1、Manual of PetroleumMeasurement StandardsChapter 20Allocation MeasurementSection 1Allocation MeasurementFIRST EDITION, SEPTEMBER 1993REAFFIRMED, SEPTEMBER 2011Manual of PetroleumMeasurement StandardsChapter 20Allocation MesurementSection 1Allocation MeasurementMeasurement CoordinationFIRST EDITION, S
2、EPTEMBER 1993REAFFIRMED, SEPTEMBER 2011SPECIAL NOTES1. API PUBLICATIONS NECESSARILY ADDRESS PROBLEMS OF A GENERALNATURE. WITH RESPECT TO PARTICULAR CIRCUMSTANCES, LOCAL, STATE,AND FEDERAL LAWS AND REGULATIONS SHOULD BE REVIEWED.2. API IS NOT UNDERTAKING TO MEET THE DUTIES OF EMPLOYERS, MANU FACTURER
3、S, OR SUPPLIERS TO WARN AND PROPERLY TRAIN AND EQUIPTHEIR EMPLOYEES, AND OTHERS EXPOSED, CONCERNING HEALTH ANDSAFETY RISKS AND PRECAUTIONS, NOR UNDERTAKING THEIR OBLIGATIONSUNDER LOCAL, STATE OR FEDERAL LAWS.3. INFORMATION CONCERNING SAFETY AND HEALTH RISKS AND PROPERPRECAUTIONS WITH RESPECT TO PART
4、ICULAR MATERIALS AND CONDI TIONS SHOULD BE OBTAINED FROM THE EMPLOYER, THE MANUFACTUREROR SUPPLIER OF THAT MATERIAL, OR THE MATERIAL SAFETY DATA SHEET.4. NOTHING CONTAINED IN ANY API PUBLICATION IS TO BE CONSTRUED ASGRANTING ANY RIGHT, BY IMPLICATION OR OTHERWISE, FOR THE MANU FACTURE, SALE OR USE O
5、F ANY METHOD, APPARATUS, OR PRODUCTCOVERED BY LETTERS PATENT. NEITHER SHOULD ANYTHING CONTAINEDIN THE PUBLICATION BE CONSTRUED AS INSURING ANYONE AGAINSTLIABILITY FOR INFRINGEMENT OF LETTERS PATENT.5. GENERALLY, API STANDARDS ARE REVIEWED AND REVISED, REAF FIRMED OR WITHDRAWN AT LEAST EVERY FIVE YEA
6、RS. SOMETIMES A ONETIME EXTENSION OF UP TO TWO YEARS WILL BE ADDED TO THIS REVIEWCYCLE. THIS PUBLICATION WILL NO LONGER BE IN EFFECT FIVE YEARSAFTER ITS PUBLICATION DATE AS AN OPERATIVE API STANDARD OR, WHEREAN EXTENSION HAS BEEN GRANTED, UPON REPUBLICATION. STATUS OF THEPUBLICATION CAN BE ASCERTAIN
7、ED FROM THE API PUBLICATIONS DEPART MENT TELEPHONE (202) 682-8000. A CATALOG OF API PUBLICATIONS ANDMATERIALS IS PUBLISHED ANNUALLY AND UPDATED QUARTERLY BY API,1220 L STREET N.W., WASHINGTON, D.C. 20005.Copyright 1993 American Petroleum InstituteFOREWORDThe Allocation Measurement Standard, API Manu
8、al ofPetroleum Measurement Stan dards, Chapter 20.1, was developed in response to an indicated desire by federal and stateregulatory agencies to reference API measurement standards. In 1986 various regulatoryagencies began requiring the petroleum industry to use the API Manual of PetroleumMeasuremen
9、t Standards for allocation measurement on federal and state leased lands. Theedition of the manual in place then was written specifically for custody transfer mea surement, which was inappropriate for allocation measurement. Although the petroleumindustry does a substantial amount of allocation meas
10、urement, the industry was beingrequired to use a standard that did not apply.The API Committee on Petroleum Measurement responded in the spring of 1987 bycommissioning a task group to survey the industry and determine if an allocation standardwas necessary. After determining that the need did actual
11、ly exist, an API working groupwas commissioned in the fall of 1987 to develop the scope and the field of application forsuch a standard.A second survey in the fall of 1987 was conducted to verify the types ofequipment used,the typical design of measurement facilities, and the typical operating proce
12、dures used forallocation measurement. This document, Chapter 20.1 of the API Manual of PetroleumMeasurement Standards, is the result of that industry survey and the efforts of the workinggroup.API publications may be used by anyone desiring to do so. Every effort has been madeby the Institute to ass
13、ure the accuracy and reliability of the data contained in them; how ever, the Institute makes no representation, warranty, or guarantee in connection with thispublication and hereby expressly disclaims any liability or responsibility for loss or damageresulting from its use or for the violation for
14、any federal, state, or municipal regulation withwhich this publication may conflict.Suggested revisions are invited and should be submitted to Measurement Coordination,Industry Services Department, American Petroleum Institute, 1220 L Street, Northwest,Washington, D.C. 20005.iiiCONTENTSPageSECTION I
15、-ALLOCATION MEASUREMENT1.1 Introduction 11.2 Scope 21.3 Terms 21.3.1 Definitions 21.3.2 Abbreviations 31.4 Referenced Publications 31.5 Liquid Quantity Measurement 51.5.1 General Design Considerations 51.5.2 Measurement Equipment Considerations 51.6 Liquid Sampling Procedures 71.6.1 Spot Sampling Sy
16、stems 71.6.2 Automatic Sampling Systems 91.7 Liquid Quality Measurement 91.7.1 Introduction 91.7.2 WaterCutAnalyzers 91.7.3 Tank Gauging Methods 141.7.4 Shrinkage Factor 151.8 Liquid Proving and Calibration Techniques 191.8.1 Proving a Master Meter 191.8.2 On-Site Proving ofAllocation Meters 201.8.3
17、 Off-Site (Transfer) Proving ofAllocation Meters 241.9 Liquid Calculation Procedures 251.9.1 Introduction 251.9.2 Shrinkage Factor 261.9.3 Sediment and Water (S; (1 - S a non dimensional value.g. CTLo,m is the volume correction factor for the effects of temperature on crude oil atmetering conditions
18、.h. CTLo,s is the volume correction factor for the effects of temperature on crude oil atstandard conditions.i. CTLostis the volume correction factor for the effects of temperature on crude oil atstock tank conditions.j. CTLwis the volume correction factor for the effects of temperature on produced
19、water;the ratio ofproduced water density at meter temperature to base temperature (see AppendixA for method of computation).k. CTLw,m is the volume correction factor for the effects of temperature on producedwater at metering conditions.1. CTLw,s is the volume correction factor for the effects of te
20、mperature on produced waterat standard conditions.m. CTS is the volume correction factor for the effects of temperature on steel.n. De,m is the density of crude oil/water emulsion at metering conditions.o. gpm refers to gallons per minute.p. GPM refers to gallons of hydrocarbon liquid per mef (1000
21、standard cubic feet) ofnatural gas.q. Me is the mass ofcrude oil/water emulsion as indicated on the flowmeter.r. MCF is one thousand cubic feet of gas.s. MF is the meter factor of the flow meter; a non-dimensional value that corrects thequantity as indicated on a meter to the actual metered volume.1
22、. SF is the shrinkage correction factor (see 1.7.4.4).u. Vostis the volume of crude oil corrected to stock tank conditions.v. Vw,st is the volume of produced water corrected to stock tank conditions.w. Xwmis the volume fraction of water cut in the crude oil/water mixture at meteringconditions.x. Xw,
23、s is the volume fraction of water cut in the crude oil/water mixture at standardconditions.y. Xw,st is the volume fraction of water cut in the crude oil/water mixture as measured bystatic methods of sampling under stock tank conditions.1.4 Referenced PublicationsThe following standards, codes, and s
24、pecifications are cited in this standard:A.G.A.I/GPA2Code 101-43 Standard Compression and Charcoal Test for Determining NaturalGasoline ofNatural GasReport No.7 Measurement ofGas by Turbine Meters1American Gas Association, 1515 Wilson Boulevard, Arlington, Virginia 22209.2 Gas Processors Association
25、, 6526 East 60th Street, Tulsa, Oklahoma 74145.34 CHAPTER 2o-ALLOCATION MEASUREMENT, SECTION 1-ALLOCATION MEASUREMENTAPIRP 12Rl Recommended Practice for Setting, Connecting, Maintenance, andOperation ofLease TanksStd 2545 Method ofGauging Petroleum and Petroleum ProductsStd 2550 Measurement and Cali
26、bration ofUpright Cylindrical TanksStd 2551 Measurement and Calibration ofHorizontal TanksManual ofPetroleum Measurement StandardsChapter 2.2B, “Calibration of Upright Cylindrical Tanks Using OpticalReference Line Method“Chapter 3.m, “Standard Practice for Level Measurement of LiquidHydrocarbons in
27、Stationary Tanks by Automatic Tank Gauging“Chapter 4, “Proving Systems“Chapter 5, “Metering“Chapter 5.2, “Measurement of Liquid Hydrocarbons by DisplacementMeters“Chapter 5.3, “Measurement ofLiquid Hydrocarbons by Turbine Meters“Chapter 6, “Metering Assemblies“Chapter 7, “Temperature Determination“C
28、hapter 8, “Sampling“Chapter 8.1, “Manual Sampling of Petroleum and Petroleum Products“Chapter 8.2, “Automatic Sampling of Petroleum and Petroleum Products“Chapter 9.1, “Hydrometer Test Method for Density, Relative Density(Specific Gravity) or API Gravity Crude Petroleum and Liquid Petro leum Product
29、s“Chapter 9.2, “Pressure Hydrometer Test for Density or Relative Density“Chapter 9.3, “Thermohydrometer Test for Density, Relative Density andAPI Gravity“ (under development)Chapter 10.1, “Determination of Sediment in Crude Oils and Fuel Oilsby the Extraction Method“Chapter 10.2, “Determination of W
30、ater in Crude Oil by Distillation“Chapter 10.3, “Determination ofWater and Sediment in Crude Oil by theCentrifuge Method“ (Laboratory Procedure)Chapter 10.4, “Determination ofSediment and Water in Crude Oil by theCentrifuge Method“ (Field Procedure)Chapter 10.8, “Standard Test Method for Sediment in
31、 Crude Oil byMembrane Filtration“Chapter 10.9, “Coulemetric Karl Fischer (under development)“Chapter 11.1, “Volume Correction Factors“Chapter 11.2.1, “Compressibility Factors for Hydrocarbons: 0-90 APIGravity Range“Chapter 11.2.2, “Compressibility Factors for Hydrocarbons 0.350-0.637Relative Density
32、 (60F/60F) and -50F to 140F Metering Temperature“Chapter 12.2, “Calculation of Liquid Petroleum Quantities Measured byTurbine or Displacement Meters“Chapter 14.1, “Collecting and Handling of Natural Gas Samples forCustody Transfer“Chapter 14.3, “Concentric, Square-Edged Orifice Meters“ (AG.AReport N
33、o.3)Chapter 14.3, Part 2, “Specification and Installation Requirements“Chapter 14.6, “Continuous Density Measurement“CHAPTER 2o-ALLOCATION MEASUREMENT, SECTION 1-ALLOCATION MEASUREMENTChapter 14.8, “Liquefied Petroleum Gas Measurement“Chapter 18.1, “Measurement Procedures for Crude Oil Gathered from
34、Small Tanks by Truck“ASTM3D1240 (ASTM-Ip4) Petroleum Measurement Table (Table 3)Std 2145 Physical Constantsfor Paraffin Hydrocarbons and Other Components ofNatural GasStd 2177 Analysis of Demethanized Hydrocarbon Liquid Mixtures ContainingNitrogen and Carbon Dioxide by Gas ChromatographyStd 2186 Ten
35、tative Method for the Extended Analysis of Hydrocarbon LiquidMixtures Containing Nitrogen and Carbon Dioxide by TemperatureProgrammed Gas Chromatography1.5 Liquid Quantity Measurement1.5.1 GENERAL DESIGN CONSIDERATIONSThis section deals with the measurement of liquid phase fluids. It does not apply
36、toliquid/gas two phase flow measurement.If the measurement scheme has flow parameters which are similar to custody transferquality measurement, the applicable API MPMS chapters should be used as a guide.However, if the measured liquid is at or above its bubble point, the following designconsideratio
37、ns should be used:a. Special effort must be made to minimize the pressure drop in the system. Pressurereduction may cause solution gas to break out from the liquid. Gas in a liquid stream willcause erroneous measurement. The following procedure should be used:1. Select and size the flow meter.2. Ins
38、tall the flow meter upstream of a control valve.3. Minimize the distance between the separator outlet and the flow meter.4. Locate the flow meter below the liquid level in the test separator.b. The flow meter should be selected to minimize the potential of erosion if a significantamount of abrasives
39、 are present in the flow stream.c. The materials for construction ofthe meter should be selected to eliminate the potentialfor stress corrosion from the chlorides or hydrogen sulfide in the produced water. Thetemperature, pressure, and composition of the streams must also be considered during thedes
40、ign and selection of materials.d. When flowing or ambient temperature affects meter performance, consideration shouldbe given to insulating or heat tracing the flowmeter system.1.5.2 MEASUREMENT EQUIPMENT CONSIDERATIONS1.5.2.1 Displacement MetersVariations in the viscosity of the liquid will affect
41、meter performance. These variationsare due to varying water cut, oil gravity, and temperature. Ifa significant viscosity variationoccurs, a series of meter factors may be developed to account for different operatingconditions. Variations in meter performance may also be reduced by using similar meas
42、ure ment procedures, proving techniques, and types of equipment at all allocation facilities.The system design and selection ofequipment should be in accordance with API MPMSChapter 5.2, as applicable.3American Society for Testing and Materials, 1916 Race Street. Philadelphia. Pennsylvania 19103.4 I
43、nstitute of Petroleum, 61 New Cavendish Street, London WIM 8AR, England.56 CHAPTER 2a-.ALLOCATION MEASUREMENT, SECTION 1-ALLOCATION MEASUREMENT1.5.2.2 Turbine MetersAPI MPMS Chapter 5.3 discusses the use ofturbine meters on single phase fluids. Singlephase has generally been used to mean liquid only
44、. API MPMS Chapter 5 may also beextended to liquid-liquid (oil and water) single phase measurement as in many allocationmeasurement schemes.The scope, field of application, system design, selection of meters, installation, opera tion, and maintenance ofturbine meters used in allocation measurement s
45、chemes are foundin API MPMS Chapter 5.3, Paragraphs 5.3.1, 5.3.2, 5.3.3, 5.3.4, and 5.3.6. In allocationmeasurement schemes, the fluid characteristics may vary substantially and this variationwill in tum affect the performance of the turbine meter.1.5.2.3 Differential Pressure DevicesThe most common
46、 differential pressure meter used in the allocation measurement ofliquids is the flange tapped, concentric orifice type. The primary element should be con structed and installed in accordance with the specifications contained in the latest revisionofAPI MPMS Chapter 14.3.The differential pressure me
47、asuring device (transmitter or bellows chart recorder) shallbe mounted below the orifice flange taps with the gauge lines sloping one inch per foottoward the secondary element. The gauge lines should be as short in length as possible andinstalled to prevent any vapor traps. Generally, on a bellows s
48、econdary element, the gaugelines should be connected to the top connections of the bellows assembly. However,depending on the liquid being measured, it may be preferable to connect to the bottombellows connections.The orifice flange tap connections shall be located on the side of the meter tube at 9
49、0degrees from vertical. Depending on the liquid being measured and ambient conditions, itmay be necessary to use a seal system to prevent plugging, corrosion, freezing, and otherproblems of the gauge lines and secondary element. The seal system shall consist of sealpots installed at the orifice taps with the pots, gauge lines, and secondary element filled witha suitable seal liquid.Accessory instrumentation to determine temperature, density, water content, and otherfactors shall be installed as necessary, depending on the application and type of measure ment (for example, vol
