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Manual of Petroleum Measurement                        Standards                        Chapter 14—Natural Gas Fluids     ...
COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
Manual of Petroleum Measurement                        Standards                        Chapter 14—Natural Gas Fluids     ...
SPECIAL NOTES                             API publications necessarily address problems of a general nature. With respect ...
FOREWORD                            API publications may be used by anyone desiring to do so. Every effort has been made  ...
COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
CONTENTS                                                                                                                  ...
CONTENTS                                                         PageCOPYRIGHT 2000 American Petroleum InstituteInformatio...
Chapter 14—Natural Gas Fluids Measurement                                  SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT  ...
2                                                     CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT                           ...
SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT                                               3               Temperature me...
4                                                              CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT                  ...
SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT                                        5               Table 1—Linear Coeffic...
6                                            CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT         5.2 MEASUREMENT BY POSITIVE...
SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT                                          7            by proving positive di...
8                                                    CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT           Where applicable,...
SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT                                          9               a. Metering tempera...
10                                            CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT              Density instruments o...
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  1. 1. Manual of Petroleum Measurement Standards Chapter 14—Natural Gas Fluids Measurement Section 8—Liquefied Petroleum Gas Measurement SECOND EDITION, JULY 1997COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  2. 2. COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  3. 3. Manual of Petroleum Measurement Standards Chapter 14—Natural Gas Fluids Measurement Section 8—Liquefied Petroleum Gas Measurement Measurement Coordination SECOND EDITION, JULY 1997COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  4. 4. SPECIAL NOTES API publications necessarily address problems of a general nature. With respect to partic- ular circumstances, local, state, and federal laws and regulations should be reviewed. API is not undertaking to meet the duties of employers, manufacturers, or suppliers to warn and properly train and equip their employees, and others exposed, concerning health and safety risks and precautions, nor undertaking their obligations under local, state, or federal laws. Information concerning safety and health risks and proper precautions with respect to par- ticular materials and conditions should be obtained from the employer, the manufacturer or supplier of that material, or the material safety data sheet. Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or prod- uct covered by letters patent. Neither should anything contained in the publication be con- strued as insuring anyone against liability for infringement of letters patent. Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. Sometimes a one-time extension of up to two years will be added to this review cycle. This publication will no longer be in effect five years after its publication date as an operative API standard or, where an extension has been granted, upon republication. Status of the publication can be ascertained from the API Measurement Coordination [telephone (202) 682-8146]. A catalog of API publications and materials is published annually and updated quarterly by API, 1220 L Street, N.W., Washington, D.C. 20005. This document was produced under API standardization procedures that ensure appropri- ate notification and participation in the developmental process and is designated as an API standard. Questions concerning the interpretation of the content of this standard or com- ments and questions concerning the procedures under which this standard was developed should be directed in writing to the Measurement Coordinator, Exploration and Production Department, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. Requests for permission to reproduce or translate all or any part of the material published herein should also be addressed to the director. API standards are published to facilitate the broad availability of proven, sound engineer- ing and operating practices. These standards are not intended to obviate the need for apply- ing sound engineering judgment regarding when and where these standards should be utilized. The formulation and publication of API standards is not intended in any way to inhibit anyone from using any other practices. Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible for complying with all the applicable requirements of that standard. API does not represent, warrant, or guarantee that such prod- ucts do in fact conform to the applicable API standard. All rights reserved. No part of this work may be reproduced, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission from the publisher. Contact the Publisher, API Publishing Services, 1220 L Street, N.W., Washington, D.C. 20005. Copyright © 1997 American Petroleum InstituteCOPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  5. 5. FOREWORD API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them; how- ever, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or dam- age resulting from its use or for the violation of any federal, state, or municipal regulation with which this publication may conflict. Suggested revisions are invited and should be submitted to Measurement Coordination, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. iiiCOPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  6. 6. COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  7. 7. CONTENTS Page SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT.............................. 1 1 SCOPE AND PURPOSE ............................................................................................. 1 2 REFERENCED PUBLICATIONS .............................................................................. 1 3 APPLICATION ............................................................................................................ 2 4 REQUIREMENTS FOR ALL MEASUREMENT METHODS ................................. 2 4.1 Provisions to Ensure That Fluids are in the Liquid Phase.................................. 2 4.2 Elimination of Swirl ........................................................................................... 2 4.3 Temperature Measurement................................................................................. 2 4.4 Pressure Measurement ........................................................................................ 3 4.5 Density or Relative Density Measurement......................................................... 3 4.6 Location of Measuring and Sampling Equipment ............................................. 3 5 VOLUMETRIC DETERMINATION IN DYNAMIC SYSTEMS .............................. 3 5.1 Measurement by Orifice Meter .......................................................................... 3 5.2 Measurement by Positive Displacement Meter.................................................. 6 5.3 Measurement by Turbine Meter ......................................................................... 6 5.4 Measurement by Other Devices ......................................................................... 6 5.5 Meter Proving..................................................................................................... 6 5.6 Sampling ............................................................................................................ 7 5.7 Sample Analysis ................................................................................................. 7 6 MASS DETERMINATION IN DYNAMIC SYSTEMS .............................................. 8 6.1 Base Conditions ................................................................................................. 8 6.2 Mass Measurement Using Displacement Type or Turbine Meters .................... 8 6.3 Orifice Meters for Mass Measurement............................................................... 8 6.4 Density Determination ....................................................................................... 9 6.5 Conversion of Measured Mass to Volume........................................................ 10 7 VOLUMETRIC MEASUREMENT IN STATIC SYSTEMS.................................... 10 7.1 Tank Calibration............................................................................................... 10 7.2 Tank Gauging of Liquefied Petroleum Gas...................................................... 10 7.3 Temperature Measurement............................................................................... 10 7.4 Relative Density Measurement............................................................................. 10 7.5 Water and Foreign Material.............................................................................. 11 7.6 Sampling .......................................................................................................... 11 7.7 Volumetric Calculation..................................................................................... 11 7.8 Mixture Calculation ......................................................................................... 12 8 MASS MEASUREMENT IN STATIC SYSTEMS ................................................... 12 APPENDIX A COMPONENT SAMPLE CALCULATIONS ..................................... 13 Figure 1 Calculations for Liquid Vapor Conversion............................................................ 15 Table 1 Linear Coefficient of Thermal Expansion................................................................ 5 Index................................................................................................................................. 17 vCOPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  8. 8. CONTENTS PageCOPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  9. 9. Chapter 14—Natural Gas Fluids Measurement SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT 1 Scope and Purpose Chapter 12.2 Calculation of Liquid Petroleum Quanti- ties Measured by Turbine or Displace- This publication describes dynamic and static measure- ment Meters ment systems used to measure liquefied petroleum gas Chapter 14.3 Concentric Square-Edged Orifice Meters (LPG) in the relative density range of 0.350 to 0.637 (see (A.G.A. Report No. 3) (GPA 8185-90) Chapter 11.2.2). The physical properties of the components Chapter 14.4 Converting Mass of Natural Gas Liquids to be measured and the mixture composition of liquefied and Vapors to Equivalent Liquid Volumes petroleum gas should be reviewed to determine the measure- Chapter 14.6 Continuous Density Measurement ment system to be used. Various systems and methods can Chapter 14.7 Mass Measurement of Natural Gas Liquids be used in measuring the quantity of product, and mutual agreement on the system and method between the contract- ASM Int’l1 ing parties is required. Metals Handbook This publication does not endorse or advocate the pref- ASME2 erential use of any specific type of meter or metering sys- Performance Test Code 19.5 (current edition) tem. Further, this publication is not intended to restrict the future development of meters or measuring devices, nor to ASTM3 in any way affect metering equipment already installed and D 1250-80 Volume XII, Table 34—Reduction of Vol- in operation. ume to 60°F Against Specific Gravity 60/ This publication serves as a guide in the selection, installa- 60°F for Liquefied Petroleum Gases tion, operation, and maintenance of measuring systems appli- D 2713-91 Test Method for Dryness of Propane cable to liquefied petroleum gases and includes functional (Valve Freeze Method) descriptions for individual systems. GPA4 2140 Liquefied Petroleum Gas Specifications 2 Referenced Publications and Test Methods (ASTM D 1835; ANSI Z11.91) To the extent specified in the text, the latest edition or revi- 2142 Standard Factors for Volume Correction sion of the following standards and publications form a part and Specific Gravity Conversion of Liq- of this publication. uefied Petroleum Gases API 2145 Physical Constants for Paraffin Hydro- carbons and Other Components of Natu- Manual of Petroleum Measurement Standards (MPMS) ral Gas Chapter 2 Tank Calibration 2165 Standard for Analysis of Natural Gas Chapter 3 Tank Gauging Liquid Mixtures by Gas Chromatography Chapter 4 Proving Systems 2166 Obtaining Natural Gas Samples for Chapter 5.2 Measurement of Liquid Hydrocarbons by Analysis by Gas Chromatography Displacement Meters 2174 Method for Obtaining Liquid Hydrocar- Chapter 5.3 Measurement of Liquid Hydrocarbons by bon Samples Using a Floating Piston Turbine Meters Cylinder Chapter 5.4 Accessory Equipment for Liquid Meters 2177 Analysis of Demethanized Hydrocarbon Chapter 6.6 Pipeline Metering Systems Liquid Mixtures Containing Nitrogen and Chapter 7.2 Dynamic Temperature Determination Carbon Dioxide by Gas Chromatography Chapter 8 Sampling 2186 Tentative Method for the Extended Anal- Chapter 9 Density Determination ysis of Hydrocarbon Liquid Mixtures Chapter 9.2 Pressure Hydrometer Test Method for Containing Nitrogen and Carbon Diox- Density or Relative Density Chapter 11.2.2 Compressibility Factors for Hydrocar- 1ASM International, 9639 Kinsman Road, Materials Park, Ohio 44073-0002. 2American Society of Mechanical Engineers, 345 East 47th Street, New bons: 0.350-0.637 Relative Density (60/ York, New York 10017-2392. 60°F) and 50°F to 140°F Metering 3ASTM, 100 Bar Harbor Drive, West Conshohocken, Pennsylvania 19428. Temperature 4Gas Processors Association, 6526 E. 60th Street, Tulsa, Oklahoma 74145. 1COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  10. 10. 2 CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT ide by Temperature Programmed Gas Liquefied petroleum gas will remain in the liquid state only Chromatography if a pressure sufficiently greater than the equilibrium vapor 2261 Analysis for Natural Gas and Similar pressure is maintained (see Chapters 5.3 and 6.6). In liquid Gaseous Mixtures by Gas Chromatogra- meter systems, adequate pressure must be maintained to pre- phy vent vaporization caused by pressure drops attributed to pip- 2286 Tentative Method of Extended Analysis ing, valves, and meter tubes. When liquefied petroleum gas is for Natural Gas and Similar Gaseous stored in tanks or containers, a portion of the liquid will Mixtures by Temperature Programmed vaporize and fill the space above the liquid. The amount Gas Chromatography vaporized will be related to the temperature and the equilib- 8173 Method for Converting Mass Natural rium constant for the mixture of components. Gas Liquids and Vapors to Equivalent Liquefied petroleum gas is more compressible and has a Liquid Volumes greater coefficient of thermal expansion than the heavier 8182-95 Standard for the Mass Measurement of hydrocarbons. The application of appropriate compressibility National Gas Liquids and temperature correction factors is required to correct mea- surements to standard conditions, except when measurement GPSA5 Engineering Data Book for mass determination is from density and volume at meter- ing temperatures and pressures. 3 Application Meters should be proven on each product at or near the This publication does not set tolerances or accuracy limits. normal operating temperature, pressure, and flow rate. If the The application of the information here should be adequate to product or operating conditions change so that a significant achieve acceptable measurement performance using good change in the meter factor occurs, the meter should be proven measurement practices, while also considering user require- again according to Chapters 4 and 5. ments and applicable codes and regulations. Systems for measuring liquefied petroleum gases use 4 Requirements For All Measurement either volumetric or mass determination methods, and both Methods methods apply to either static or dynamic conditions. The following general requirements apply to dynamic Mass determination methods of measurement are most measurement systems using either volumetric or mass deter- commonly used where conditions in addition to temperature mination methods of measuring liquefied petroleum gases. and pressure will affect the measurement. Such conditions include compositional changes, intermolecular adhesion, and 4.1 PROVISIONS TO ENSURE THAT FLUIDS ARE volumetric changes caused by solution mixing. Mass mea- IN THE LIQUID PHASE surement is applicable to liquefied petroleum gas mixtures where accurate physical correction factors have not been Provisions shall be made to ensure liquefied petroleum gas determined, and to some manufacturing processes for mass measurement conditions of temperature and pressure will be balance determination. adequate to keep the fluid totally in the liquid phase. For mea- Volumetric methods of measurement are generally used surement in the liquid phase, the pressure at the meter inlet where physical property changes in temperature and pressure must be at least 1.25 times the equilibrium vapor pressure at are known and correction factors can be applied to correct the measurement temperature, plus twice the pressure drop measurement to standard conditions.6,7 Volumetric measure- across the meter at maximum operating flow rate, or at a pres- ment is applicable to most pure components and many com- sure 125 pounds per square inch higher than the vapor pres- mercial product grades. sure at a maximum operating temperature, whichever is lower Many of the measurement procedures pertaining to the (see Chapters 5.3 and 6.6). measurement of other products are applicable to the measure- ment of liquefied petroleum gases. However, certain charac- 4.2 ELIMINATION OF SWIRL teristics of liquefied petroleum gas require extra precautions When using turbine or orifice meters, the installation to improve measurement accuracy. shall comply with the requirements specified in chapters 5.3 or 14.3, respectively. 5Gas Processors Suppliers Association; Order from Gas Processors Associa- tion, 6526 E. 60th Street, Tulsa, Oklahoma 74145. 4.3 TEMPERATURE MEASUREMENT 6USA System—Standard temperature is 60°F and standard pressure is the vapor pressure at 60°F or 14.696 pounds per square inch absolute, whichever Use of a fixed temperature may be acceptable, in some is higher. This is not the same pressure base standard as that used for gas. cases, when it varies by only a small amount; however, a 7International System of Units (SI)—Standard temperature is 15°C and stan- continuously measured temperature is recommended for dard pressure is the vapor pressure at 15°C or 101.325 kilopascals, whichever is higher. maximum accuracy.COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  11. 11. SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT 3 Temperature measurements, where required, should be 5.1 MEASUREMENT BY ORIFICE METER made at a point that indicates flowing conditions in the mea- 5.1.1 GENERAL ORIFICE METERING EQUATIONS suring device. The accuracy of instruments and the type of measurement used are specified in Chapters 4, 5.2, 5.3, 5.4, Measurement of liquefied petroleum gases by orifice 7.2, and 14.6. meter shall conform to Chapter 14.3, Part 1 using orifice and line internal diameter ratios and appropriate coefficients for 4.4 PRESSURE MEASUREMENT flow as agreed upon between the parties. The equations and factors development given in this standard are limited in scope. Use of a fixed pressure may be acceptable in some cases, For a complete explanation and development refer to Chapter where it varies by only a small amount; however, a continu- 14.3, Part 1. A complete listing of all the unit conversion fac- ously measured pressure is recommended for maximum tors (N1) can be found in Chapter 14.3, Part 1, Section 1.11.4. accuracy. The orifice meter is inherently a mass measurement device Pressure measurements, where required, should be made with the following fundamental flow equation: at a point that will be responsive to varying pressure condi- tions in the measuring device. The accuracy of instruments q m = C d E v Y ( π / 4 )d 2g c ρ t, p ∆P 2 and the type of measurement used should be as described in Chapters 4, 5.2, 5.3, 5.4, and 14.6. The practical orifice meter flow equation used in this stan- dard is a simplified form that combines the numerical con- 4.5 DENSITY OR RELATIVE DENSITY stants and unit conversion constants in a unit conversion MEASUREMENT factor (N1): The sample point for measurement of density or relative ρ t, p ∆P 2 density (specific gravity) of the liquid should reflect the vary- qm = N 1 C d E v Y d ing conditions that exist at the meter. Densities to be used to determine mass measurement must be obtained at the same Where: flowing conditions that exist at the meter. The accuracy of Cd = orifice plate coefficient of discharge. instruments and the type of measurement used should be as d = orifice plate bore diameter calculated at flowing described in Chapters 9.2 and 14.6. temperature (Tf). ∆P = orifice differential pressure. 4.6 LOCATION OF MEASURING AND SAMPLING Ev = velocity of approach factor. EQUIPMENT N1 = unit conversion factor. Measuring and sampling equipment shall be located as qm = mass flow rate. required in Chapter 8 and must be located to minimize or ρt,p = density of the fluid at flowing conditions (Pf,Tf). eliminate the influence of pulsation or mechanical vibration Pf = flowing pressure (psia) caused by pump or control valve generated noise. Special Y = expansion factor. precautions should be taken to minimize or eliminate the effects of electrical interference that may be induced in the The expansion factor, Y, is included in the above equations flow meter pick-up coil circuit. Use of a preamplifier is rec- because it is applicable to all single-phase, homogeneous ommended. Newtonian fluids. For incompressible fluids, such as water at Representative samples shall be obtained as required in 60°F and atmospheric pressure, the empirical expansion fac- GPA 2166 and GPA 2174. When automatic sampling systems tor is defined as 1.0000. are used, care must be taken to ensure that the sample is taken The following equations can be used to determine flow rate: from the center one-third of cross-sectional area of the 1. Flow rate in cubic feet per hour at flowing conditions: stream, the stream is well mixed at that point, the sample point is not in a dead leg, and the sample system does not per- ∆P mit bypassing the meter. Q f = 359.072C d E v Y d 2 ------- - ρ t, p 5 Volumetric Determination in Dynamic ∆P Systems Q f = 359.072C d E v Y d 2 --------------- ρ w, b G f - Dynamic measurement of liquefied petroleum gas (liquid phase), for custody transfer, can be performed using several 2 ∆P Q f = 45.4683C d E v Y d ------ - different measurement devices. The choice of the specific Gf type selected is dependent upon mutual agreement between the contracting parties. 2. Flow rate in pounds mass per hour:COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  12. 12. 4 CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT ∆Pρ t, p 2 Q f = 359.072C d E v Y d Y = 1.0000, per 4.1, provisions are made toensure that the liquefied petroleum gas fluids are always mea- ∆PG f 2 Q f = 2835.6681C d E v Y d sured in a liquid state. Normally 1.0000 should be used unless the liquefied petroleum gas is being Measurement of liquefied petroleum gas having a high measured at temperatures and pressures that may vapor pressure is sometimes simplified, where deliveries are alter the fluid properties. obtained in mass units, by multiplying the volume at flowing conditions times the density (measured within prescribed lim- 5.1.2 Velocity of Approach Factor (Ev) its at the same flowing temperature and pressure that exists at The velocity of approach factor, Ev, is calculated as follows: the meter) times the meter and density adjustment factors as shown in 6.2. Calculation of the volume at standard condi- 1 E v = ----------------- - 1–β 4 tions can then be made using 6.5 or GPA 8173. 3. Flow rate in cubic feet per hour at base conditions: and, β = d/D. 359.072 Q f = ------------------ C d E v Y d ∆Pρ t, p 2 - ρb Where: 45.4683 d = orifice plate bore diameter calculated at flowing Q f = ------------------ C d E v Y d ∆PG f 2 - temperature (Tf). Gb D = meter tube internal diameter calculated at flowing 4. Flow rate in cubic feet per hour at base conditions temperature (Tf). using volume and compressibility correction tables. (This method should only be used when measuring a pure product 5.1.3 Orifice Plate Bore Diameter (d) or mixture with well defined fluid properties.) The orifice plate bore diameter, d, is defined as the diame- ∆P ter at flowing conditions and can be calculated using the fol- ------- ( C tl C pl ) 2 Q f = 359.072C d E v Y d - lowing equation: ρ t, p d = d r [ 1 + α1 ( T f – T r ) ] ∆P ------ ( C tl C pl ) 2 Q f = 45.4683C d E v Y d - Where: Gf Where: α1 = linear coefficient of thermal expansion for the ori- fice plate material (see Table 1). d = orifice plate bore diameter in inches. d = orifice plate bore diameter calculated at flowing ∆P = orifice differential pressure in inches of H2O at 60°F. temperature (Tf). Ev = velocity of approach factor. dr = reference orifice plate bore diameter at Tr . N1 = 359.072 (US units conversion factor 9.97424 Tf = temperature of the fluid at flowing conditions. E-02 × 3600) Tr = reference temperature of the orifice plate bore qm = mass flow rate in pound-mole/hour. diameter. ρt,p = density of the fluid at flowing conditions (Pf,Tf) in pound-mole/foot3. Note: α, Tf , and Tr must be in consistent units. For the purpose of this stan- dard Tr is assumed to be at 68°F (20°C). ρb = density of the fluid at base conditions (Pb,Tb) in pound-mole/foot3. The orifice plate bore diameter, dr , calculated at Tr is the ρw,b = 62.3663 pound-mole/foot3—density of air-free diameter determined in accordance with the requirements pure water at 60°F and an atmospheric pressure of Chapter 14.3, Part 2. 14.696 pounds per square inch. Gf = relative density at flowing conditions. Ratio of the 5.1.4 Meter Tube Internal Diameter (D) density of the liquid at flowing conditions to the The meter tube internal diameter, D, is defined as the diam- density of water at 60°F. eter at flowing conditions and can be calculated using the fol- Gb = relative density at base conditions. lowing equation: Ctl = correction factor for temperature to correct the vol- D = Dr [ 1 + α2 ( T f – T r ) ] ume at flowing temperature to standard tempera- ture. See ASTM D 1250-80, Volume XII, Table 34, Where: GPA 2142-57 or other agreed-upon tables. α 2 = linear coefficient of thermal expansion for the Cpl = correction factor for pressure to correct the vol- meter tube material (see Table 1). ume at flowing pressure to standard conditions. D = meter tube internal diameter calculated at flowing See Chapter 11.2.2 or other agreed-upon tables. temperature (Tf).COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  13. 13. SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT 5 Table 1—Linear Coefficient of Thermal Expansion 2L 2 M 2 = ----------- - 1–β Linear Coefficient of 19, 000β 0.8 Thermal Expansion (α) A =  --------------------  -  Re D  U.S. Units Metric Units 10 β 6 0.35 Material (in/in/°F) (mm/mm/°C) C =  ----------  -  Re D  Type 304 and 316 stainless steela 0.00000925 0.0000167 Where: Monela 0.00000795 0.0000143 Carbon steelb 0.00000620 0.0000112 β = diameter ratio. = d/D. Note: For flowing temperature conditions outside those stated above and for Cd(FT) = coefficient of discharge at a specified pipe other materials, refer to the American Society for Metals Metals Handbook. aFor flowing conditions between –100°F and +300°F, refer to ASME PTC Reynolds number for flange-tapped orifice meter. 19.5. Ci(FT) = coefficient of discharge at infinite pipe Reynolds bFor flowing conditions between –7°F and +154°F, refer to Chapter 12, number for flange-tapped orifice meter. Section 2. Ci(CT) = coefficient of discharge at infinite pipe Reynolds number for corner-tapped orifice meter. 5.1.5 Empirical Coefficient of Discharge Equation d = orifice plate bore diameter calculated at Tf. for Flange-Tapped Orifice Meters. D = meter tube internal diameter calculated at Tf. e = Napierian constant. The concentric, square-edged flange-tapped orifice = 2.71828. meter coefficient of discharge, Cd, (FT) equation, devel- L1 = dimensionless correction for the tap location. oped by Reader-Harris/Gallagher (RG), is structured into = L2. distinct linkage terms and is considered to best represent = N4/D for flange taps. the current regression database. The equation is applica- N4 = 1.0 when D is in inches. ble to nominal pipe sizes of 2 inches (50 millimeters) and = 25.4 when D is in millimeters. larger; diameter ratios (β) of 0.1 to 0.75, provided the ori- ReD = pipe Reynolds number. fice plate bore diameter, dr , is greater than 0.45 inch (11.4 millimeters); and pipe Reynolds numbers (ReD) greater 5.1.6 Reynolds Number (ReD) than or equal to 4000. For diameter ratios and pipe Rey- nolds numbers below the limit stated, refer to Chapter The RG equation uses pipe Reynolds number as the corre- 14.3.1.12.4.1. The RG coefficient of discharge equation lating parameter to represent the change in the orifice plate for an orifice meter equipped with flange taps is defined as coefficient of discharge, Cd, with reference to the fluid’s mass follows: flow rate (its velocity through the orifice), the fluid density, and the fluid’s viscosity. 10 β 6 0.7 C d = C i ( FT ) + 0.000511 ---------- - The pipe Reynolds number can be calculated using the fol- Re D lowing equation: + ( 0.0210 + 0.0049 A )β C. 4 4q m Re D = ---------- - C i ( FT ) = C i ( CT ) + TapTerm. πµD The pipe Reynolds number equation used in this standard C i ( CT ) = 0.5961+ 0.029β 2 is in a simplified form that combines the numerical constants – 0.2290β + 0.003 ( 1 – β )M 1 . 8 and unit conversion constants: TapTerm = Upstrm + Dnstrm. N 2 qm Re D = ----------- - – 8.5L 1 µD Upstrm = [0.0433 + 0.0712e – 6.OL For the Reynolds number equations presented above, the ] ( 1 – 0.23A )B. 1 – 0.1145e symbols are described as follows: Dnstrm = – 0.0116 [ M 2 – 0.52M 2 ]β ( 1 – 0.14 A ) 1.3 1.1 D = meter tube internal diameter calculated at flowing temperature (Tf). Also, µ = absolute viscosity of fluid. β 4 N2 = unit conversion factor. B = ------------- - π = universal constant. 1–β 4 = 3.14159. M 1 = max  2.8 – ----- ,0.0 D qm = mass flow rate. -  N4  ReD = pipe Reynolds number.COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  14. 14. 6 CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT 5.2 MEASUREMENT BY POSITIVE Air eliminators should be used with caution, particularly DISPLACEMENT METER where the line in which they are installed could be shut-in occasionally and where complete vaporization could occur. In The manufacturer’s recommendations should be carefully this case, thermal relief valves may be required to prevent considered in sizing positive displacement meters (see physical damage to the equipment. Chapter 5.2). Vapor formation resulting from the effects of ambient tem- Air eliminators should be used with caution, particularly perature or heat tracing on the line ahead of the meter could where the line in which they are installed could be shut-in cause inaccuracies and damage, which are most likely to be occasionally, and where complete vaporization could occur. encountered during startup. Caution must be exercised. Vapor formation resulting from the effects of ambient tem- Liquid measurement by turbine meter should conform to perature or heat tracing on the line ahead of the meter could the procedures described in Chapter 5.3. If volumetric mea- cause inaccuracies and damage, which are most likely to be surement is being performed, appropriate correction factors encountered during startup. Caution must be exercised. should be used that will adjust the measured volume to stan- dard conditions by correcting for temperature, pressure, and 5.2.1 Volume at Standard or Base Conditions meter factor. Factors to be applied will be found in Chapters Liquid measurement by positive displacement meters 4, 11, and 12. should conform to the procedures in Chapter 5.2. Appropriate The following equation is used when performing volumet- correction factors should be used to adjust the measured vol- ric measurement by turbine meter: ume to standard conditions by correcting for temperature, V b = V f × M.F. × C tl × C pl pressure, and meter factor. Factors to be applied will be found in Chapters 11 and 12. Where: The positive displacement measurement equation is: Vb = volume at base or standard conditions. Vf = volume at flowing conditions, indicated by a V b = V f × M.F. × C tl × C pl measuring device. Where: M.F. = meter factor, obtained by proving the meter according to Chapters 4 and 12.2. Vb = volume at base or standard conditions. Ctl = correction factor for temperature to correct the Vf = volume at flowing conditions, indicated by a volume at flowing temperature to standard tem- measuring device. perature. See ASTM D 1250-80, Volume XII, M.F. = meter factor, obtained by proving the meter Table 34, GPA Standard 2142-57 or other according to Chapters 4 and 12.2. agreed-upon tables. Ctl = correction factor for temperature to correct the Cpl = correction factor for pressure to correct the vol- volume at flowing temperature to standard tem- ume at flowing pressure to standard conditions. perature. See ASTM D 1250-80, Volume XII, See Chapter 11.2.2 or other agreed-upon tables. Table 34, GPA Standard 2142-57 or other agreed-upon tables. Turbine meters used for volumetric measurement at flow- Cpl = correction factor for pressure to correct the vol- ing conditions, in deriving total mass shall conform to Chap- ume at flowing pressure to standard conditions. ter 5.3 for the service intended. Temperature or pressure See Chapter 11.2.2 or other agreed-upon tables. compensating devices shall not be used on these meters, and accessories shall conform to Chapter 5.4. The measured 5.2.2 Volume at Flowing Conditions for Mass mass, converted to equivalent component volumes at standard Determination conditions, may be determined according to GPA 8173. The volume measured at flowing conditions (Vm) times the 5.4 MEASUREMENT BY OTHER DEVICES meter factor equals the volume at flowing conditions. Dis- placement meters used for volumetric measurement in deriv- Dynamic measurement of liquefied petroleum gas can be ing total mass shall conform to the standards described in accomplished using other types of equipment by mutual Chapter 5.2 for the service intended. Temperature or pressure agreement of the contracting parties. Application of this stan- compensation devices are not to be used on these meters, and dard requires use of industry recognized custody transfer the accessories used shall conform to Chapter 5.4. devices. 5.3 MEASUREMENT BY TURBINE METER 5.5 METER PROVING The manufacturer’s recommendations should be carefully The primary measuring device must be compared to a considered in sizing turbine meters (see Chapter 5.3). known standard. Comparison to a standard is accomplishedCOPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  15. 15. SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT 7 by proving positive displacement and turbine meters using a adequately sized. If samples are to be shipped by common conventional pipe prover or a small volume prover cali- carrier, containers must comply with the latest hazardous brated in accordance with Chapter 4. Tank-type provers are materials regulations of the United States Department of not recommended because liquefied petroleum gas may Transportation, manufacturer’s recommendations, or similar vaporize in the tank, making accountability for these vapors appropriate authority. difficult. When a meter is used to measure more than one Products or mixtures that have equilibrium vapor pressures product, the meter shall be proved at the operating rates of above atmospheric pressure shall be maintained at a pressure flow, pressure, and temperature and at the specification of the where vaporization cannot occur within the on-line sample liquid that it will measure in routine operation. Several meter system or transfer containers. For single cavity sample con- factors may be required where normal operations change sig- tainers, care must be taken to ensure at least a 20 percent out- nificantly. The proving device should be installed so that the age in transfer containers. All systems must allow for thermal temperature and pressure within the prover and meter coin- expansion without overpressuring the system. (See GPA 2174 cide as closely as possible. Meter and prover volumes shall be on sampling.) corrected to base conditions according to Chapters 4, 11, and Use of sample collection and transportation containers 12. Factors shall be adjusted, as required, between proving equipped with floating pistons or bladders (and equipped to dates as a result of significant changes in metering pressure, maintain sample storage pressures above vapor pressure) is temperature, product, or flow rate since the last proving. one effective way to avoid liquid-vapor separation. When using this type of equipment, adequate precautions must be 5.6 SAMPLING observed to allow for thermal expansion of the product so that excessive pressure or release of product does not occur. Sampling shall be accomplished to yield a sample that is Sample handling procedures outlined in GPA 2174, using proportional to, and representative of, the flowing stream dur- immiscible fluid outage cylinders, may also be used. Water ing the measuring interval. Proportional samplers take small used with this method may result in removal of carbon diox- samples of the flowing stream proportional to the flow rate. ide or other water-soluble components from the sample. Time incremental sampling may be used only when the flow A sampling system, for taking proportional samples rate is constant. Time proportional sampling systems must over a period of time, must provide a workable mixing stop sampling when the flow stops. system that thoroughly mixes the sample. Proportional The sample collecting system shall be designed to contain samples, to be truly representative, must be mixed before the collected sample in the liquid state. This may be done being transferred to the portable sample container. Product using a piston cylinder or a bladder cylinder. Both the piston mixing should not be attempted until the sampler has been cylinder and bladder cylinder normally use inert gas vapor isolated from the source. Procedures for thorough mixing not normally found in the sample stream (for example, of samples shall be provided to ensure that samples trans- helium), hydraulic oil, or pipeline fluid to oppose the liquid ferred to transportation cylinders and the analysis injection and maintain a pressure level above the vapor pres- obtained are representative of the flowing stream during sure of the sample. the measured interval. Precautions shall be taken to avoid vaporization in sample After mixing, the sampled product is transferred to a porta- loop lines when operating near the product vapor pressure. In ble piston cylinder or a double-valved sample cylinder, using some cases when sampling volatile materials, it may be nec- the immiscible fluid displacement method. Transfer the sam- essary to either insulate sample lines and sample containers, ple to the portable cylinder using the same procedure used to or to control the pressure or temperature of sample containers. take spot samples. When the required number of portable cyl- Sample loops should be short and in small diameter. Sam- inders has been filled, the remaining product in the sampler pling should be from the center one-third of the cross- must be vented back into the pipeline or disposed of before sectional area of the stream using a sample probe. Ade- the sampler is returned to service. quate sample loop flow rates should be maintained to keep Obtaining a representative sample of the liquid stream for fresh product at the sample valve and to minimize the time transport to the laboratory shall be in accordance with lag between the meter and the sampler. Sample loops must GPA 2174. Provisions shall be made for thermal expan- not bypass the primary measurement element. sion. Department of Transportation-approved containers When sample collection cylinders are emptied, all sample shall be used. lines, pumps, and related equipment should be purged or bled down to avoid contamination or distortion of the flowing 5.7 SAMPLE ANALYSIS sample. Sampler systems should be designed to minimize dead product areas, which could distort samples. Depending upon the composition of the stream, the liquid Obtaining a representative sample shall be in accordance sample analysis shall follow the chromatographic procedures with GPA 2166 and GPA 2174. Sample containers must be described in GPA Publications 2165, 2177, 2186, and 2261.COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  16. 16. 8 CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT Where applicable, such as with liquefied petroleum gas plished through procedures in Chapter 14.6 by referral to mixtures, special efforts shall be made to accurately deter- weighing devices used to calibrate density meters to test mine the molecular weight and the density of the heavi- weights of known mass. This referral or calibration is done at est final combined peak eluted—for example, heptanes or near the densitometer location, eliminating the need for plus fraction (or of the last significant fraction deter- further correction for local gravitational force variances. mined by agreement). Weight observations to determine fluid density shall be corrected for air buoyancy (commonly called weighed in vac- 6 Mass Determination in Dynamic uum) and for local gravity, as necessary. Such observations Systems (Relative Density Range can be used in conjunction with the calibration of density 0.350 to 0.637) meters or for checking the performance of equation of state correlations. Procedures are outlined in Chapter 14.6. Mass measurement is applicable to liquefied petroleum gas Volumes and densities for mass measurement shall be mixtures and to components that are affected by composi- determined at operating temperature and pressure to elim- tional changes, intermolecular adhesions, solution mixing, or inate temperature and compressibility corrections. How- extreme pressure and temperature conditions where accurate ever, equivalent volumes of components are often physical correction factors have not been determined. computed for the determined mass flow. These volumes Mass measurement in a dynamic state normally utilizes shall be calculated at a temperature of 60°F (15.56°C) and (a) a volumetric measuring device at flowing conditions, (b) a pressure of either 14.696 psia (101.325 kPa) or equilib- a density or relative density (specific gravity) measuring rium pressure of the product at 60°F (15.56°C) whichever device for determining density or relative density at the is greater. same flowing conditions as the measuring device, and (c) a representative sample of the fluid flowing through the mea- suring system, collected proportional to flow, as presented 6.2 MASS MEASUREMENT USING in GPA 8182. DISPLACEMENT TYPE OR TURBINE METERS Mass measurement is obtained by multiplying the mea- The equation for determining mass using displacement- sured volume at flowing conditions times flowing density type or turbine meters is: measured at the same conditions, using consistent units. The equivalent volume at standard conditions of each component in the mixture may be obtained by using a compositional Metered volume Meter factor analysis of the representative sample and the density of each at meter at meter Mass = × component at 60°F and the equilibrium pressure at 60°F (see operating operating GPA 8173). conditions conditions Liquids with relative densities below 0.350 and above 0.637 and cryogenic fluids are excluded from the scope of this document. However, the principles can apply to these flu- Densitomer ids with modified application techniques. Density at Equipment exists that uses diverse principles for measuring "" × meter operating × correction volume, sampling the product, and determining the composi- factor (if tion and density of the product. This publication does not conditions applicable) advocate the preferential use of any particular type of equip- ment. It is not the intention of this publication to restrict future development or improvement of equipment. 6.3 ORIFICE METERS FOR MASS MEASUREMENT 6.1 BASE CONDITIONS The following is a sample calculation of the mass flow rate Density is defined as mass per unit volume: using an orifice meter to measure delivery of a liquefied petroleum gas (raw mix) from a gas processing plant. Mass Density = -------------------- Volume A. Given Mass is an absolute measure of the quantity of matter. 1. Orifice meter station designed, installed, and operated Weight is the force resulting from an acceleration due to grav- in compliance with specifications in the API MPMS, ity acting upon a mass. Changes of gravity acceleration from Chapter 14, Section 3, Parts 1 and 2. one locality to another will affect the resulting weight force 2. Product being delivered is de-methanized liquid (raw observed. Quantities determined in accordance with GPA mix) from a gas processing plant having the following 8182 shall be mass rather than weight. This may be accom- analysis:COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  17. 17. SECTION 8—LIQUEFIED PETROLEUM GAS MEASUREMENT 9 a. Metering temperature - - - 80°F. 6.4 DENSITY DETERMINATION b. Viscosity - - - 0.095 centipoise. Density may be determined by empirical correlation, based c. Meter tube internal diameter (I.D.) 4.026" at 68°F. on an analysis of the fluid or on a direct measurement of the d. Orifice plate 316 ss - - - 2.005" at 68°F. flowing density. e. Operating differential pressure ∆P - - - 50" H2O at 60°F. f. Operating density of 29.47 pounds/feet.3 6.4.1 Empirical Density B. Problem Liquid density may be calculated as a function of com- Calculate the mass flow rate in pounds mass per 24 hours position, temperature, and pressure. It is preferred that the and convert to volume at 60°F and equilibrium vapor pressure calculated or measured density be applied in real time to in gallons of each component. the flowmeter. This provides for the maximum mass mea- C. Solution surement precision, that is, the incremental volume of measured liquid is always in direct time relation to the ρ t 1, p1 ∆P 2 qm = N 1 C d E v Y d density measured or calculated. However, it is common practice to use the composition of a sample taken continu- Where: ously during the delivery period proportional to the vol- ume delivered, and to use the average temperature and qm = pounds mass per second. pressure for the delivery period. Cd = orifice plate coefficient of discharge. Calculations may be made by means of empirical corre- d = orifice plate bore diameter calculated at flowing lations or by generalized equations of state. The empirical temperature. correlations are derived from fitting experimental data ∆P = differential pressure across orifice plate. Static covering specific ranges of compositions, temperatures, pressure measured at upstream flange tap. and pressures and can be inaccurate outside these ranges. Ev = velocity of approach factor. The GPA procedure TP-1 for ethane/propane mix and TP-2 N1 = unit conversion factor. for high ethane raw make streams are examples. TP-3 is a t1, ρ1 = indicates temperature and pressure at flowing con- more theoretical procedure for application to liquefied ditions. natural gas. a. Calculate the I.D. of the meter tube at 80°F. Generalized equations of state do not have strict limitations D = Dr [1 + α2 (Tf –Tr)] Tf = Flowing temperature, Tr = on ranges of compositions and conditions and can be applied Reference temperature, Dr (reference temperature) to a wide variety of systems; however, empirical correlations = 4.026 at 68°F. Carbon steel. are much more accurate when applied to the specific systems D = 4.026 [1 + 0.00000620(80-68)] = 4.02630". for which they were derived. The Rackett equation, the Han- α2 = Coefficient of thermal expansion in carbon steel Starling modification of the BWR equation of state, and sev- (inch/inch/°F). eral modified Redlich-Kwong equations of state (Soave, Mark V, Peng-Robinson) are examples. b. Calculate orifice bore diameter at flowing temperature of It is the responsibility of the contracting parties to verify 80°F. the validity and limits of the accuracy of methods considered d = dr [1 + 0.00000925(80–68)] = 2.00522". for empirical density determination on the particular fluids to c. Calculate, β, ratio of d/D = 2.00522/4.0630 = 0.498031. be measured. Significant errors can occur from inaccuracies in tempera- d. Calculate Ev—velocity of approach factor. ture and pressure measurement, recording, or integration. Ev = 1/(1–β4)0.5 = 1/(1–0.061531).5 = 1.032256. Products with a relative density less than 0.6 are particularly e. Expansion factor Y = 1.0. susceptible to errors and require a higher level of precision. See Chapter 14.6 for recommended precision levels of tem- f. Calculated, Cd (FT), coefficient of discharge for flange taps. perature and pressure. Calculation of the mass flow rate provides an easy way to obtain the volumetric flow rate at flowing conditions and the 6.4.2 Measured Density volumetric flow rate at base conditions. Calculation of flow involves an iteration process on a digital computer. For the Measured density of products having a relative density given set of conditions the rate of flow is: between 0.350 and 0.637 shall be determined using den- sity meters installed and calibrated in accordance with Qm per day (24 hours) = 828,600 pounds mass Chapter 14.6.COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000
  18. 18. 10 CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT Density instruments or probes shall be installed as follows: respective equivalent liquid volumes at 60°F (or 15.56°C) and the equilibrium vapor pressure at 60°F (or 15.56°C), using a. No interaction that would adversely affect the flow or den- component density values in vacuum from Chapter 11 or sity measurements shall exist between the flowmeter and the GPA 2145. Example calculations, repeated from Chapter density transducer or probe. 14.4, are provided in the appendix. b. Temperature and pressure differences among the fluid in the flowmeter, the density measuring device, and the calibrat- ing devices must be minimized and must be within specified 7 Volumetric Measurement in Static limits for the fluid being measured and the mass measurement Systems accuracy expected or required. The total fluid volume is the sum of the volume of the fluid c. Density meters may be installed either upstream or down- currently in the liquid state plus the volume of the fluid in the stream of primary flow devices in accordance with Chapter vapor state converted to equivalent liquid volume. 14.6, but should not be located between flow straightening Volumetric measurement is obtained by using calibrated devices and meters and must not bypass the primary flow vessels or tanks with gauging devices that can be read at the measurement device. vessel operating pressures to determine the liquid level. The volume of vapor above the liquid is determined by using the Densitometer accuracy will be seriously affected by the ideal gas law (PV = NRT) corrected by the gas compressibil- accumulation of foreign material from the flowing stream. The ity factor. The liquid and vapor are corrected for temperature possibility of accumulation should be considered in selecting and pressure to standard or base conditions of temperature density measurement equipment and in determining the fre- and the vapor pressure of the product at standard or base tem- quency of density equipment calibration and maintenance. perature. The vapor volume can be converted to equivalent Accuracy of the data recording, transmission, and computation liquid volume by using the appropriate factors. A pressure equipment and methods should also be considered in system vessel or container must be able to safely withstand the vapor selection. See Chapter 14.6 for further comments. pressures of the contained product at the maximum operating temperature. 6.5 CONVERSION OF MEASURED MASS TO VOLUME 7.1 TANK CALIBRATION Conversion from mass determined into equivalent volumes of components shall be in accordance with the latest revision Procedures for calibrating tanks and vessels are presented of GPA 8173, as described below. In this procedure, a chro- in Chapter 2. matographic analysis representative of the delivered product is used to determine the mass of each individual component 7.2 TANK GAUGING OF LIQUEFIED PETROLEUM that comprised the total mass. The individual component GAS masses are then converted to their respective equivalent liq- Procedures for gauging liquefied petroleum gas in stor- uid volumes at 60°F (or 15.56°C) and equilibrium vapor age tanks are presented in Chapter 3. Special precautions pressure at 60°F (or 15.56°C), using component density val- are necessary to accurately account for the vapors above ues from GPA 2145. The method and frequency of deter- the liquid. The composition and volume of the vapors are mining physical properties for combined component dependent upon the temperature and pressure conditions fractions (such as C7+) must be established and agreed to of the liquid. by the affected parties. The calculation of total mass flowing must be performed continuously on-line by a suitable device or by off-line inte- 7.3 TEMPERATURE MEASUREMENT gration of charts on which metered volume and density are Chapter 5.4 contains general requirements for temperature continuously recorded, so that at all times the density corre- measurement. Procedures for measuring the temperature of sponds to the volume measured. liquefied petroleum gas in storage vessels under static condi- Conversion of the determined mass into an equivalent vol- tions are presented in Chapter 7. ume of each component at base or standard conditions at equilibrium vapor pressure at 60°F (15.56°C) or 14.696 7.4 RELATIVE DENSITY MEASUREMENT pounds per square inch absolute (101.325 kilopascals), whichever is higher, shall be in accordance with Chapter Procedures for determining relative density of liquefied 14.4. In this procedure a chromatographic analysis, represen- petroleum gas are presented in Chapters 9, 11, 12, 14.6, and tative of the delivered product, is used to determine the mass 14.7. Observed relative densities (specific gravities) are cor- of each individual component comprising the total mass. The rected to standard or base conditions by using tables in individual component masses are then converted to their Chapter 11.1.COPYRIGHT 2000 American Petroleum InstituteInformation Handling Services, 2000

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