S E R

Oil Water

w

P o P = c P e r u s s e r p y r a l l i p a C

2 0.0 0.0

0.2

0.4

0.6

0.8

e v i t i s o P

R E T A W E L B I C U D E R R I

Capillary pressure vs. Sw for water drainage and imbibition L I O L A U D I S E R

W a

t e r

W

d r ra i nag a e

a t e

r

i m

1

b i b i t i

0

1.0

o n

e v i t a g e N

1.0

Water saturation, Sw

3 0.0

0.2

0.4

0.6

Water saturation, Sw

0.8

1.0

Relative Permeabilities : Welge method (1) Experimental procedure • Plug preparation (measure k and ) • Plug evacuation and water saturation • Plug in the cell • Displacement with oil – measure collected water – calculate Swi – measure flow rate at Swi – calculate Kro at Swi

Relative Permeabilities : Welge method (2)

• Displacement with gas or water – measure total produced volume vs time – measure oil produced volume vs time – when no more oil is produced measure flow rate at Sor to calculate Krg or Krw at Sor

• Compute Kg / Ko or Kw / Ko (Buckley - Leverett) • Compute Krg (or Krw) and Kro (Johnson, Bossler, Naumann)

Relative Permeabilities : Three phases • Relative permeability to the wetting (water) phase is only a function of the wetting phase saturation. sa turation. • Relative permeability to gas is only a function of gas saturation in most cases. • Relative permeability to oil is calculated from relative permeabilities in two phases systems.

Kro (So, Sw, Sg) (Krow Krw) (Krog Krg) Krw Krg Krw

water relative permeability at Sw (water-oil system)

Krg

gas relative permeability at Sg (gas-oil system)

Krow Krog

oil relative permeability at Sw (water-oil system) oil relative permeability at Sg (gas-oil system)

Relative Permeabilities : Buckley - Leverett theory • As Assu sume me :

- no no grav gravit ity y effe effect ct (l (lit ittl tle e or or hor horiz izon onta tall plu plugs gs)) - no capillary effect (high flow rate)

• Mathematical development presented assumes water-oil case (equivalent for gas-oil case) • Fractional flow equation

qw qo f w

K Krw

P

A

w

K Kro

x

P

A

o

qw qw qo

x

1 1

w o

Kro Krw

Relative Permeabilities Formula (Empirical) • Do not provide critical and residual S

S*

So Sor 1 Sw Sor

or

1 Sw Sor 1 Swi Sor

S* normalized saturation

Kro

Krg or Krw

Sandstones (homogenous)

(S*)3

(1 S*)3

Sandstones (heterogenous)

(S*)3.5

(1 S*)2 (1 S*1.5)

(S*)*

(1 S*)2 (1 S*2)

Limestone

Problems Linked with Relative Permeabilities (1)

• Rel perm. is a composite parameter BLACK-BOX

Includes : -

Rock / Fluid interaction Rock / Fluid / Fluid / Fluid interaction ( interfacial tension) Gravity - Capillary forces Heterogeneity (scaling)

nb: Measurements more reliable if conducted at reservoir conditions with actual reservoir fluids

Problems Linked with Relative Permeabilities (2)

• Some people have tried to get rid of relative permeability : no success ! • Hysteresis (Drainage - Imbibition) • Relative permeability cannot be obtained directly from production data (matching parameter)

Relative permeability Curves

• Kr curves

not universal F (porous medium, fluid cond.) • Kr curves • Kr curves f (saturation history) hysteresis Kr (Dr.) Kr (Imb.) • Practical success due to adjustment possibilities Problems - Initial choice if no history - No real scientific support. Global adjustment parameter only ?


Relative Permeabilities Influence of Wettability

Water Wet

Swi

50 %

Oil Wet

Sor Sw

Swi

Values of Swi and Sor Values of Krw for Sor Position of the intersection

50 % Sor

Sw

Factors Controlling Flood Efficiency

Displacement efficiency - Connate water saturation - Relative permeabilities

Areal sweep efficiency - Mobility ratio - Well pattern

Vertical sweep efficiency - Geological model - Contrast in layer - Permeabilities

Volumetric sweep efficiency=Eareal*Evertical

- Current lines - Iso-P lines

I- Areal sweep efficiency

Ea = Aswept/ A Aswept/ A total

II- Vertical sweep efficiency

Ev = Aswept/ A Aswept/ A total

Pressure profile between injector and productor

Injector

Producer

Pwinj

e r u s s e r P

Pr

Sor

Qwinj = II (Pwinj-Pr )

Soi

Pwf

Qo = PI (Pr -Pwf )

Five Spot Injection Pattern

Injectors Producers Injector

Producer

Cross section

Water flooded zone - Intermediate status

Water flooded zone - Final status

Mobility Ratio

Oil mobility

=

ko  o

kw

Water mobility

=

M mobility ratio

mw = mo



Qo  A



 w





 Vo

 Vw

f (relative velocity)

Mobility Ratio Concept – Mobility

mi = Ki/ i (proportional to fluid velocity) M mw mo

– Mobility ratio



(Relative velocity of the two fluids for a same P) – 2 cases: m < 1 or m > 1

M

Ideal case < 1

M>1 (most frequent case)

Piston like displ.

Instabilities

krw (Sor )



 w

x

 o

Kro(Soi)

to lower M

w (polymers)

kro (surfactants)

Producer well

Area under observation

Injector well

Water flooding: Mobility Ratio = 1.43

WOR = Instantaneous producing water-oil ratio Water Breakthrough

WOR = 0.5

WOR = 2

70.5%

82.2%

Oil-containing area Water invaded area

Mobility Ratio = 0.4 Oil-containing area Water invaded area

Area sweep efficiency 65%

Water Breakthrough

Area sweep efficiency 82.8%

WOR = 0.6

87.4%

X-ray shadowgraphs shadowgraphs of flood progress progress in scaled scaled five-spot five-spot patterns

WOR = 4.7

95.6%

macroscopic trapping 60 à 90% du volume

Water

macroscopic trapping 30 to 70% volume

Oil

Water Injection Recovery Volumetric Relationships

W.I. recovery (STB)

Oil left in swept area (STB)

–

Oil left in non swept area (STB)

PV VR  Ø  I  Swc  VR  Ø  Ev  Sor VR  Ø  I  Ev   I  Swc   b1 b1 b1 

N(wi) 

O.I.P. at = beginning of W.I. – (STB)





Water Injection Efficiency

Water-flood Waterflood recovery recovery = Areal sweep efficiency efficiency x Vertical sweep efficiency x Displacement efficiency

Water Injection Recovery R = Ed x Ev x EA Ed = Displacem Displacement ent efficiency Ev = Vertical efficiency Volumetric efficiency = EA x EV EA = Horizontal efficiency Order of magnitudes Ed

=

Soi - Sor = 0.6 @ S = 10% wi 0.5 @ Swi = 30% Soi 0.3 @ Swi = 50%

Evert = 0.4 if non-communic non-communicating ating layers 1 in homogenous reservoir EA = f (mobility ratio) use abacus for rapid estimate

Effect of Mobility Ratio

On the displaceable volumes injected for the five-spot pattern. M = w / o* (after dyes, caudle, and

On sweep efficiencies for the fivespot pattern. Fw is the reservoir cut and M = w / o* (after dyes, caudle, and

Erickson, Trans. AIME)

100

t n e c r 90 e p y c 80 n e i c i f f 70 e p e e 60 w S

Erickson, Trans. AIME)

100

Displacement volumes injected

50 0.1

t n e c r 90 e p y c 80 n e i c i f f 70 e p e e 60 w S

2. 5 2.0 1.75 1. 4 1.2 1.0 0.9 0.75

h g u r o h k t a r e l B

ia a n i t i I n

0.2

0.4

2.0

4.0

Fw 95 9 0

8 0 7 0 6 0 5 0 4 0 30 2 0

50 0.1

10

Reciprocal mobility ratio 1/M

*

( γw

0

0.2

0.4

2.0

4.0

Reciprocal mobility ratio 1/M



kw w

, γo



ko o

)

10

How and Where Injecting Water ?

THE PATTERN - The peripheral injection - The direct and staggered line-drive - The five spot - The seven spot - The nine spot - Special patterns (two, three, four spot)

Field water injection rate- Number of injectors • Qwinj Bwinj = QoBo +( Qwp Bwp) +( Qfg Bfg)

•

Average qwinj per injector = II (P winj - Pr ) Pr @ time t to be maintened by water injection

•

Rough estimate of no. of injectors = Qwinj / qwinj

•

Remarks :

Phydrostatic

Pwinj < Pfrac

Pfrac = frac gradient x depth (frac gradient 0.65 psi/ft-0.70psi/ft) Phydrostatic = water gradient x depth (water gradient 0.45 psi/ft-0.47psi/ft) 



Water injection pattern selection

• Water injection objectives : => Insure pressure maintenance => Qwinj => Insure good volumetric sweep efficiency => increase number of injectors?

• Economical optimization is the key issue Number and location of injectors to be decided to optimize volumetric sweep efficiency i.e reserves

Pattern selection criteria

• Peripheral injection for : - structure with reasonable dip (to benefit from gravity) - rather good permeability

• Pattern injection for : - low dip formation - low permeability formation

Peripheral Water Injection Water injector

Producer

Oil water contact Injector

Producer

Flooding Patterns Injection well Production well Pattern boundary TWO-SPOT

REGULAR FOUR-SPOT

SKEWED FOUR-SPOT

NORMAL NINE-SPOT

THREE-SPOT

FIVE-SPOT

INVERTED NINE-SPOT

SEVEN-SPOT

DIRECT LINE DR DRIVE

INVERTED SEVEN-SPOT

STAGGERED LINE DRIVE

Classical Waterflood Patterns (1) Well spacing

Row of producers

Distance of injector to producer

Row of injectors

Line drive Well spacing

Row of producers

Row of injectors

Staggered line drive

Distance of row of injector to row of producer

Classical Waterflood Patterns (2)

Five spot

Well spacing

Distance of injector to producer

Depletion Above Pb Optimum Level of W.I. Pressure Maintenance



Generally P maintained at P > Pb



Oil FVF = maximum @ Pb

minimum volume of stock tank oil left



Oil vi viscosity minimum at at Pb

mobility ra ratio mi minimum

Depletion Below Pb

Critical Gas Saturation - Definition : Sg < Sgc

Krg = 0 - Use of Kr from displacement process = unreliable - P > PSgc : monophasic flow (oil) - P < PSgc : diphasic flow ( oil + free gas)

Development of Gas Phase - Nucleation: supersaturation + nucleation sites (energy) - Coalescences: diffusion + supply - Formation of an elongated gas channel (or "gas finger") - Gas production

Supplemental Suppleme ntal recovery (water displacing oil) Production well

Injection well 1.0

Sgr n o i t a r u t a S 0

Sgr

Sg

Sor Sob Swf

So

Swc

Swc

Swc

Flooded out reservoir

Oil bank area

Reservoir unaffected (as yet) by flood

Sgr – Residu Residual al gas gas satura saturati tion on Sor – Resid Residual ual oil oil satur saturat ation ion Sg – Gas Gas sa satu turat ration ion du due e to to prima primary ry dep deple letio tion n So – Oil Oil sat satura urati tion on aft after er pri primar mary y depl depleti etion on Sob – Oil bank bank oil saturat saturation ion Swf – Water Water saturatio saturation n added added by injection

Distance

Saturation Profile During a Waterflood in a Depleted Reservoir When a Trapped Gas Saturation Exists

e l a c s n o i t a r u t a s d i u l F

TRAPPED GAS

INITIAL GAS SATURATION

OIL BANK INVADING WATER BANK CONNATE WATER Distance

INITIAL OIL SATURATION

Waterflood Efficiency vs Sgi Sgr

70

Ro

60

% N / 50 p

N = 40 o

R , V P 30 %

Sor

Displaced gas

r g

S 20 r o

Sgr

S 10 0

0

10

20

Sgi % PV

30

ENHANCED OIL RECOVERY PROCESSES CONTENTS -1-INTRODUCTION EOR world potential-

-2-THERMAL PROCESSES Steam injection –Air injection - Steam -3-CHEMICAL METHODS -Polymers and Surfactants

-4-GAS INJECTION as a promising EOR process Specificities,Mechanisms,Efficiencies,Selection criteria,Ratios,Methodology to - Specificities,Mechanisms,Efficiencies,Selection conduct a GI project

-5-CONCLUSIONS: EOR vs R&D

Typical Oil Field Performances

NP

NP e t a R l i O d l e i F

WATER-CUT

NATURAL DEPLETION (30%)

WATER INJ. (+ 15%)

3rdTYPE IRM (+ 5%) EOR (+ 10%)

Aband. Rate Diagnosis

Time Years

Ultimate Reserves and Recovery mechanism sequence Npu =N1+N2+N3 at economical abandonment abandonment conditions =N1+(Ni-N1)[EdxEvol]water +(Ni-N1-N2)[EdxEvol]gas

How to optimise Npu?How to combine N1,N2,N3? Main parameters? N1(nat.depl.) :identification-limitations-duration N2(water inj.) :limitations :limitations-implementa -implementation-duration tion-duration N3 (EOR)

:process selection-imp selection-implementation lementation

Tertiary Recovery Objectives PRODUCE-ECONOMICALLY - PART OF OIL LEFT BY CONVENTIONAL RECOVERY METHODS – Improvement of displacement efficiency

decreasing Sorw miscible or near miscible gas injection miscible chemical flood-surfactant flood-surfactants s increasing gravity forces oil vaporization – Improvement of volumetric sweep efficiency

lowering mobility ratio by increasing chemical flood - polymers

reducing

o

thermal flood

w

Microscopic and Volumetric Sweep Efficiencies Example of Five Spot Injection PatternSoi

Injectors Producers Injector

Producer

Cross section Sorw

Water flooded zone - Intermediate status

Water flooded zone - Final status

Pore Level Mechanisms - Microscope Efficiency 

Competition between viscous and capillary forces capillary number: Nc  m E 1.0 , . f f e t n e m e c a l p 0.5 s i d c i p o c s o r c 0.0 i M



U


10-6


100

Competition between gravity and capillary forces Dombrowski Brownwell number: gk  Nb Em

for Nb > 10-5

Water Injection Efficiency

Water-flood efficiency

=

Areal sweep efficiency x Vertical sweep efficiency xDisplacement efficiency Sorw = 0

Limitations:

Ed<1

Eareal<1

f(pattern,mobility f(pattern,mob ility ratio)

Evertical<1

vs.layer contrast

Limitations of conventiona conventionall methods-

Recovery by conventional methods= Natural depletion +Water injection recovery =N1+N2 =N1+(Ni-N1)xEdispl.XEvol.

Ed=

Soi-Sorw

Evol<1

1-Swi

<1 ~60%

~0.4 to 1

Oil left in swept zones

Oil left in unswept zones

Enhanced Oil Recovery Methods

Enhanced Oil Recovery IMPROVEMENT OF VOLUMETRIC EFFICIENCY Evol

OIL VISCOSITY REDUCTION

INCREASE WATER VICOSITY

IMPROVEMENT OF DISPLACEMENT EFFICIENCY Ed

REDUCE INTERFACIAL TENSION

SURFACTANT

HEAVY OIL STEAM INJECTION IN-SITU COMBUSTION

INCREASE GRAVITY FORCES

GAS INJECTION MISCIBLE NEAR MISCIBLE HC,CO2,N2,AIR,…

OIL VAPORIZATION

IMMISCIBLE LEAN GAS INJECTION STEAM INJ.(LIGHT OIL)

POLYMER

Lean gas injection (HC,N2,CO2,AIR,..) Stable displacement

Production Mechanisms

Mechanism

Order of magnitude of recovery factor

I- Oil reservoirs Natural depletion only

5 to 20 %OOIP

ND+Water depletion

30 to 50 %OOIP

ND+WI+Enhanced oil recovery

50 - 65 %OOIP

II- Gas reservoirs Natural depletion

60 - 90 % OGIP

EOR contribution in the world oil production ESTIMATION* YEAR 2000

THERMAL

1.0 to 1.5 MMstb/d

CHEMICAL

0.3 to 0.7 MMstb/d

GAS INJECTION

3.5 to 4.5 MMstb/d

EOR PRODUCTION

5 to 7 MMstb/d(out of more than 70MMstb/d)

(*from 1995 data+personal extrapolation)

World Oil reserves estimates( P.R.Bauquis-2000-)

-Conventional reserves ( billion stb ) Initial Cumulative production Remaining to be produced

1800 to 2500 800 800 1000 to 1700

-Non conventional reserves (economically recoverable at year 2030 horizon)

Deep offshore(below 500m water depth) Ultra heavy oil(50/50 Orinoco and Athabasca) GasToLiquids conversion -Overall reserves

100 600 100

100 600 100

1800 to 2500

TENTATIVE ESTIMATE of EOR POTENTIAL

YEAR 2000 ROUGH WORLD RESERVE‘’GUESTI RESERVE‘’GUESTIMATE’’ MATE’’ CONVENTIONAL RESERVES *: RESERVES *: 1000 billion stb (for an initial oil in place of >3500billion stb) 1% recovery factor improvement~35 billion stb ! UNCONVENTIONAL RESERVES: RESERVES: Deep offshore:100 billion stb Heavy oil :600 billion stb *onshore+offshore( less than 300 meters water depth)

TENTATIVE ESTIMATE of EOR POTENTIAL

CASE of MATURE or AGEING OIL FIELDS (more than 20 years old and/or in declining phase)

-75% of the conventional reserves located in mature fields -70% of the world production from fields of >20years old,majority of them started their decline phase(generally increasing water-cut)

ENHANCED OIL RECOVERY

Heavy oils

qoi= High viscosity

a kakro(Swi+g) h

x (Pr -Pwf ) = PIx (Pr -Pwf ) oBo[Lnr e /r w +s-0.75] Low PI

Low or Uneconomic Uneconomical al oil rate


Thermal Flood

HEAVY OIL(°API<20-25)=HIGH VISCOSITY(10 to > 106 cpo) =LOW PI =LOW or VERY LOW RATE 

Methods:Increase reservoir temperature Steam Injection In-situ Combustion



Effect Reduction of oil viscosity due to heating effect

Heavy Oil : a mix of heterogeneous denomination Confusing heterogeneous denominations :

- Heavy Oil, Extra Heavy Oil, Oil Sands, Tar Sands, Bitumen, …. need  need

for a simple classification

4 Classes based mainly on downhole viscosity : A Class : Medium Heavy Oil









25°> d°API > 18° 100 cPo > > 10 cPo, mobile at mobile at reservoir conditions

B Class : Extra Heavy Oil

20°> d°API > 7° 10 000 cPo > > 100 cPo , mobile at reservoir conditions

C Class : Tar Sands and Bitumen

12°> d°API > 7° > 10 000 cPo, non mobile at reservoir conditions

D Class : Oil Shales Reservoir = Source Rock, no permeability Mining Extraction Extracti on only

Heavy Oil (excluding Oil Shales) : 3 Main Categories Heavy Oil Classification 10 000 000 Wabasca Athabasca

C Class : 1 000 000 ) Tar Sands & Bitumen o p C ( y t i s o c s i V e l o h n w o D

Canada

100 000

B Class : Extra Heavy Oil

Peace river Cold lake Upper & Lower Ugnu Cat canyon

10 000

Eljobo

Boscan Poso creek Yor ba lind a Fazenda Fazenda be lem Llancanelo Alto do rodrigues 2 Belridge KernLloyminster river

Orinoco 1 000

Mormora mare

100

Tia juana Midway Estreito Bressay Morichal Bati raman Mariner (H) Sarago mare Alto do rodrigues 1 Pilon Bechraji Duri Mount poso Rospomare Qarn alam Varadero Balol Bachaquero Emeraude Captain Mariner (M) Boca de Jaruco West sak

Grenade

A Class : Medium Heavy Oil

 Lacq

10 0,0

5, 0

10 , 0

15,0

API Density

20 , 0

Tempa

Dalia

Rosa

(11-23°API)



Shoonebeck

Sup. 2 5 ,0


Thermal Methods :





s t Steam Injection e Steam : Good Heat a Carrier T mo Oil Mobility Increases i Steam DistillationnProcess in Zone 1 : Light Oil Vapor j Condenses and Enriches Existing Oil Reduction on Sor Thanks to Solvent Slug e c Application : Max Depth = 1500t M (Heat Losses) i So > 50 % Thick Pay, High Ko n Cheap Steam


Thermal Methods Steam Injection Steam Injection

Producer

Steam

d e n s e d a m n e C o S t

Hot Water Zone Oil & Water

Schematic Representation of in Situ Combustion Process and the Various Zones as Formed in the Oil Reservoir


Thermal Methods Cyclic Steam Injection Process Scheme Steam injection

Soak period

Produced fluids

Viscosity Steam Steam

Viscous oil

Heat Heat Cond. water Viscous oil

Low oil Water


Thermal Methods Cyclic Steam Injection Producer

Producer

Heat

Heat

n e o z e d c t e e e f f f a a m e e t S o w l o f l l a io n o t i a a t t i v G r a

Cyclic Steam Stimulated Producers with Drainage Area Overlapped and Gravitational Effect in Place


Thermal Methods In Situ Combustion 

Application : Depth o

: Not to Shallow : Less than 5000 cp

So

: > 30 %

Reservoir

: Sandstone


Thermal Methods In Situ Combustion 

Oil is Ignited around Well Bore



Burning Front Sustained by Continuous Injection of Air



A Small Portion of the Oil is Burned



The Heat Generated Reduces Oil Viscosity  Produces Miscible Fluids  Increases Sweep Efficiency  Reduces Oil Saturation 



Continuous Air Injection Develops Efficient Gas Drive Mechanisms


Thermal Methods Air Injection Air Injection

Producer

Combustion front Burned rock

n e o z r o n e o z p . V a n d e n s C o

Oil bank

Schematic Representation of in Situ Combustion Process and the Various Zones as Formed in the Oil Reservoir

Air Injection

Mechanisms : Oil + Flue Gas 

Reservoir Pressure Maintenance / Repressurization



Gravity Stable Displacement



Oil Swelling



Miscibility - Flue Gas / Reservoir Oil

Air Injection Mechanisms FLUE GAS

Air + Oil + Water N2 + Oil

Oil Stripping

Hc Gas + Stripped Oil + N2

O2 + Oil

Oxydation

LTO

Co, Co2 + others

Temperature

Oil Vaporization

(Oil Composition

HTO

and Res. Temp.) WATER

STEAM

Co, Co2 + others

Air Injection 

Oxygene Oil Reactivity vs Reservoir Temperature



Possible Spontaneous Oil Ignition and Complete Comsumption



Two Classes of Oxidation Reactions : 1- Low Temperature Oxidation (LTO) : up to 250 / 250 / 300° C Polar Compounds : Alcohol, Ketone, Aldehyde, Ester CO + CO2 2- High Temperature Oxidation (HTO) : from 300 / 300 / 350° C

to 500 / 500 / 600° C Combustion of Coke CO2 

Between LTO and HTO : Oil Cracking ?

C

H

Air Injection Experimental Programme : Simulations  

Simulations with Therm (SSI) Reaction Stoichiometry for Combustion

1- C11+

23.54 O2

21.66 COX

11.91 H2o

Heat

2- PS4 2 PS4

8.39 O2

7.72 COX

4.25 H2o

Heat

3- PS3 3 PS3

4.35 O2

4 COX

2.2 H2o

Heat



Reaction Rates Based on Arrhenius Equation K = A exp (-E / (-E / RT)



Thermal Constants - Heat of Reaction - Rate Constant - Activation Energy

Model Therm Features Temperature, Composition computed for each cell at each time step 

Temperature Computation Includes : -



Heat from Heat from surro surroun undin ding g cells cells by CONVECTION Heat He at from from surro surroun undin ding g cells cells by CONDUCTION Heat He at from from surro surroun undin ding g cells cells by RADIATION Heatt from Hea from the the cel celll itsel itself f Heat of Reaction in the grid block (reaction r)

Composition Computation Includes : - Darcy Flow - Composition Changes in the grid block due to Chemical Reactions

Air Injection

% t n e t n o c 2

C ° . p m e T

O

600

20

400

10

Tres

Legend O2

Flue gas (N2 CO

flue gas

heavy ends

Thermal front (water oil vaporisation oxydation CO CO2 LTO (alcool, aldehyde, ester) some visbreaking CO2

HC)

Steam vaporised oil (heavy)

Oil

Vaporized oil fuel oil

Steam

Condensed oil fuel oil

Water

Oil rim Sorw Sorw

flue gas flue gas

flue gas

flue gas

flue gas

fuel oil

condensed water condensed water

"Heavy Oils" : Wordwide OiI In In Place Worlwide Oil in Place : # 4,600 Gb

Canada Venezuela USA CEI Mid.-East Africa Others

1683

36% 27% 14% 8.7%

Oil Shales (D) 700 Gb (15%)

Medium Heavy Oil (A) 360 Gb (8%)

1284

662

400

5.3%245 2%110 7%

272 Tar Sands & Bitumen (C) 1,940 Gb (42%)

Extra Heavy Oil (B) 1,600 Gb (35%)

"Heavy Oils" : Resources of 4000 to 5000 Gb (OIP) Potential Reserves depends on recovery factors

equivalent to 50-100% of worldwide conventional oil reserves 5 to 10 times (?) the ultra-deep offshore potential reserves mainly (80%) in extra heavy oil, tar sands and bitumens mainly (80%) in North and South America less than 1% produced or under active development

270

310

260

Venezuela

Canada

Saudi Arabia

Huge Untapped Resources in Orinoco and Athabasca 54,000 km2

45,000 km2 ALBERTA

Athabasca

Fort Mc Murray

Peace River

Cold Lake Edmonton Lloydminster Calgary

SINCOR OPCO

Cretaceous Oil Sands Cretaceous Heavy Oils

SURMONT SAGDPilot

Extra Heavy Oils

Tar Sands & Bitumen

(µ < 10,000 cPo)

(µ > 10,000 cPo)

Oil in place: 1,200 Gb

Oil in place: 1,300 Gb

(PDVSA estimates)

(EUB estimates)

The Orinoco Belt Deposits: a New Saudi Arabia? First exploration campaigns in the 1930’s One of the largest extra heavy crude oil deposits in the world Orinoco 54,000 km2 1,200 Bbls oil in place

Recoverable reserves • 100 Bbls • Est Estima imated ted pote potentia ntiall reserv reserves es of of around around 300 300 Bbls Bbls (post (post 202 2020) 0) • Ext Extra ra heavy heavy cru crude de oil oil (8 - 10° API), API), wit with h high high sulfur sulfur cont content ent • Sh Sha all llow ow sa sand nd re res ser erv voi oirs rs

Saudi Arabia conventional conventional oil reserves estimated around 260 Bbls (O&GJ)

Cold Production Scheme Electrical Submersible pump

55 0 m

m 0 0 2

1 400 m

SINCOR FIELD - Reservoir model parameters Parameters (fluvial) Permeability :

20 D

Kv/Kh:

0.1

Sgc: Cp

6.5 % 10 E-6psi-1

Viscosity @ Pbp

2000 cP

Skin

0

Constraints Maximum pump rate

2000 blpd

Water-cut max

95%

SAGD Process

SAGD Process

Bitumen is solid at reservoir conditions Preheating phase needed to establish hydraulic communication Steam injection and production of condensed water and mobile oil Horizontal well pair

Oil reservoir

Steam injection well

Steam flows to interface and condenses

Heated oil and condensate flow to well

Production well, oil and condensate are drained continuously

ENHANCED OIL RECOVERY


Surfactant - Polymer Injection



The Process is Conducted in Two Steps : Injection of the Surfactant Slug Injection of the Polymer Mobility Buffer



Surfactant Aim Lower Interfacial Tension between Oil and Water Displace Oil that cannot be Displaced by Water Alone



Polymer Aim : Provide Mobility Control for More Effective Piston - Like Displacement


Chemical Flood Polymers



Method Addition of Polymers to Water Being Injected This is Done in Conjunction with Surfactants Polymers : Organic Materials Soluble in Water



Effect Increase of Water Viscosity


Chemical Flooding Polymer Flooding

•

Polymer Reduces Water / Oil Mobility Ratio due to w M 1 Volumetric Sweep Efficiency Improves Higher Recovery at Breakthrough

•

Application : T < 100 °C : Medium to High K > 100 mD o < 100 cp

, Kw

Water Injection Sweep Efficiency Effect of Polymer Flooding

Water Flooding

Polymer Flooding


Chemical Methods Schematic View of Polymer Flood Injector

Producer

Fresh Water Water

Polymer solution

Fresh Water

Oil


WATER INJECTION + SURFACTANTS

OW

MICRO EMULSIONS, ALCOHOL, LPG PLUG

OW

= 0


Water Injection + Chemicals

Not Efficient

Difficult at High Temperature with High Salinity

In Carbonate Reservoirs

ENHANCED OIL RECOVERY PROCESSES

Gas Injection = a Promising Future for E.O.R.

Gas Injection:Obje Injection:Objectives ctives

 Analyse  Show

the traditional misgivings against Gas Injection

the decisive improvements in 3 domains :

Lean Gas Injection  Near Miscible Gas Injection  Air Injection 

Thanks Tha nks to : - R & D Ach Achiev ieveme ements nts - Gas Injection Active Project Review and Re-study


Optimum Technical Recovery

INJECTION EFFICIENCY

=

OIP before injection - OIP after injection OIP before injection

= Evolumetric x Emicroscopic

in swept zones (Ev) = Sorg

OIP left after injection

in unswept zones (1 - Ev) = Soi

Swept zones : EMIC =

Soi - Sorg Soi

EOR by Gas Injection - Volumetric and Microscopic Sweep Efficiencies Oil Producer

Gas Injector

Oil Producer

Oil Producer

Sorg

Soi


Nature of Gases and Injection Conditions

 Nature

:

Hydrocarbon (Lean, Rich, Enriched)  Non Hydrocarbon : CO2, N2, Air, Flue Gas 

 Injected

Gas / Rock Fluids Reactions :

Exchanges (Mass Transfert) = Important or Not  Thermal Effects or Not (O2 Presence) 

 Conditions

: Secondary or Tertiary Conditions

(Nb : Fractu Fractured red Reser Reservoirs voirs : Specif Specific ic Mechanis Mechanisms) ms)

HYDROCARBON GAS COMPOSITION Methane CH4 C1

Ethane C2H6 C2

Propane C3H8 C3

Butane C4H10 C4

LPG

Pentane ….. C5H12 ….. C5+ CONDENSATES

LEAN GAS: lean in intermediate components low liquid content(LPG+CONDENSATES) C >75% C +<25% 1 2

RICH GAS: rich in intermediate components fairly high liquid content(LPG+CONDENSATES)

60%
25%
OTHER POSSIBLE COMPONENTS: CO ,N ,H S


– Majority of IOR projects in the world:  

Water injection (for conventional oil) Steam injection (for heavy oil)

– Gas injection: traditional misgivings 

 

Poor sweep efficiency( g/o mobility ratio >>1) and unstable displacements High compression cost (vs. Water pumping) Gas availability (demanding gas market)

– Exception to this "Ostracism":    

Us = CO2 injection Canada = rich gas/Lpg injection Venezuela (Oriente), Iran ( Asmari Asmari), Libya (Intissar ) Algeria (Hassi-Messaoud)


Injected fluids:Gas Specificities( vs.Water)

 Exchanges

with Oil

Need for Equation Of State- Better /

? - Higher Mobility Ratio  Higher  Need

Sensitivity to Reservoir Heterogeneities

More Design Optimization



Enhanced Understanding of Mechanisms



Sophisticated Lab Experiments



Compositional Modelling



Reservoir Characterization


Benefits of Gas Injection

Gas/oil mobility ratio= Mg/o



Krg(Sorg) =

g

 o

x

>> 1

Kro(Soi)

Good Macroscopic Efficency if : -Gravity Stable Displacement -Possible Mobility Control by WAG(water alternating gas)

Tertiary Oil Recovery by Gas Injection

Thermodynamic conditions during oil displacement – Miscibility – Partial miscibility 

Vaporizing gas drive



Condensing gas drive

– Immiscibility

Reservoir conditions – Secondary – Tertiary

Miscibility Diagram for a Reservoir Oil Vs Injected Gas Composition and Pressure (At reservoir temperature) s a g n o i t c e j n i f o t n e t n o c s u l p e n a h t E

1

First contact miscibility

2

Vaporizing gas drive miscibility

3

Condensing gas drive miscibility

4

Immiscible fluids

1

3

4 2

Pressure (Log. P)


Gas injection-Two Domains :

1- Immiscible 1 Immiscible Lean Gas (Low Pressure) Gravity Drainage Dominant

2- Miscible 2 Miscible or Near Miscible Enriched Gas Lean Gas at High Pressure (Thermodynamic Exchanges Dominant)

Microscopic Oil Displacement by Water and Gas Miscible Gas Injection

Sorg Lean Gas Injection

Sorg (t1)

Sorg (t2)

Sorw

Sorg

Soi Water Injection

Pore Level Mechanisms - Microscope Efficiency 

Competition between viscous and capillary forces capillary number: Nc m E 1.0 , . f f e t n e m e c a l p 0.5 s i d c i p o c s o r c 0.0 i M





U


10-6


100

Competition between gravity and capillary forces Dombrowski Brownwell number: gk Nb 

Em

for Nb > 10-5

Miscibility Diagram for a Reservoir Oil Vs Injected Gas Composition and Pressure (At reservoir temperature) s a g n o i t c e j n i f o t n e t n o c s u l p e n a h t E

1

First contact miscibility

2

Vaporizing gas drive miscibility

3

Condensing gas drive miscibility

4

Immiscible fluids

1

3

4 2

Pressure (Log. P)

EOR by Gas Injection:MMP(Minimum Miscibility Pressure Graphical laboratory determination Slim tube experimen experiments(42ft ts(42ft lenght) Actual reservoir temperature and actual gas(fixed composition) 6 to 8 points increasing pressure

At 1 PV injected

100% >90%

At break through

y r e v o c e r

MMP

Pressure(fixed gas composition)

-

P1

P2

P3

P4

P5

P6

EOR by Gas Injection:MMR(Minimum Miscibility Richness Graphical laboratory determination Slim tube experimen experiments(42ft ts(42ft lenght) Actual reservoir temperature and actual gas(fixed pressure) 6 to 8 points increasing enrichment

100% >90%

MMR

y r e v o c e r

Enrichment (fixed pressure)

-

R1

R2

R3

R4 R5

R6


Benefits of Gas Injection

EFFICIENCY= Microscopic Sweep Efficency x Macroscopic Sweep Efficency Good Microscopic Efficency (Soi-Sorg)/Soi if :

-Changes in Kr Depending on Capillary Number Nc -Swelling -Phase Behaviour -Miscible or Near Miscible Displacements

Sorg lower than Sorw or Sorg= 0 ?


Main R & D Achievements

 Understanding 

E.O.S.



Laboratory

of Mechanisms

Compositional Simulation  Formulation  Upscaling  Resolution  Pre and Post Processing


R & D : Practical Effects

 Better

Predictions

 Possibility

to Perform Numerous Sensitivity Runs

Nature of Gas Richness of Gas Pressure Injection / Production Scheme Optimum Development : Mmp or Mmr ?  Efficiency

of Gravity Drainage in Tertiary Conditions


Which Optimum ? EFFICIENCIES % NPV E MIC

NPV

E VOL x E MIC

MMP MMR

GAS RICHNESS (at FIXED P) PRESSURE (GAS COMP. FIXED)

Gas Injection = a Promising Future for E.O.R. P = 3 5 00 p s i

P = 3 000 ps i

Unflooded So = Soi

Gas flooded zone Sorg 0% Soi - Sor Emic = = 100% Soi Evol = 60%

Gas flooded zone Sorg = 15%

Recovery = ecovery = 60% x 100% = 60%

Recovery = ecovery = 80% x 80% = 64%

Emic = 80% Evol = 80%

Optimum Technical Recovery

EMIC

If EMIC

Soi - Sorg Soi

1

 Example


1 at miscible conditions (Sorg = 0) < 1 at non miscible conditions (Sorg

EVOL x EMIC Maximum ?

: Case 1 : EMIC Case 2 : EMIC

1, EVOL 0.8, EVOL

0.6 0.8

Case 2 better than Case 1!

0)


LEAN GAS INJECTION GRAVITY DRAINAGE MECHANISM

Immiscible Lean Gas Injection

None or limited thermodynami thermodynamical cal exchanges at fairly low pressure Gravity drainage in the gas invaded zone may be very efficient Gravity drainage is a recovery process in which the gravity force is the main mechanism gravity forces > capillary forces h ogg > 2 og cos / r Gravity drainage must be efficient within an economical time scale remark:

ogg

>

owg

and

og<

ow

Immiscible Lean Gas Injection - Gravity Drainage

•

Driving force is due to the differences of densities between gas and oil - (more or less) ever present phenomenon- what ever is the injected gas:lean,ri gas:lean,rich,CO ch,CO2,N2,air,flue gas,…

Reservoir factors affecting the process: - high mobility to oil - fairly good permeability - high formation dip(say>6°)and large oil column or thick reservoir stratification on rock - lack of stratificati - fractured rock - high density contrasts - Preferably water-wet rock

Tertiary Oil Recovery by Gas Injection Immiscible gas injection 

Field examples of gravity drainage efficiency

Field

Sorw

Sorg

Weeks Islands (US)

22%

2%

+ 20% OOIP

Hawkins (US)

35%

12%

+ 20% OOIP

Mile Six Pool (Peru)

37%

19%

+ 17% OOIP

Recovery

Long Core Model Description

11

12 2

3

4

5

6 7

11

1

8 10

11 13

9

1- Injection pump 2- Solvents cells 3- Formation water cell 4- Thermo-regulated storage cell 5- Thermo-regulated type cell 6- ------- pressure valve 7- Atmospheric separator 8- Oil recovery device 9- Gasometer 10- Computer and data acquisition 11- Relative pressure sensors 12- Differential pressure -------13- Gas chromotography apparatus

Tertiary Oil Recovery from Waterflooded Reservoirs

h

Sorg S0 Oil saturation measurement

Initial conditions

Water flood

0

2

39

135

169

170

Oil saturation % PV

78%

26.5%

21.8%

21.2%

19.8%

Top = 5% Bottom = 45%

Oil recovey % OOIP

0

66%

72.3%

73.2

74.7%

Step Duration, days

Gas injection

Limiting Oil Saturations for Lab Experiments

LAB. SAMPLE h

Initial GOC

Centrifuge Gas invaded zone

GOC limit

Core displacement Sor1 Sor2

Field

So

Tertiary Gas Displacement:2 phases Water-Oil relperm 70 ) 60 V P 50 % ( y r e 40 v o c e r 30 l i O

Sim.

20

Lab. 10 0

0

0.2

0.4

0.6

PV INJ (water)

0.8

1

SECONRADY ASSOCIATED GAS INJECTION SECONDARY GAS DISPLACEMENT OIL/GAS REL.PERM.-SIMULATION OF EXPERIMENTAL RESULTS

P I O O % , Y R E V O C E R L I O

Relative Permeabilities : Three phases 

Relative permeability to the wetting (water) phase is only a function of the wetting phase phas e saturation.



Relative permeability to gas is only a function of gas saturation in most cases.



Relative permeability to oil is calculated from relative permeabilities in two phases systems. Krw=f(Sw only)

 So and Sg distribution

Krg=f(Sg only)

 So and Sw distribution

K ro at a given S o ,depends on how the 2 other fluids are distributed Example:

Kro(So=20%,Sw=30%,Sg=50%) # Kro(So=20%,Sw=40%,Sg=40%)

Tertiary Gas Displacement 60 p i w t 50 % p i o t 40 % y r e v 30 o c e R

20 10 PV Inj. (gas) 0 0

0.2

0 .4

Water prod. Sim. Water prod. Lab.

0 .6

0 .8

1.0

GOR Sim. GOR Lab.

1.2

1.4

Oil Sim. Oil Lab.

Tertiary Injection Simulations Vertical vs Horizontal Displacement 0.5 n o i t 0.4 a r u t a s 0.3 l i O

0.2 0.1 0 2

4

6

8

10

12

14

16

18

20

Cell number

Initial

Vertical 15 days

Horizontal 15 days

Tertiary Gas Injection Simulation Oil Saturation Profiles 0.6 n 0.5 o i t a r u 0.4 t a s l i O0.3

0.2 0.1 0 2

Initial

4

6

3 days

8

10

12

5 days

14

16 18 Cell number

10 days

20

15 days

IN-SITU SATURATION MONITORING GAMMA-RAY/X-RAY

TERTIARY GAS GRAVITY DRAINAGE Oil,gas,water production

Oil saturation evolution

TERTIARY LEAN GAS INJECTION EXAMPLE OF 3-D SIMULATION RESULTS ON OIL SATURATION CHANGES

End of waterflood

After 10 years of gas injection

e l a c s n o i t a r u t a s l i O


LEAN GAS INJECTION at HIGH PRESSURE ENRICHED GAS INJECTION MISCIBILITY or PSEUDO MISCIBILITY CONDITIONS

Vaporizing Gas - Drive HPGD 

Multiple Contact Miscibility



Lean (Separator) Gas (75 to 100% C1) = Continuous Co ntinuous Injection 60 to 100% HCPV (10-15 Years) (Prod Gas Re-injected)



C2-C6 Transfered from Oil (Light Oil ~ 40° Api) to Gas



Operating P = > 3000 / 3000 / 3500 psi



Projects -

Some 20 Projects Large Scale - Long Period Mainly Sec. Rec. Recovery > 50% OOIP Examples : Examples : - Hassi Messaoud - Abu-Dhabi

Condensing Gas Drive Miscibility (Enriched Gas Injection) 

Multiple Contact Miscibility (C2 plus transfered from Gas to Oil-Swelling- )



Slug Size

= 10 to 20% HCPV



Drive Gas HCPV

= Lean Gas (Continuous or WAG) = 40 to 60%



Operating P= 1500 to 3000 psi (for 30° Api Oil)



Projects = - Some 20 Identified 1960's and 1970's - Several Gravity Stable CGD in Pinnacle Reefs (Canada) - Secondary Projects Mainly (Oil Gravity = 30 to 50° Api) - Examples : Ra Rain inbo bow w (Al (Albe bert rta) a) Intisar (Libya) - Estimated Incremental Rec : + 15 to 25% OOIP

Miscible Slug Process (LPG Injection) 

First Contact Miscibility



Slu Sl ug Siz Size e = 5 to 10 10% % HC HCPV



Drive Gas = - Lean Gas (Continuous or WAG) : 50 to 60%HCPV - Flue Gas



Some Drawbacks



Oper Op erat atin ing g Pr Pres essu sure re = 12 1200 00 ps psii (m (min inim imum um))



Projects = - 50 Projects (1950's and 1960's)

= LPG Expansive Possible Solvent Dilution

- Oil Gravity = 30 to 50° Api - Recove Recovery ry = + 10 to 30% OOI OOIP P (abov (above e W.F) - Ratios = 0.5 to 1.5 Stb / Rb LPG - Examples = Wizard Lake = 84% OOIP

Gas Injection = a Promising Future for E.O.R. The Miscible Solvent Slug Method Injector

Chase H2O or Gas

Producer

Solvent Slug

Reservoir Oil

Gas Injection = a Promising Future for E.O.R. WAG(Water-Alternating-Gas)Displacement WAG(Water-Alternatin g-Gas)Displacement Process Injector

Producer

WAG Cycle

Water

Miscible Gas (Solvent)

Reservoir Oil


Methodology



Gas Availability in the Vicinity of the Oil Field



Screening Study Using Ratios for Pre- Feasibility Study



Laboratory Experiments on Actual Rocks / Fluids



Numerical Simulations with Compositional Model : 1D, 2D, 3D



Pre-project Studies : Surface and Well Aspects, Capex, Opex, Economics



Screening Study of Non Hydrocarbon Gases



Pilot or Phase 1 ?



History Matching to Validate the Model. Adjustments.


Some Ratios for Screening Studies

 Injection 

Rate :

5 to 7 % HCPV / Year



Type :

- Continuous for Lean Gas - Slug for Rich Gas - WAG

 Additional 

Production

+ 8 to + 15 % OOIP above Water Injection Recovery (for 10 - 15 Years Project Duration)


Selection Criteria



Lean Gas Injection (Gravity drainage)



Fairly Light Oil (> 30° Api) Good permeability Thin formation : dip + hc column or Thick formation

Rich / Enriched Gas (Near miscible cond.)



Air Injection into Light Oil (Add. thermal effects)

Most reservoirs with light oil (> 30° api) - See above + Minimum Reservoir Temperature (Spontaneous Ignition)

HC GAS INJECTION:COMPOSITIONS AND PRESSURES

C1~100% Methane

COMPOSITIONS C1>75-80% 50-60%
C3 /C4 LPG

GAS RICHNESS PRESSURES(in the reservoir) Pfrac > Pwinj

>

‘MMP’

CGD

LPG

Order of magn. 1200

(psi)

CO2

Pres

>

VGD

1200/1500 1500/3000 3000/3500

Pwf

N2 >4000/4500


AIR INJECTION INTO LIGHT OIL RESERVOIRS

AIR: GAS

79%N2,21%O2 (mole)

-AVAILABLE (at atmospheric pressure)

-FREE

Air Injection Mechanisms FLUE GAS

Air + Oil + Water N2 + Oil

Oil Stripping

Hc Gas + Stripped Oil + N2

O2 + Oil

Oxydation

LTO

Co, Co2 + others

Temperature

Oil Vaporization

(Oil Composition

HTO

and Res. Temp.) WATER

STEAM

Co, Co2 + others


Air Injection into Light Oil Reservoirs

Mechanisms

Flue-gas generated in-situ



Reservoir Pressure Maintenance / Repressurization



Gravity Stable Displacement



Oil Swelling



Miscibility - Flue Gas / Reservoir Oil


Other gases to be considered for injection: -N2 -CO2 -Flue gas -Impoverished Air (90 to 95% N 2) -Mixtures: N2+hydrocarbon gas CO2+hydrocarbon gas Need :Specific sophisticated experimental studies Specific EOS (equati (equation on of state) to predict exchanges Numerical simulation of lab results Field pilot? Extension?

d e e n y t i v i t a e r C


What ever is the INJECTION GAS COMPOSITION , the in-situ WORKING or DRIVING GAS has has different composition ,resulting from the injected gas/resident oil exchanges

Gas Injection = a Promising Future for E.O.R. RECOVERY MECHANISMS Pressure maintenance (Qginj Bginj= QoBo+ QwpBwp+ QfgBfg) Gravity drainage:exists what ever is the gas but more or less efficient vs. og / og Formation dip or thickness Permeability and vertical barriers

Miscibility or pseudo-miscibility(

og =0

or low) :

at high pressure for lean gas at lower pressure for enriched gas

Thermal effects vs.O2 presence

Gas Injection = a Promising Future for E.O.R THERMAL AIR INJECTION

NON THERMAL

MISCIBLE HEAVY OIL (DRY-WET)

Miscible Slug Process

NON MISCIBLE

LIGHT OIL

Enriched CGD Slug

Lean CO2 VGD Continuous

Lean gas

N2

N2 Immisc. CO2

Flue gas


Gas Injection: Some Conclusions

1- Traditional 1 Traditional Misgivings to be Reconsidered 2- Decisive Improvements during the Last 3 Decades in 3 Domains = Lean Gas Injection  Near Miscible Gas Injection  Air Injection into Light Oil Reservoirs 

3- Gas 3 Gas Injection Project = More Demanding More Design Optimization


Conclusions (Cont’d)

4- Ability 4 Ability to Master a Gas Injection Project Past Field Experience Ability to Conduct Simultaneously :    

Fundamental Approach Experimental Approach Numerical Approach Practical Approach

5- Sophisticated 5 Sophisticated Lab Experiments + Detailed Reservoir Description = Crucial Importance 6- Expected 6 Expected Additional Recovery = + 8 to + 15 % OOIP above Conventional Recovery(10 to 15 years project) 7- For 7 For Ageing Field = Only Process ?

ENHANCED OIL RECOVERY PROCESSES

SOME CONCLUSIONS


Oil Recovery Improvement

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Conventional Methods

• • • 

Initiate Unconventional Methods = How ? When ?

• • • 

Reservoir Characterization (Hydraulics Units) Infill Drilling Well Monitoring

Microscopic Efficiency Macroscopic Efficiency Reservoir Management

Combination

Sor

Tertiary Process Selection Criteria

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Reservoir characteristics and status

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Ability to master a process

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Injected fluids: – Availability – Cost – Suitability (environment, safety)

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Process efficiency: – Additional reserves – Additional rate

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Economics: – Capex, Opex – Barrel price

A HYDROCARBON RESERVOIR IS INVISIBLE

Extrait d'un dessin de Sempé

Copyright © Charillon – Paris

RESERVOIR ENGINEERING DYNAMIC ASPECTS- PRODUCTION -

WELL DRILLING PERTURBATION OF THE GEOLOGICAL EQUILIBRIUM

A FASCINATING DIALOGUE BETWEEN THE SLOWNESS OF THE EARTH AND EARTH AND THE IMPATIENCE OF THE MAN STARTS MAN STARTS

RESERVOIR ENGINEERING ROLE

PREDICT FUTURE RESERVOIR PERFORMAN PERFORMANCES CES FOR SEVERAL PERTURBATI PERTURBATIONS,to ONS,to RECOMMAND THE OPTIMUM DEVELOPMENT SCENARIO

PREDICTING means QUANTIFYING QUANTIFYING means FORMULAE to express PHYSICAL MECHANISMS PHYSICAL MECHANISMS to be UNDERSTOOD at MICRO and MACROSCOPIC SCALES

EOR and R& D (1) STUDY OBJECTIVES:FI OBJECTIVES:FIELD ELD APPLICATION MANY EOR FAILURES CAN BE EXPLAINED BY:

-insufficient reservoir characterization -insufficient understanding of conventional behaviour -reactive reactive-instead -instead of proactive-attitude proactive-attitude -insufficient-or nonenone-cooperation/synergy cooperation/synergy between the different approaches: -fundamental -experimental -numerical -practical

EOR and R& D (2) 2 CURRENTS MUST FERTILIZE THE R&D in EOR PROJECTS ONE ASCENDING ASCENDING from from FUNDAMENTAL to FIELD APPLICATION ONE DESCENDING DESCENDING from from FIELD RESULTS toFUNDAMENTAL FIELD APPLICATION PILOT or PHASE 1 PHASE 1

NUMERICAL(-1D-2D-3D)-

EXPERIMENTAL

FUNDAMENTAL

EXPERIMENTAL/ FUNDAMENTAL

MODEL VALIDATION

FIELD RESULTS

NUMERICAL HISTORY MATCHING ADJUSMENTS

EOR and R& D (3)

FUNDAMENTAL ASPECT-TO UNDERSTAND , QUANTIFY AND PREDICT-, IS A NECESSARY and CRUCIAL PART OF THE WAY TO FIELD APPLICATION SHOULD NOT BE OPPOSED TO APPLIED R&D UNIVERSITIE S and SPECIALISED INSTITUTES CAN BE UNIVERSITIES (MUST BE) ASSOCIATED HYDROCARBON HYDROCARB ON RESERVOIR:UNI RESERVOIR:UNIQUE QUE NATURAL SYSTEM -TO EXERT PEOPLE CREATIVITY

-TO INCREASE SCIENTIFIC and INDUSTRIAL CULTURE

Production Mechanism

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