4.0 Measurement of Natural Gas
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4.0 GAS FLOW MEASUREMENT THE ORIFICE METER -PRINCIPLES AND OPRATIONS -ADVANTAGES AND LIMITATIONS -MEASUREMENTS -CALCULATION OF GAS VOLUMES -ORIFICE CONSTANTS -ACCURACY OF MEASUREMENTS OBJECTIVES At the end of this topic, the student should be able to Describe the principles of operation of the orifice meter. Calculate gas flow rates using data collated from an orifice meter. Discuss the factors which affect the operations of the orifice meter
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4.0 Measurement of Natural Gas
Introduction The volume of gas is the fundamental basis for settlement in most gas-sales gas-sales transactions. transactions. Payments for royalties and taxes are usually based on measured volumes. Gas, being a vapor, is not subject to conventional methods of storage in large quantities. Therefore, it must be measured instantaneously as it flows through a pipeline. A fluid flowing through a line can be measured by placing a constriction in the line to cause the pressure of the flowing fluid to drop as it passes the constriction. This pressure drop is called differential pressure. A direct relationship exists between the rate of flow and the amount of this pressure drop or differential.
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There are several measuring devices, however the selection of the measurement method to be used should be made only after careful analysis of several factors, including the following: 1. 2. 3. 4. 5. 6. 7. 8. 9.
Accuracy desired Expected useful life of the device Range of flow and temperature Maintenance requirements Power availability, if required Cost of operation Initial cost Availability of parts Acceptability by others involved
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The Orifice Meter
The typical orifice meter consists of a thin flat stainless steel plate about 3/16 in. thickness, with an accurately machined circular hole that is centered in a pair of flanges or other plate-holding device in a straight section of smooth pipe. Pressure tap connections are provided on the upstream and downstream sides of the plate so that the pressure drop or differential pressure may be measured. This pressure difference and the absolute pressure in the line at a specified “tap” location are recorded continuously and are later translated into rate of flow. Figure 1 illustrates the flow pattern through an orifice, how the resulting pressure differential across the orifice is measured, and the change in static pressure that occurs.
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Figure 1 also shows that two arrangements of the taps are commonly comm only used: (a) flange taps (b) pipe taps. taps . For meters using “flange taps” taps ” the center of the upstream pressure tap is placed one inch from the upstream face of the orifice plate, whereas the center of the downstream pressure tap is placed one inch from the downstream face of the orifice plate. However, for meters using “pipe taps” taps ” the upstream pressure tap is placed two and one-half times the actual inside pipe diameter from the upstream face f ace of the orifice plate and the downstream pressure tap is placed eight times the actual inside pipe diameter from the downstream face of the orifice plate. Pipe tap orifice meters are more accurate if the system is subjected to pressure pulsations. On the other hand, flange tap orifices are easier to install and by extension change.
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Primary Element A complete orifice meter is generally considered to be composed of two major elements. The first is the differential pressure-producing device called the primary element and is composed of the following: 1.
The meter tube - a length of special pipe through which the gas flows.
2.
The orifice plate holding and positioning device - an orifice flange or an orifice fitting installed as an integral part of the meter tube to hold the orifice plate in a position perpendicular and concentric to the flow of gas.
3.
The orifice plate - a flat circular plate with a centrally bored, sharp-edged orifice machined to an exact, predetermined dimension that forms a calibrated restriction to the flow of gas through the meter tube. It is also the source of the pressure differential.
4.
Pressure taps - precisely located holes through the pipe walls or orifice plate holder. These allow for the measuring of the gas pressure on each side of the orifice plate. Straightening vanes - a device that may be inserted in the upstream section of the meter tube to reduce swirling in the gas stream.
5.
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Secondary Element The secondary element is called the differential gauge and is the device for measuring the pressures. It is connected with tubing to the upstream and downstream pressure taps of the primary element. One part of the device indicates or records the difference between the pressures on each side s ide of the orifice plate, and the other part indicates or records one of these pressures. Gauges which record differential and static pressure, using circular charts with printed scales, are extensively used. They provide a permanent perm anent record.
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4.3 Advantages and Limitations of the Orifice Meter Advantages of Orifice Meter The advantages of using an orifice meter are as follows: * *
Accuracy Ruggedness due to no moving components Available in wide range of sizes Suitable for most gases & liquids Widely established and accepted Simplicity Availability of standard tables of meter factors need not be Flow Calibrated Calibrated Orifice need
Limitations of Orifice Meter The limitations of using an orifice meter are as follows: Accuracy Deteriorates with Wear & Damage and Flow Profile Accuracy Affected by Density and High Unrecoverable Pressure Drop Maintenance is Required Time-Consum ing & Expensive Installation is Time-Consuming
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4.4 Measurement Calculations Basic Flow Equation The relationship of rate of flow with the flowing or static pressure of the gas, as well as the differential pressure across the orifice is expressed as: Qh =
C1
h w Pf
------ - ---- ---- - -
(1)
where: Qh = rate of gas flow, cu ft/hr at contract base conditions C1 = orifice flow constant, corrected for operating and base conditions hw = differential differential pressure pressure across orifice, in. of water water Pf = static pressure, psia The product of the square roots of the differential pressure and absolute static pressure, h P , is commonly referred to as the pressure extension. w
f
The orifice flow constant C 1 may be defined as the rate of flow in cubic feet per hour at contract base conditions when the pressure extension equals unity.
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The orifice flow constant, C 1, is obtained by multiplying a basic orifice flow factor, F b, by various correcting factors that are determined by the operating conditions, contract requirements, and physical nature of the installation, as follows: C1 = Fb*Fpb*Ftb*Fg*Ftf *F *Fr *Y* *Y* Fpv*Fm*Fl*Fa
(2)
where: Fb = basic orifice flow factor, cu ft/hr Fpb = contract pressure base Ftb = contract temperature base Fg = specific gravity factor Ftf = flowing temperature factor Fr = Reynolds number (viscosity) factor Y = expansion factor Y1 based on upstream static pressure Y2 based on the downstream static pressures Ym’ based on a mean of the upstream and downstream static pressures Fpv = supercompressibility supercompress ibility factor Fm = manometer factor for mercury meter Fl = gauge location factor Fa = orifice plate expansion factor.
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The derivation of some of these factors is very complex. Actually, several factors can be determined only by very extensive tests and experimentation, from which tables of data have been accumulated so that a value may be obtained. Tables for these factors are available and should be referred to for actual values when making mak ing calculations. There are two sets of tables one for flange taps one for pipe taps.
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Estimation of C 1 Variables (a) Fb - Basic Orifice Flow Factor The basic orifice factor, F b, is obtained obtained from the attached tables for both flange taps and pipe taps. (b) Fpb - Contract Pressure Base =
14.73 Pb
(3)
where Pb = the required contract pressure base in psia Tb
(c) Ftb - Contract Temperature Base = 520
(4)
where Tb = the absolute temperature base specified by the contract, ( oF + 460). (d) Fg - Specific Gravity Factor = Factor =
1.0
(5)
g
where g = the specific gravity of the th e flowing gas. (e) Ftf - Flowing Temperature Factor =
520 Tf
(6)
where Tf = actual flowing temperature in degrees absolute, ( oF + 460). of 33 18
(f) Fr - Reynolds Number (Viscosity) Factor Fr = where b
1
=
b h w p f
(7)
f( β) d
and
where: d = D =
=
D
(8)
orifice ID pipe ID
For pipe taps, it is recommended that should fall within the range 0.20 to 0.67. “b” values for Reynolds Number Factor, F r , is obtained from the the attached attached tables for both flange taps taps and pipe taps.
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(g) Y - Expansion Factor If the absolute static pressure is taken at the upstream differential pressure tap, the value of the expansion factor, Y1, is obtained o btained from the attached tables for both flange taps and pipe taps. If the absolute static pressure is taken at the downstream differential pressure tap, the value of the expansion factor, Y2, is obtained o btained from the attached tables for both flange taps and pipe taps.
(h) Fpv - Supercompressibility Factor Fpv = where
Zb Z
(4.9)
Zb = gas deviation factor for contract base conditions. Z = gas deviation deviation factor factor for operating conditions.
If contract base conditions are standard conditions, Z b = 1. A definite procedure for the calculation of coefficients coefficients can be established to ensure that all such coefficients will be calculated in the same manner and that, starting with the same basic data, any two persons using this procedure will arrive at identical answers for each coefficient.
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Most natural gas streams contain water, and some of these streams streams are saturated saturated with water. Errors in gas measurement may result if the presence of water vapor in the gas is not properly properl y accounted for. Measurement error will not usually result if a fielddetermined specific gravity gravity is used in the gas volume computation and if this gravity was determined on the wet sample. However, when a specific gravity is calculated from an analysis of gas, the analysis is customarily reported on a dry basis and must be converted to a wet basis before a wet specific gravity can be obtained. Subsequently, once the water content is determined, the volume of water present in the wet gas stream may be subtracted to arrive at the dry gas volume. The errors in volume measurement is usually insignificant at pressures above 200 psig, but at low pressures the errors can be substantial.
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EXAMPLE 4.1 Calculate the gas flow rate q in MMscf/D, for the following conditions: Pipe ID Pcontract Orifice ID hw Tf Pf Tcontract Patm g
= = = = = = = = =
8.071 in. 15.4 psia 4.00 in. 64 in. 800F 625 psig 650F 14.5 psia 0.72
Additional Information a. Based on flange taps and the t he static pressure upstream. b. Assume Fm, Fl and Fa = 1
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Accuracy of Measurements Several factors can affect the accuracy of measurement obtainable with the differential-type flow instruments. The more common factors can be categorized as sources of (i) constant errors and errors and (ii) variable errors. errors. In most cases, corrections can easily be made mechanically or through adequate maintenance. The constant errors include the following: 1. Incorrect information as to the bore of the orifice plate. 2. Contour of the orifice plate (convex or concave). 3. Dullness of the orifice edge. 4. Thickness of the orifice edge 5. Eccentricity of the orifice bore in relation to the pipe bore 6. Incorrect information as to the pipe bore 7. Excessive recess between the end of pipe and the face of orifice plate 8. Excessive pipe roughness.
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The variable errors include the following: 1. Flow disturbances caused by insufficient length of meter tube or irregularities in the pipe e.g. from welding 2. Incorrect locations of differential taps in relation to the orifice plate 3. Pulsating flow 4. Progressive buildup of solids, dirt, and sediment on the upstream side of the orifice plate 5. Accummulation of liquid in in the bottom of a horizontal run or Liquids in the piping or meter body 6. Changes in operating conditions from those used in the coefficient calculations (i.e., specific gravity, atmospheric pressure, temperature) 7. Corrosion or deposits in the meter tube 8. Formation of hydrates in meter piping or body 9. Leakage around the orifice plate fittings 10. Wrong range on chart 11. Incorrect time for rotation of chart 12. Excessive friction between pen and chart
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Processing Meter Charts Charts should first pass through the hands of the operating location staff and, when necessary, a measurement specialist who will note on the back ba ck of the chart the gravity, temperature, supercompressibility factor, and any other information affecting the volume, and will verify the field data imprinted on the back of the chart. On the basis of past history or familiarity with conditions at the meter, the measurement specialist will estimate volumes when the meter was inoperative because of a stopped clock, a pen not marking, or freezing. fre ezing. Many sales contracts include provisions to the effect that if for any reason, meters are out of service so that the amount of gas cannot be determined from chart computations, the gas delivered during the period in which the meter was inoperative can be determined by one of several methods including the following: following: 1.
By correcting the error with mathematical calculations calculations if such error is ascertainable by calibration or test. Such errors include a wrong-sized orifice plate, a plate placed in backwards, a differential pen not zeroed, a static pen not calibrated, and so forth.
2.
By estimating estimating the volume volume by comparison comparison with deliveries during a period when the meter was operating properly.
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Orifice Plate Orifice plates should be inspected to ascertain that 1. 2. 3. 4. 5.
the upstream edge is sharp the face of the plate is flat the face of the plate is smooth and without pits the correct size of the bore, measured by micrometer, is stamped on the plate no dirt or ice has collected against the orifice plate.
Orifice Fittings If the meter tube is equipped with an orifice fitting, f itting, the following observations and operations should be made 1. 2. 3. 4.
Packed glands must be kept tight The moving parts must be lubricated The plate carrier should be removed for inspection on a routine schedule Moving parts should be actuated to prevent them from becoming frozen
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Measurement Problems Freezing Hydrate formation at the orifice, in meter piping, or in the meter chamber may occur when the temperature of the wet gas being measured m easured falls below the hydrate temperature. The chart, on which recordings have been made while the meter was partially frozen, should have a full f ull explanation written on the face of the chart and estimated static and differential pressures lines should be drawn in. Preventive measures include – include – 1. 2. 3. 4. 5. 6.
elimination of piping leaks installation of line heaters installation of a heated meter house dehydration of gas use of inhibitors enlargement of the meter piping and valves to ½ inch maximum
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Pulsating Flow Pulsations in a pipeline originating from a reciprocating system or some other similar source consist of sudden changes in both velocity and pressure of the flowing fluid. The most common sources of pulsation involved in gas measurement are 1. 2. 3.
reciprocating compressors. compress ors. irregular movement of quantities of water or oil condensate in the line intermitters on wells.
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In order to obtain reliable measurements, it is necessary to suppress the pulsations. In general, general, the following methods are valuable in diminishing pulsation and its effect on orifice flow measurement: 1.
2.
3.
Locating the meter tube tube in a more favorable favorable location with regard to the source of pulsation, such as increasing the distance from the source of pulsation. Inserting capacity restriction, or specially designed filters in the line between the source of pulsation and the meter tube in order to reduce the amplitude of the pulsation. Operating at differentials as high as is practicable by replacing the orifice plate in use with an orifice orif ice plate having smaller orifice
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Slugging The conditions commonly called slugging refer to a liquid (water, oil, or condensate) accumulation in a gas line. In low-pressure lines, the liquid will gather at a low place in the line and restrict the passage of gas until enough gas pressure has accumulated to blow through the liquid. In a high-pressure system, the liquid will sweep up to and through the orifice. Both conditions produce erratic recordings and inaccurate measurement of an un-determinable extent.
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Sour Gas Freezing and corrosion are two frequent problems in measuring gas containing hydrogen sulfide. Corrosion in a closed line free of air and water is negligible, and most meter corrosion is due to hydrogen sulfide in the surrounding atmosphere. Possible remedies include the following changes in equipment: 1. Static spring: 316 stainless steel; is generally satisfactory. 2. Differential pen shaft: Teflon bearings that are unaffected by hydrogen sulfide are used. Lubrication with a silicone lubricant is helpful. 3. Pen: Self-feeding pens give better service and are more closely sealed against the atmosphere. 4. Clocks: Vapour-proof clocks are essential. The rubber seal should be coated with varnish. The winding stem and chart hub stem should be coated with grease. 5. Seal Pots: Seal pots are for protection of mercury mercur y in mercury-type mercur y-type meters. Some recommended sealing fluids are ethylene glycol or glycol-base antifreeze compound with 40 percent water. An inhibitor of 4 ml of 25% formaldehyde per gallon may be added. The orifice factor must be corrected when sealing fluids are used. Natural Gas Liquid Measurement of 33 31
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