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  • 1. Manual of Petroleum Measurement Standards Chapter 14—Natural Gas Fluids Measurement Section 1—Collecting and Handling of Natural Gas Samples for Custody Transfer FIFTH EDITION, JUNE 2001COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 2. COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 3. Manual of Petroleum Measurement Standards Chapter 14—Natural Gas Fluids Measurement Section 1—Collecting and Handling of Natural Gas Samples for Custody Transfer Measurement Coordination Department FIFTH EDITION, JUNE 2001COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 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 fed- eral 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 Generally, API standards are reviewed and revised, reafÞrmed, or withdrawn at least every Þve years.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 Þve 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 Department [telephone (202) 682-8000]. A catalog of API publications and materials is published annu- ally 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 notiÞcation 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 standardization manager, 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 gen- eral manager. 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 © 2001 American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 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; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any federal, state, or municipal regulation with which this publication may conßict. Suggested revisions are invited and should be submitted to the standardization manager, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. iiiCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 6. COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 7. CONTENTS Page 14.1.1 INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 14.1.2 PURPOSE AND SCOPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 14.1.3 REFERENCED PUBLICATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 14.1.4 DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 14.1.5 HYDROCARBON DEW POINT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 14.1.5.1 Initial Sampling of a Gas Stream of Unknown Hydrocarbon Dew Point and Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 14.1.6 GENERAL CONSIDERATIONS FOR THE DESIGN OF A NATURAL GAS SAMPLING SYSTEM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 14.1.6.1 The Components of Typical Sampling Systems . . . . . . . . . . . . . . . . . . 4 14.1.6.2 Flow Characteristics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 14.1.6.3 Causes of Gas Sample Distortion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 14.1.6.4 Revaporization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 14.1.6.5 Cleanliness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 14.1.6.6 General Discussion of Heating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 14.1.7 SAMPLE PROBES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 14.1.7.1 General Design Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 14.1.7.2 Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 14.1.7.3 Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 14.1.7.4 Probe Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 14.1.8 SAMPLE LOOPS/LINES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 14.1.8.1 General Design Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 14.1.8.2 Pressure Drop in a Sample Loop . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 14.1.8.3 Tubing Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 14.1.8.4 Pressure Regulators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 14.1.8.5 Pumps. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 14.1.8.6 Filters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 14.1.8.7 Separators. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 14.1.9 SAMPLE CONTAINERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 14.1.9.1 General Design Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 14.1.9.2 Types of Sample Containers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 14.1.10 MATERIALS FOR SWEET AND SOUR GAS SERVICE. . . . . . . . . . . . . . . . . 15 14.1.10.1 General Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 14.1.10.2 Carbon Steel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 14.1.10.3 Dissimilar Materials. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 vCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 8. Page 14.1.11 OTHER APPARATUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 14.1.11.1 Timers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 14.1.11.2 Flow Computers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 14.1.11.3 Power Supplies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 14.1.11.4 Pressure Gauges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 14.1.12 SPOT SAMPLING METHODS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 14.1.12.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 14.1.12.2 Evacuated Container Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 14.1.12.3 Reduced Pressure Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 14.1.12.4 Helium Pop Method. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 14.1.12.5 Floating Piston Cylinder Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 14.1.12.6 Water Displacement Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 14.1.12.7 Glycol Displacement Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 14.1.12.8 PurgingÑFill and Empty Method. . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 14.1.12.9 PurgingÑControlled Rate Method . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 14.1.12.10 VacuumÐGathering System Method . . . . . . . . . . . . . . . . . . . . . . . . . . 19 14.1.12.11 Use of an Extension Tube/ ÒPigtailÓ . . . . . . . . . . . . . . . . . . . . . . . . . . 23 14.1.13 AUTOMATIC SAMPLING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 14.1.13.1 Composite Samplers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 14.1.13.2 Continuous Sampling Systems for On-line Analyzers . . . . . . . . . . . . 23 14.1.14 SAMPLING INTERVALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 14.1.14.1 General Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 14.1.14.2 Composite Sample Intervals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 14.1.14.3 Spot Sampling Intervals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 14.1.15 SAFETY, LABELING, HANDLING, AND TRANSPORTATION OF CYLINDERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 14.1.15.1 Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 14.1.15.2 Labeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 14.1.15.3 Handling and Transportation of Cylinders . . . . . . . . . . . . . . . . . . . . . 25 14.1.16 GUIDELINES FOR ANALYSIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 APPENDIX A THE PHASE DIAGRAM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 APPENDIX B FLUID MECHANICAL CONSIDERATIONS IN GAS SAMPLING. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 APPENDIX C LESSONS LEARNED DURING SAMPLING IN HYDROCARBON SATURATED AND 2-PHASE NATURAL GAS STREAMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 APPENDIX D HYDROGEN SULFIDE WARNING . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 APPENDIX E API LABORATORY INSPECTION CHECKLIST. . . . . . . . . . . . . . . . 43 viCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 9. Page Figures 1a Typical Spot Sampling System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 1b Typical Composite Sampling System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 2 Typical Continuous (On-Line) Sampling System/Mobile Sampling System . . . . . 6 3 Examples of Thermodynamic Processes Associated with Sampling System Design and Sampling Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 4 Straight Tube Sample Probe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 5 Typical Regulated Sample Probe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 6 Typical Double Valve Sample Cylinder . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 7 Typical Floating Piston Cylinder . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 8 API-Recommended Spot Sampling Apparatus for Fill and Empty Method. Close-Coupled and Direct Mount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 9a Vacuum Gathering System Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 9b Alternate Method of Sampling from a Vacuum-Gathering System . . . . . . . . . . . . 22 10 Typical Sample Form . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 A1 PressureÑVolume and PressureÑTemperature Diagrams for a Pure Component . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 A2 PressureÑVolume and PressureÑTemperature Diagrams for a Mixture . . . . . . . 32 A3 Retrograde Condensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 A4 Examples of Thermodynamic Processes of Natural Gas . . . . . . . . . . . . . . . . . . . . 34 B1 Laminar Flow in the Entrance Region of a Pipe. . . . . . . . . . . . . . . . . . . . . . . . . . . 36 B2 Comparison of Laminar and Turbulent Velocity ProÞles for Flow in a Pipe. . . . . 36 Tables 1 Fill and Empty Purge Cycles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 viiCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 10. COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 11. Chapter 14—Natural Gas Fluids Measurement Section 1—Collecting and Handling of Natural Gas Samples for Custody Transfer 14.1.1 Introduction composition. Time proportional samplers, particularly if they continue to sample even when ßow has stopped, are not capa- This standard concentrates on proper sampling systems ble of accurately characterizing natural gas streams that have and procedures. It recognizes the critical impact of hydro- variable compositions. carbon dew point consideration to the overall accuracy and Sampling systems and procedures not in compliance with success of these practices and procedures. Analyses of gas this guideline may result in errors. Upgrading existing facili- samples are used for many purposes and are applied to var- ties and practices to comply with this standard is strongly ious calculations, some of which have an impact on the encouraged but shall be at the discretion of the parties accuracy of custody transfer calculations (quantity and involved. quality). Inaccuracies can result from using: 14.1.2 Purpose and Scope a. Inappropriate sampling techniques and/or equipment, The purpose of this standard is to provide a comprehensive b. Inappropriate sample conditioning and handling, guideline for properly collecting, conditioning, and handling c. Samples collected from non-representative locations and/ representative samples of natural gas that are at or above their or under non-representative operating conditions, or hydrocarbon dew point. The standard considers spot, composite, continuous, and d. Inappropriate analytical methods. mobile sampling systems. This standard does not include Analyses from samples can be utilized in many different sampling of liquid streams. ways, including the following: This standard includes comments identifying special areas of concern or importance for each sampling method included. a. Calculations to determine the heating value, volumetric It is intended for custody transfer measurement systems and ßow rate, total energy, density, viscosity, hydrocarbon dew may be applicable to allocation measurement systems. point, and compressibility. The accuracy of moisture determinations from samples b. Calculations to determine the gallons per thousand stan- collected using the recommendations in this standard has not dard cubic feet (liters per cubic meter) of recoverable liquid been determined. product from the stream. This standard does not include sampling multi-phase ßow c. IdentiÞcation of contaminants contained in the gas stream. (free liquid and gas). d. Compositional information used for process design and to determine whether the stream meets contractual 14.1.3 Referenced Publications speciÞcations. The current editions of the following standards, codes, and This standard incorporates guidelines and recommenda- speciÞcations are cited in this standard: tions for obtaining representative samples safely. It should be useful as a resource document for training programs as well. ASTM1 This standard attempts to consider both sweet and sour gas D 1142 Standard Test Method for Water Vapor streams as well as high- and low-pressure applications. Content of Gaseous Fuels by Measurement Streams at or above the hydrocarbon dew point temperature, of Dew-Point Temperature and streams that may contain water vapor up to the point of saturation are addressed. DOT2 It is not the intent of this standard to recommend particular equipment suppliers or manufacturers. 49 Code of Federal Regulations Although economic, regulatory, compositional, and con- 1American Society for Testing Materials, 100 Barr Harbor Drive, tractual considerations must always be evaluated and identi- West Conshohoken, Pennsylvania, 19428-2959. Þed, samples should be collected on a ßow-proportional or 2U.S. Department of Transportation. The Code of Federal Regula- ßow-weighted basis whenever practical. Spot samples, by tions is available from U.S. Government Printing OfÞce, their nature, cannot fully represent a gas stream of varying Washington, D.C. 20001. 1COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 12. 2 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT GPA3 14.1.4.11 gas quality: Refers to physical characteristics determined by the composition (including non-hydrocarbon Std 2166 Obtaining Natural Gas Samples for Analy- components, speciÞc gravity, heating value and dew points) sis by Gas Chromatography of the natural gas mixture. Std 2261 Analysis for Natural Gas and Similar Gas- eous Mixtures by Gas Chromatography 14.1.4.12 hydrocarbon dew point: A temperature at a given pressure at which hydrocarbon vapor condensation NACE4 begins. MR-01-75 SulÞde Stress Cracking Resistant Metallic 14.1.4.13 lag time in a sample system: The time Materials for OilÞeld Equipment required for a molecule to migrate from the inlet of the sam- ple probe to the inlet of an analyzer. 14.1.4.14 mobile sampling system: The system asso- 14.1.4 Definitions ciated with a portable gas chromatograph. 14.1.4.1 absorption: Occurs when natural gas constitu- 14.1.4.15 multi phase flow: DeÞned as two or more ents are dissolved into a liquid or solid that is not considered phases (see 14.1.4.18) in the stream. to be the mixtureÕs liquid phase. 14.1.4.16 normal condensation: Caused by an 14.1.4.2 adsorption: Occurs when a thin Þlm of mole- increase in pressure or a decrease in temperature. cules adheres to a liquid or solid surface. 14.1.4.17 normal vaporization: Caused by a decrease 14.1.4.3 chilled mirror test: Used to determine dew in pressure or an increase in temperature. points (water and/or hydrocarbon) by passing the natural gas over a mirror while gradually reducing the temperature of the 14.1.4.18 phase: A physical state of a compound (e.g., mirror until condensation forms. solid, liquid, or gas). Each phase has a distinct molecular arrangement and can be readily identiÞed (like the two phases 14.1.4.4 continuous sampling systems: Provide for of H2O in ice waterÑsolid and liquid). an uninterrupted ßow of sample. 14.1.4.19 phase behavior: Refers to the condensation 14.1.4.5 de-sorption: Occurs when adsorbed or and vaporization characteristics of a hydrocarbon mixture. It absorbed molecules are released from a liquid or solid sur- includes considerations such as temperature, pressure, com- face. position, relative amounts of the liquid and gas phases. 14.1.4.6 extension tube (“pigtail”): A piece of tubing 14.1.4.20 pitot probe: An impact device with an inlet placed on the end of a sample container used to move the and return port that provides ßow to a hot loop by converting point of pressure drop (point of cooling) away from the sam- velocity into a differential pressure. ple being acquired. See GPA Standard 2166. 14.1.4.21 re-circulation region (“eddy”): An area 14.1.4.7 floating piston cylinder: A container which within a piping system where gas is not continually being has a moving piston that has its forces balanced by a pre- replaced even though gas is ßowing through the system. charge pressure. 14.1.4.22 representative gas sample: Composition- 14.1.4.8 flow-proportional composite sampling: ally identical, or as near to identical, as possible to the sample source stream. The process of collecting gas over a period of time at a rate that is proportional to the pipeline ßow rate. 14.1.4.23 residual impurities: Any substances, such as air or natural gas components, that are left in a sample 14.1.4.9 gas sample distortion: Any effect that results cylinder. in a sample that is not representative of the gas stream. 14.1.4.24 retrograde condensation: Caused by a 14.1.4.10 gas sampling system: The system intended decrease in pressure or increase in temperature. to deliver a representative sample of natural gas from the pipeline to the analytical device. 14.1.4.25 retrograde vaporization: Caused by an increase in pressure or decrease in temperature. 3Gas Processors Association, 6526 E. 60th Street, Tulsa, Oklahoma 74145. 14.1.4.26 sample container: Any container used to 4National Association of Corrosion Engineers, 1440 South Creek hold a natural gas sample. Typical sample containers are con- Drive, Houston, Texas 77218-8340. stant volume cylinders or ßoating-piston cylinders.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 13. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 3 14.1.4.27 sample loop: Part of the sampling system that 14.1.5.1 INITIAL SAMPLING OF A GAS STREAM conveys the sample from the probe to the container or analyt- OF UNKNOWN HYDROCARBON DEW ical device. It is typically external to the analysis device. This POINT AND COMPOSITION should not be confused with the sample loop that is inside an analytical device such as a gas chromatograph. In order to properly apply the methods discussed in this standard, it is necessary to start with a reliable value for the 14.1.4.28 sample probe: A device extending through hydrocarbon dew point of the stream to be sampled. the meter tube or piping into the stream to be sampled. For initial sampling of a gas stream of unknown composi- 14.1.4.29 sample source: Refers to the stream being tion, the following techniques are recommended in order of sampled. preference: 14.1.4.30 sampling separator: A device in the sam- ¥ Measure the hydrocarbon dew point temperature and pling system used to collect free liquids. maintain the sample gas temperature above the mea- sured hydrocarbon dew point temperature. NOTE: 14.1.4.31 single-phase flow: Natural gas ßowing at a ASTM D 1142, Standard Test Method for Water Vapor temperature above the hydrocarbon dew point and free of Content of Gaseous Fuels by Measurement of Dew- compressor oil, water, or other liquid or solid contaminants in Point Temperature, recommends that the sample should the ßow stream. be 3¡F (1.7¡C) above the dew point. For the purposes 14.1.4.32 slip stream (“hot loop” or “speed loop”): of this standard, the sample should be maintained Provides for a continuous ßow of sample. according to the recommendations in Section 14.1.6.6, General Discussion of Heating. 14.1.4.33 water dew point: The temperature at a spe- ciÞc pressure where water vapor condensation begins. When the hydrocarbon dew point temperature is not measured, 14.1.5 Hydrocarbon Dew Point ¥ use a constant pressure spot sampling method while The hydrocarbon dew point is a temperature at a given maintaining the sample gas temperature at or above pressure at which hydrocarbon vapor condensation begins. the ßowing gas temperature, perform an extended In general, when the sample system is kept above the analysis, and calculate the hydrocarbon dew point hydrocarbon dew point temperature, all methods, when temperature, or properly applied, can provide a sample that is representative ¥ use a pressure-reducing sampling method, perform an of the sample source. However, it is difÞcult (or nearly extended analysis, and calculate the hydrocarbon dew impossible) to obtain accurate and repeatable results when point temperature (when using a sampling method the temperature of any element of the sample system falls involving a pressure reduction, provide sufÞcient heat, below the hydrocarbon dew point temperature, or when sampling a stream with a temperature near the hydrocarbon at, or prior to, the point of pressure reduction, to offset dew point. the Joule-Thomson effect) or, The hydrocarbon dew point for a particular gas changes ¥ use historical information, such as analyses or dew with temperature and pressure. Because the hydrocarbon dew point measurements from a similar gas source or, point is not constant for all pressures and temperatures, the proper application of the methods in this standard may ¥ take a sample, heat the sample gas to 140¡F (60¡C), require the use of a phase diagram. The phase diagram is par- perform an extended analysis, and calculate the hydro- ticularly useful when the pressure or temperature of the gas carbon dew point temperature. changes during the sampling process. This tool is discussed in detail in Appendix A. Once the calculated hydrocarbon dew point temperature is known, maintain the sample gas temperature 20Ð50¡F (11Ð For purposes of this standard, the Soave-Redlich-Kwong (SRK) method of hydrocarbon dew point calculation using 28¡C) above the hydrocarbon dew point temperature as dis- compositions from an extended analysis (C9+) was used. Var- cussed in 14.1.6.6, General Discussion of Heating. ious computer programs are capable of calculating the hydro- If the stream changes composition, pressure, or tempera- carbon dew point temperature at various pressures. The ture, or if there is an indication that the hydrocarbon dew accuracy of the calculated hydrocarbon dew point tempera- point has changed, repeat this process to ensure that the ture depends on the calculation method used and on the accu- hydrocarbon dew point is known and that the gas temperature racy of the gas composition that is entered into the computer is maintained in the sampling system according to 14.1.6.6, program. General Discussion of Heating.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 14. 4 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT 14.1.6 General Considerations for the Natural Gas Streams. Also see Appendix B, Fluid Mechani- Design of a Natural Gas Sampling cal Considerations in Gas Sampling for a detailed discus- System sion of ßuid mechanics. Users are cautioned not to interpret liquids condensed by The main consideration in the design of a natural gas sam- the metering or sampling system as free liquids ßowing pling system is to deliver a representative sample of the gas through the pipeline. from the sample source to an analytical device. Issues that should be addressed when designing a sampling 14.1.6.2.2 Single-Phase Flow system include: expected gas quality, phase-change charac- teristics, type of sample/analysis, material to be used for sam- Single-phase ßow is natural gas ßowing at a temperature ple delivery, ambient condition extremes, cleanliness, above the hydrocarbon dew point and free of compressor oil, availability of power, ßow rate, and transport time. water, or other contaminants in the ßowing sample source Further consideration should be given to the presence of stream. In general, it is preferred that the single phase gas in inert compounds such as carbon dioxide (CO2) or nitrogen the pipeline be in the turbulent ßow regime, because the ßuid (N2). These compounds will not only impact the heating turbulence creates a well-mixed, representative ßuid. value and density of the gas, they also may determine the gas chromatograph carrier gas needed and whether or not the 14.1.6.3 CAUSES OF GAS SAMPLE DISTORTION stream meets contractual speciÞcations. Since natural gas is a mixture of organic and inorganic pure gases, its integrity will be sacriÞced if any components of the 14.1.6.1 THE COMPONENTS OF TYPICAL sample gas are depleted or augmented (e.g., air-contamina- SAMPLING SYSTEMS tion, de-sorption of hydrocarbons). This section identiÞes Spot and composite sampling methods require the use of a fundamental mechanisms of sample distortion. An under- sample container to transport the sample from the Þeld loca- standing of these mechanisms will reduce the likelihood of tion to the laboratory. Examples are shown in Figures 1a and poorly designed sampling systems. 1b. Figure 1a is an example of a spot sampling apparatus It is important to recognize that only sample collection dis- employing the purging-Þll and empty method. Figure 1b is an tortion mechanisms are identiÞed in this section. Poor gas example of an application using a composite sampler. analysis techniques can also distort the indicated composition Figure 2 shows the components in a continuous sampling (see 14.1.16, Guidelines for Analysis). system or mobile sampling system. For speciÞc details regarding the design of these sys- 14.1.6.3.1 Phase Changes tems, see 14.1.7, Sample Probes, 14.1.8, Sample Loops/ Condensation and revaporization of hydrocarbons within Lines, 14.1.9, Sample Containers, and 14.1.13, Automatic the sampling system can cause signiÞcant distortions in a gas Sampling. sample. These types of sample distortions can occur under For details regarding the heating and insulating of sam- both ßowing and non-ßowing conditions (i.e., in a ßowing pling systems, see Section 14.1.6.6, General Discussion of sample delivery system or in sample containers), or if the Heating. sample comes in contact with sampling equipment that is below the hydrocarbon dew point. See Appendix A, The 14.1.6.2 FLOW CHARACTERISTICS Phase Diagram, for a detailed discussion of the thermody- 14.1.6.2.1 General namics of these phase changes. Accurate sampling from gas streams with temperatures at Piping elements, such as valves and oriÞces, can create the hydrocarbon dew point temperature is more difÞcult than re-circulation regions (eddies) in the ßowing sample source sampling from streams with temperatures above the hydro- stream. The gas composition in these eddies may be mea- carbon dew point temperature. Additionally, depending on the surably different from the gas composition of the bulk ßow. pipeline pressure, retrograde condensation may occur if the The gas downstream of a gas-liquid separator will be near pressure is reduced. Some gas mixtures will have a hydrocar- its hydrocarbon dew point, and a reduction in line tempera- bon dew point that is high enough to cause condensation at ture will likely cause some condensation to occur. In other ambient temperatures commonly experienced during the cases, a pipeline may be operating with both gas and liquid year. If condensation does occur, and only the gaseous phase continually present in the pipe. Obtaining an accurate gas of the partially condensed sample is analyzed, the heating sample under these conditions is difÞcult and outside the value and density of the sample will be incorrect. Further- scope of this standard. See Appendix C, Lessons Learned more, the remaining sample will no longer be representative During Sampling in Hydrocarbon Saturated and 2-Phase of the sample source.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 15. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 5 Composite sampler (see 14.1.13.1) Sample container (see 14.1.9) Pipeline Figure 1a Figure 1b Sample probe (see 14.1.7) “Pigtail” (see 14.1.12.11) Purge valve and drilled plug assembly (see 14.1.12.11) Note: Insulation and heat tracing are not shown. See 14.1.6.6, General Discussion of Heating for gas temperature requirements. Figure 1a—Typical Spot Sampling System Figure 1b—Typical Composite Sampling SystemCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 16. 6 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT Heated enclosure (if necessary) (see 14.1.6.6) Filter Sample line (see 14.1.8.6) (see 14.1.8) Regulator Analytical (see 14.1.8.4) Device Heat tracing (if necessary) (see 14.1.6.6) Carrier gas Sample probe Calibration (see 14.1.7) gas Pipeline Figure 2—Typical Continuous (On-Line) Sampling System/Mobile Sampling System The integrity of gas samples (and calibration standards) avoid condensation if the sample gas temperature is main- with condensed components can be recovered by revaporiz- tained above the hydrocarbon dew point. The gas temperature ing the condensed liquids, provided that no ßuid (gas or liq- must be high enough to offset the reduction in temperature uid) has been released from the sample container prior to associated with the pressure reduction (path 1Ð3, Figure 3). revaporization. See 14.1.6.4, Revaporization, and Appendix See Section 14.1.6.6, General Discussion of Heating and A, The Phase Diagram. Appendix A, The Phase Diagram, for further information. 14.1.6.3.1.1 Flowing and Sampling Conditions 14.1.6.3.1.2 Sample Conditions A gas sample ßowing through a sampling system may When a non-ßowing gas sample, such as a sample con- experience temperature and pressure changes. Pressure and tained in a sample cylinder, is subjected to a temperature temperature reductions occur when the gas accelerates below the hydrocarbon dew point temperature, condensation through tubing elements within the sampling system. If the (and, therefore, sample distortion) will occur. gas is near the hydrocarbon dew point, condensation may A gas sample could condense in the sample cylinder occur, causing gas sample distortion. It is important to be while it is being transported or awaiting analysis in a labora- aware of the Þttings and elements within a ßowing sampling tory. Consider a natural gas with the phase diagram shown system, particularly those that cause signiÞcant pressure drop. in Figure 3 and contained within a sample cylinder. Path 4Ð For example, consider natural gas ßowing through a 5 shows that the sample can condense if the cylinder is restriction such as a partially closed valve or regulator. If the exposed to an ambient temperature below the hydrocarbon hydrocarbon dew point curve for a gas being sampled is rep- dew point temperature. resented by Figure 3, condensation could occur as the pres- If it is necessary to transfer a small representative sample sure of the gas is reduced from 1500 psia to 900 psia (10.3 from a large accumulator, care must be taken to insure that MPaabs to 6.2 MPaabs) (path 1Ð2, Figure 3). It is possible to any condensation that may have occurred has been revapor-COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 17. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 7 kPa psia – 2000 – Composition 13000 1900 – Supercritical N2 = 2.05533 – Path 1–2: Retrograde condensation during throttling to a Fluid CO2 = 0.5132 12000 1800 – lower pressure. No or not enough heat tracing on sample line. C1 = 82.6882 – 1700 – Path 1–3: Heat tracing can offset the cooling which occurs C2 = 6.9665 11000 during the throttling process, thereby avoiding condensation. C3 = 4.5441 1600 – – i-C4 = 1.1559 1500 – (See 14.1.6.6, General Discussion of Heating) 10000 n-C4 = 1.2856 1400 – 1 i-C5 = 0.3983 – 9000 Liquid 2-Phase nC5 = 0.2624 1300 – Region C6 = 0.0836 – 1200 – Pressure 8000 Critical C7 = 0.0273 Region Vapor C8 = 0.0167 – 1100 – 7000 C9 = 0.0009 1000 – – 6000 900 – 2 3 – 800 – 5000 4 700 – – 600 – 5 4000 Condensation due to constant pressure Condensation that occurs when a sampling with sample or calibration standard is 500 – exposed to ambient temperatures – 3000 Tcylinder < THC dew below the hydrocarbon dew point 400 – This can occur during constant pressure temperature. – 300 – and water/glycol displacement sampling. 2000 200 – 7 6 – 1000 100 – – 0– –200 –180 –160 –140 –120 –100 –80 –60 –40 –20 –0 20 40 60 80 100 120 140 °F –120 –100 –80 –60 –40 –20 –0 20 40 60 °C Temperature Figure 3—Examples of Thermodynamic Processes Associated with Sampling System Design and Sampling Methods ized prior to and during transfer and that the sample is well 3. If the temperature of the sampling equipment is below the mixed. This is not a recommended practice because it is very hydrocarbon dew point temperature, condensation can occur difÞcult to transfer a representative sample from one cylinder even when sampling at constant pressure (path 6Ð7). See Sec- to another if the gas is at or near the hydrocarbon dew point. tion 14.1.6.6, General Discussion of Heating, and Appendix Gas sample containers and the lines to an analysis device A, The Phase Diagram, for further information. should always be heated prior to analysis. Heating times and temperatures should be sufÞcient to ensure that any 14.1.6.3.2 Surface Effects condensed hydrocarbons are revaporized before an analysis is started. See Section 14.1.6.6, General Discussion of There are three important surface effects that have been Heating, and Appendix A, The Phase Diagram, for further identiÞed for gas sampling. information. 1. Clean, solid surfaces are subject to adsorption (stick- ing) and de-sorption (unsticking) of gas molecules. 14.1.6.3.1.3 Cold Sampling Equipment 2. Some liquids may dissolve gas molecules, or they may If the sample stream comes in contact with sampling yield certain gas molecules if the liquid already contains equipment that is at a temperature below the hydrocarbon signiÞcant amounts of dissolved gas molecules. dew point, condensation, and therefore, sample distortion can occur. Consider the natural gas mixture represented by Figure 3. Porous surfaces can cause gas sample distortions.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 18. 8 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT The Þrst two effects tend towards an equilibrium that is 14.1.6.3.3 Residual Impurities dependent on pressure and temperature. If the temperature and/or pressure of the sampling system changes, hydrocar- Gas sample distortion can be caused by residual impuri- ties such as air or previous samples and they may be difÞ- bons could be removed from or released into the sample cult to detect. For example, a gas chromatograph not stream. This will cause an incorrect determination of heating conÞgured to detect oxygen will show a residual of air as value and density. increased nitrogen. This type of impurity might not be Sampling systems should incorporate clean, inert and non- detected. If a small amount of the previous gas sample was porous materials and sufÞcient temperature control to remain left in the sampling system or sample container, it might not above the hydrocarbon dew point if the surface effect errors be detected either. are to be avoided. Strategies for removing residual impurities involve See sections 14.1.6.5, Cleanliness, 14.1.8.3, Tubing Mate- purging, evacuating and repeated Þll/empty cycles. Sample rials, 14.1.6.6, General Discussion of Heating, 14.1.10, distortion due to the presence of residual impurities may Materials for Sweet and Sour Gas Service, and Appendix A, be a problem if any of these methods are performed The Phase Diagram, for further information. poorly. If there are leaks in any valves or seals these meth- ods may not work, even if the procedures are performed 14.1.6.3.2.1 Adsorption correctly. Adsorption occurs both chemically and physically. Chemi- 14.1.6.4 REVAPORIZATION cal adsorption is due to a reaction between the gas molecules and the solid surface molecules. Phase Changes, Section 14.1.6.3.1, identiÞes a phase Physical adsorption occurs because free surfaces, such as change as one cause of gas sample distortion. This type of the inner surfaces of tubing or sample containers, tend to sample distortion will have a signiÞcant impact on the integ- attract gas phase molecules. For a given surface and gas mol- rity of the gas sample. ecule, the extent of physical adsorption depends on the If the gas phase of a partially condensed sample contained amount of surface area and the pressure and temperature. in a sample container is analyzed, the heating value and den- Changing the pressure and/or temperature could either adsorb sity of the sample will be biased and the remaining sample or de-sorb gas molecules. will no longer be representative of the sample source. Sample distortion due to chemical and physical adsorp- If a gas chromatographÕs calibration gas standard experi- tion can be minimized by prudent selection of sampling sys- ences a phase change and calibration occurs while the cali- tem materials. In general, materials and coatings that are bration gas is still in two phases, all analyses performed from chemically inert and of minimum porosity are the best that point forward will be biased. Furthermore, the composi- choices. tion of the calibration gas standard will have changed. The integrity of the sample (and the calibration standard) 14.1.6.3.2.2 Liquid/Gas Interfaces can be recovered by heating the containers if no ßuid (gas or liquid) is withdrawn prior to revaporization. Care must be Another surface effect that causes gas sample distortion taken to ensure that all condensed gases are revaporized when occurs between gas molecules and the surfaces of some liq- a gas sample is analyzed in a laboratory. uids. Hydrocarbon liquids can dissolve signiÞcant amounts of Section 14.1.6.6, General Discussion of Heating, pro- natural gas components. This is especially important if the vides guidelines for heating samples and calibration stan- sampling system or sample container has been exposed to liq- dards, and for revaporizing condensed samples and uid hydrocarbons. calibration standards. Proper cleaning procedures will minimize the potential for this problem. See 14.1.6.5, Cleanliness. 14.1.6.5 CLEANLINESS The impact of liquid hydrocarbon residues is discussed in 14.1.6.3.2.3 Plastic Tubing 14.1.6.3.2.2, Liquid/Gas Interfaces. Proper cleaning proce- With the exception of Nylon 11 or equivalent, most plastic dures must be followed in order to remove liquid hydrocar- tubing tends to cause gas sample distortion and is not recom- bon residues and other impurities (e.g., water or glycol mended as a gas sample conduit for hydrocarbon analysis. residue) that may exist. Sample systems should be designed so that they may be CAUTION: Be careful not to apply direct heat or high tem- thoroughly and easily cleaned. A procedure for cleaning sam- perature heat tracing to any plastic tubing, including ple systems and sample containers is essential for good gas Nylon 11. sampling practices.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 19. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 9 Sample containers must be purged and cleaned prior to its secondary components (e.g., valves, Þttings or relief each collection of sample, unless they are special passivated devices) should be non-reactive to sulfur or sulfur-contain- cylinders used to sample streams containing highly reactive ing compounds. components. The most effective cleaning agent is wet steam. Note: Interaction with water and other components present in the Steam cleaning is acceptable only if the steam is clean and sample gas may degrade the sulfur content regardless of the cylinder does not contain corrosion inhibitors, boiler water treating material. The sample loop, including any separator in the system, chemicals or other substances that may contaminate the sam- must be thoroughly purged and be cleared of contaminants and ple cylinder. accumulated liquids prior to sample collection. Solvents, such as acetone and liquid propane, that do not leave a residue after drying are generally acceptable for 14.1.6.6 GENERAL DISCUSSION OF HEATING removing most heavy ends contamination, although they may Condensation may occur in composite, spot, mobile or on- sometimes present hazards such as ßammability and toxicity. line sampling systems. If any part of the sampling process Decon Contrad¨ 70 washing also produces acceptable results causes the sample to fall below the hydrocarbon dew point, that compare well to the solvents. Other solvents chemically scattered and biased analytical results and non-representative equivalent to Decon Contrad¨ 70 can reasonably be expected samples are likely to result. In order to avoid this problem, the to produce acceptable results, however, their effectiveness sample gas temperature must remain above the gas hydrocar- must be tested prior to use. bon dew point during sampling. This can be accomplished by Supercritical carbon dioxide cleaning produces acceptable heating sample probes and by heat tracing lines, regulators results, in spite of the fact that some dirty hydrocarbon spot and sample cylinders or by employing some other means of trails may be left in the cylinder after it is cleaned. delivering heat to the ßuid in the sampling system. Due to the uncertainty in measuring or calculating the WARNING: Using supercritical carbon dioxide to clean hydrocarbon dew point, it is recommended that the gas being cylinders can be hazardous due to the physical properties sampled be maintained at 20Ð50¡F (11Ð28¡C) above the of the ßuid and the high pressures and low temperatures expected hydrocarbon dew point throughout the sampling involved and should be used with great caution. system. If ambient temperatures are above the hydrocarbon dew point, heating may not be required. When the sampling process involves a pressure reduction, provide sufÞcient heat Sample containers must be dried and purged after wet at or prior to, the point of pressure reduction to offset the cleaning procedures (e.g., wet steam). Evacuating the cylin- Joule-Thomson effect (approximately 7¡F (3.9¡C) per 100 psi der to 1 millimeter of mercury absolute (133 Paabs) (near (690 kPa) of pressure reduction). perfect vacuum) or less will eliminate the residual liquid. Nitrogen, helium and dry instrument quality air are good 14.1.6.6.1 Heat Tracing examples of gases that may be used to dry or purge cylin- ders that are free of deposits and heavy hydrocarbon con- Heat tracing methods most commonly used are steam, hot tamination. water and electrical. Many laboratories leave a blanket of nitrogen, helium or Electrical heat tracing is normally used in remote locations other gases in sample cylinders in order to protect the cylin- or in locations where it is difÞcult to use steam or hot water. der from air contamination. Blanket gases and gases used to Electrical heat tape should be self-limiting or controlled with pre-charge sample cylinders must be carefully selected so temperature-limiting devices. that, should leakage occur within the cylinder or should the Electrical heat tracing and all electrical equipment sample be contaminated by these gases, the chromatograph must meet the electrical codes for the intended service will not interpret the contamination as a part of the sample area. These requirements ensure that a heating element being analyzed. For example, a chromatograph using helium does not overheat if a failure in the electrical components as a carrier gas will not detect helium gas left over from the occurs. Overheated electrical components could cause pre-charge of a single cavity cylinder or helium leaking by injury or an explosion in a natural gas application. the piston in a constant pressure cylinder. Sampling systems on residue gas lines on the outlet of gas Many sulfur species will be readily absorbed by general plants should be heat traced to insure that liquids do not con- purpose sample cylinders. The resulting analysis will dra- dense in the sample system during plant upsets. Once these matically understate sulfur levels. Samples to be analyzed liquids accumulate in a sampling system, it may take days for sulfur content need to be collected in clean and dry spe- after the process is operating normally before representative cially-lined or passivated cylinders dedicated for that pur- samples are collected from the system. Purging the entire sys- pose. The entire wetted surface of the sample container and tem may be required.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 20. 10 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT 14.1.6.6.2 Catalytic Heater psi [690 kPa] of pressure reduction). If necessary, heat the regulator or regulating probe and the associated tubing A catalytic heater produces heat through an exothermal (where exposed to ambient conditions) to maintain the gas reaction between a combustible gas, such as natural gas, oxy- temperature 20Ð50¡F (11Ð28¡C) above the calculated hydro- gen and a catalyst. The heat given off by the reaction can be carbon dew point temperature. adjusted by varying the rate of gas ßow to the catalyst. The heat released by the reaction is well below the ignition tem- 14.1.6.6.6 Composite Sampling Systems perature of the natural gas. Electrical heat tracing and all electrical equipment It is recommended that these systems, including the sample must meet the electrical codes for the intended service container, be maintained above the hydrocarbon dew point to area. These requirements ensure that a heating element ensure the composite sample is representative of the ßowing does not overheat if a failure in the electrical components gas stream. Tests conducted under actual Þeld operating con- occurs. Overheated electrical components could cause ditions have shown that composite sampling systems do not injury or an explosion in a natural gas application. consistently provide representative samples when exposed to ambient temperatures below the sample gas hydrocarbon dew 14.1.6.6.3 Insulation point. Insulation is used to protect the ßowing stream from cold Note: No tests were conducted with sample containers below the ambient conditions or covering heat tracing around the exter- hydrocarbon dew point and all other components of the composite sampling system above the hydrocarbon dew point. nal portions of the probe assembly, regulator and sample line. It will help ensure that the stream being sampled 14.1.6.6.7 Calibration Standards remains above the hydrocarbon dew point during the sam- pling process. The calibration standard shall be heated for a minimum period of 4 hours after the skin temperature of the cylinder 14.1.6.6.4 Sample Containers reaches a temperature 20¡F (11.1¡C) above the calculated hydrocarbon dew point. The intent of this requirement is to During sampling, the cylinder temperature must be kept ensure that the core temperature of the calibration standard above the hydrocarbon dew point. If the sample cylinder is has reached a temperature of at least 20¡F (11.1¡C) above the exposed to temperatures below the hydrocarbon dew point calculated hydrocarbon dew point of the calibration gas. after the sample has been collected, the sample can be recov- Vaporization of the heavy components will occur more rap- ered by heating it to 140¡F (60¡C) or 20Ð50¡F (11Ð28¡C) idly at higher temperatures above the calculated hydrocarbon above the dew point, whichever is lower, and maintained at dew point. It is generally not necessary to exceed 50¡F that temperature for at least 2 hours prior to analysis. (27.8¡C) above the calculated hydrocarbon dew point. Heat- Sample containers can be heated using a water bath, heat- ing the calibration standard for a longer period or continu- ing blankets, heat tape or a heated chamber as long as the ously will not cause deterioration of the standard. The sample temperature of the heating medium is controlled. Heat lamps lines from the calibration standard to the chromatograph and and similar devices are not recommended since it is difÞcult any regulators in the system must also be maintained at a tem- to control the temperature of the cylinder. Any method used perature at least 20¡F (11.1¡C) above the calculated hydrocar- for heating the sample cylinders must meet the require- bon dew point. ments of all applicable codes and regulations. For details regarding condensation and vaporization of nat- It is not anticipated that sample cylinders will need to be ural gas, see 14.1.6.3, Causes of Gas Sample Distortion, and heated above 140¡F (60¡C), but, if a special condition exists, Appendix A, The Phase Diagram. special care must be taken to not overpressure the cylinder and to consider the effect of the heat on seals and other mate- 14.1.7 Sample Probes rials in the entire sample container assembly. Use the label to verify that the contents of the container will not overpressure 14.1.7.1 GENERAL DESIGN CONSIDERATIONS the sample cylinder when heated. Exercise care to avoid heat- Sample probes are designed for the purpose of directing a ing cylinders Þlled with liquids, as the cylinder may be over- representative portion of the natural gas sample source in the pressured. pipeline to the sampling system. The probe extends into the pipeline to ensure a representative sample that is free of 14.1.6.6.5 Pressure Regulators and Regulating unwanted contaminants that may have collected on the inte- Probes rior pipe wall. Sample probes may be designed as Þxed or as The gas temperature must be maintained at a temperature insertable and retractable units. The probe and associated high enough to offset the reduction in temperature associated valving should not restrict the sample outlet ßow. A well- with pressure regulation (approximately 7¡F [3.9¡C] per 100 designed sampling system requires the use of a properlyCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 21. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 11 installed sample probe. There are several designs of sample 14.1.6.6, General Discussion of Heating, 14.1.6.3, Causes probes available. Each design has its own advantages and dis- of Gas Sample Distortion, and Appendix A, The Phase Dia- advantages. The design must also consider the possibility of gram, for further information. resonant vibration being induced in the probe by high ßowing velocities in the pipeline. Gas lines with streams free of 14.1.7.3.3 Pitot Probes/Dual Probes entrained liquids and at ßowing conditions well above their A Pitot probe can be used, provided the gas velocity in the dew point temperatures may be sampled with any probe pipeline is sufÞcient to drive the ßow throughout the entire design. Lines that are operating at or near the gas streamÕs loop, or two straight tube probes can be installed across a dif- dew point may require special probes designed to overcome ferential pressure point, assuring ßow throughout the system. the problems of condensation in the gas. In selecting a sample probe, the Þrst step is to determine sampling conditions and Note: Adequate data is not available to make recommendations then to determine the proper sample probe for the application. regarding the performance of Pitot probes. See Section 14.1.6, General Considerations for the Design of a Natural Gas Sampling System. 14.1.7.4 PROBE INSTALLATION 14.1.7.4.1 Location 14.1.7.2 APPLICATION A probe conÞguration such as discussed in 14.1.7.3, Types, Sample probes and other components of sampling systems should be used for all sampling techniques. It is industry must be designed to deliver a representative sample of the practice that the collection end of the probe be placed within sample source. the approximate center one-third of the pipe cross-section. For larger line sizes, probe lengths in excess of 10 inches 14.1.7.3 TYPES (0.25 m) shall not be required. This position separates the 14.1.7.3.1 Straight Tube Probes probe inlet from the pipe wall (the area most likely to contain migrating liquids). The most basic sample probe design is the straight tube probe shown in Figure 4. The probe may be attached to a CAUTION: When the velocity of the ßowing stream exceeds Þxed coupling assembly or to one that allows the probe to be approximately 30 ft/s (9.1 m/s), special attention should be removed completely. All Þttings installed in the sampling sys- given to ensuring that the mechanical design of the probe is tem should be non-restrictive and must be rated for the sufÞcient to prevent harmonic oscillations from causing the intended line pressure and temperature. The materials must probe to fail, potentially damaging downstream equipment. be suitable for use with the product, its contaminants and Clean, dry gas systems free of any liquids can be sampled ambient conditions. ModiÞcations to this basic design are at any location; however, it is prudent to recognize that Þeld numerous. Filters and screens added to the collecting end of installations are subject to changes in ßowing conditions and the probe may reduce the possibility of small liquid particles composition without notice. The probe location in the center entering the probe. This practice must not alter the composi- one-third of the pipeline is common practice and will help to tion of the sampled gas. Some Þlters or screens may encour- avoid many of the problems encountered by such potential age the creation of liquids not otherwise present in the stream. changes. For ßowing streams that are not near their hydrocar- Inappropriate probes or Þlters could alter gas streams that are bon dew point, the probe should be positioned either very close to the hydrocarbon dew point. The collection end upstream or downstream of the meter tube, and at least 5D of the probe may be straight or angle-cut. downstream of any ßow disturbing elements, such as elbows, swirl generators, headers, valves and tees. If the sample 14.1.7.3.2 Regulating Probes source is at or near its hydrocarbon dew point, some research has indicated that the probe should be located at least 8 pipe Regulating probes are commonly used with continuous diameters downstream of any ßow disturbance, including an sampling systems designed to deliver gas to the sampling oriÞce meter. Sample probes should be located on the top of system at reduced pressure. An illustration of a typical the pipeline to discourage the ingestion of liquids. Probes and probe is shown in Figure 5. The probeÕs most basic form is a the related tubing should be installed so that liquids will not straight tube with an integral regulating mechanism. If ret- accumulate in the probe or the sample lines. rograde condensation is possible, then condensation of the sample gas could occur in the probe after the pressure is Note: Probes should not be installed in any Òdead-endÓ section reduced, and a non-representative sample will result. Fins of pipe, where gas is not continually ßowing or where there may be used on the probe to improve heat transfer with the may be recirculation regions or Òeddies.Ó See Section 14.1.6.2, Flow Characteristics, Appendix B, Fluid Mechanical Consider- sample gas to prevent condensation. Care must be taken to ations in Gas Sampling, and Appendix C, Lessons Learned During minimize the effect of thermally coupling the probe to the Sampling in Hydrocarbon Saturated and 2-Phase Streams, for pipe carrying the sample source stream. See sections more information.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 22. 12 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT Pressure regulating screw Figure 4—Straight Tube Sample Probe Diaphragm Connecting rod Heat exchange Pressure reducing portion port Figure 5—Typical Regulated Sample ProbeCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 23. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 13 14.1.8 Sample Loops/Lines amount of components retained or released depends on their concentration in the sample gas, the sample loop tempera- 14.1.8.1 GENERAL DESIGN CONSIDERATIONS ture, the ßowing pressure and the amount of the tubing The sample loop (slip stream) is the part of the sampling coated with oil. system that delivers the gas from the sample probe to the inlet Nylon 11 tubing, or an equivalent, can be used effectively of the analysis device and then to a lower pressure point. in certain applications where excessive heat is not required. It Sample loops should be designed to deliver a representative is particularly useful when checking for the presence of free sample of the sample source gas that is ßowing in the pipe- liquids. The sample loop must be cleaned if free liquids have line. The velocity of the gas ßowing in the sample line and the or are suspected to have contaminated the system (see Section volume of the sample system determine how often a new rep- 14.1.6.5, Cleanliness). resentative sample can be obtained. It is preferred that the sample line be sloped upward from the sample probe to the 14.1.8.4 PRESSURE REGULATORS sample extraction point. This will minimize the accumulation Pressure regulators are often required at the point where of liquid in the loop. the gas sample is withdrawn from the sample loop, to reduce In order to obtain a representative sample, the loop must be the gas pressure from pipeline pressure to a usable pressure designed to ensure that the volume of gas in the sample loop for the sample container or analysis device. Specialized pres- is replaced between samples. This requires the sample loop sure regulators that are inserted into the pipeline to take ßow rate to be relatively high and the volume of the loop to be advantage of the ßowing gas temperature are available (see small. Excessively high ßow rates may cause liquid particles 14.1.7.3.2, Regulating Probes). Insertion type regulators that present in the pipeline to be drawn into the sample probe. incorporate integral Þltration to remove free liquids are also Sample loops that purge to the atmosphere can cause unac- available. Pressure regulators must have a pressure rating that ceptable amounts of gas waste and violate environmental reg- exceeds the maximum expected line pressure of the gas sam- ulations. In addition, a large pressure loss in a sample loop pling system. Regulators should be constructed of materials may cause cooling and condensation which will affect the that are not reactive with the gas being sampled. accuracy of the sample. Care must be taken when using any type of regulator, to ensure that the gas does not condense. Retrograde condensa- 14.1.8.2 PRESSURE DROP IN A SAMPLE LOOP tion may occur even if the gas is maintained at pipeline tem- Proper operation of a sample loop requires a pressure dif- perature. If the gas changes phase and condensation does ferential from the collection end to the discharge end. This occur, a representative sample will not be obtained. pressure differential may be produced with an oriÞce plate, One method of reducing the possibility of heavy end con- regulator, or pump. Attaching the ends of a sample loop densation in a pressure regulator is to use a heated regulator. across a ßow restriction will provide a pressure differential to This type of regulator should be designed to supply enough the sample loop that is proportional to the ßow rate squared. heat during the pressure reduction to avoid condensation. This arrangement will provide a ßow in the sample loop that Another method of reducing the possibility of condensation is is proportional to the ßow through the oriÞce. Custody trans- heat tracing. In general, the amount of heat energy required to fer meters cannot be used for this application because the offset the effect of the pressure drop will depend on the gas ßow through the sample loop will bypass the meter and result composition, pressure, temperature, pressure drop and hydro- in a biased ßow rate measurement. carbon dew point. The gas temperature must be maintained at a temperature high enough to offset the temperature reduction 14.1.8.3 TUBING MATERIALS associated with the pressure reduction. See sections 14.1.6.3, Causes of Gas Sample Distortion, 304 or 316 stainless steel tubing is the recommended mate- 14.1.6.6, General Discussion of Heating, and Appendix A, rial for the sample loop under most conditions. Other tubing The Phase Diagram, for further information. materials, such as Nylon 11 or an equivalent, can be used if the product sampled adversely effects or is effected by the 14.1.8.5 PUMPS stainless steel tubing. 1/16, 1/8, and 1/4 inch (1.59, 5.08, and 6.35 mm, respectively) stainless steel tubing have relatively Pumps may be used to provide sufÞcient gas ßow through small volumes per unit length that allow free liquids to be a sample loop. The pump should be installed to provide more easily swept out of the loop. If mechanical security is a steady ßow without signiÞcant pulsation or ßow interrup- concern, the tubing can be encased in larger tubing or pipe. tions. The pump produces the best results when it is installed All sample loop tubing must be steam cleaned and dried downstream of the sample container or analysis device. The before installation. Any oil left in the tubing from the manu- pump and the sample loop line size must be properly matched facturing process must be removed. This oil can retain or to assure that pump damage will not occur. The preferred release some of the heavier hydrocarbon components. The pump for the application is a centrifugal pump.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 24. 14 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT 14.1.8.6 FILTERS Particulate Þlters are used to remove solid, abrasive parti- cles from the sample source stream. This is primarily intended to protect the analysis equipment. Typical Þlter sizes are 2 to 7 microns (0.08 to 0.28 mils) and generally do not affect analytical results more than ±0.25%. Be sure to change Þlters regularly and insure condensation does not occur within them. Multiple streams, with different heating values, ßowing through the same Þlter, may cause sample distortion and should be avoided. 14.1.8.7 SEPARATORS The standard does not recommend the use of the separator referred to in the GPA Standard 2166 when sampling single- phase streams. Heat transfer may cause condensation or vaporization when the gas temperature is depressed below, or elevated above the hydrocarbon dew point. It should be noted that in streams outside the scope of this standard, GPA separators may be used to prevent free liquids from entering the section of the sampling system downstream of the separator. Refer to GPA Standard 2166 for guidance in the use of the separator. 14.1.9 Sample Containers 14.1.9.1 GENERAL DESIGN CONSIDERATIONS A sample container stores a gas sample in a protected and secure state until the gas composition can be determined. The container should not alter the gas composition in any way nor affect the proper collection of the gas sample. The materials, valves, seals, lubricants and other components of the sample container must all be speciÞed with this major consideration in mind. In addition to the mechanical compo- nents of the container, the cleaning, prior to each use, and handling of the container must be carefully performed to ensure that no contamination of the gas sample will occur. See 14.1.6.5, Cleanliness. Sample containers should be labeled with an identiÞcation number and maximum working pressure. If required, the date of the last physical inspection must either be included on a cylinder label or be Þled in readily accessible records. If the container is to be transported, it must meet U.S. DOT (CFR 49) speciÞcations. See 14.1.15, Safety, Labeling, Handling, and Transportation of Cylinders. 14.1.9.2 TYPES OF SAMPLE CONTAINERS A general description of sample containers may be found in the latest revision of GPA Standard 2166. 14.1.9.2.1 Single- and Double-Valve Standard Cylinders These cylinders are also known as constant volume cylin- ders, single cavity cylinders, and ÒspunÓ cylinders. An exam- Figure 6—Typical Double ple is shown in Figure 6. Valve Sample CylinderCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 25. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 15 Use sample containers that are designed to safely meet the within the cylinder. The use of guide rings is recommended anticipated operating extremes for their intended service and to ensure smooth piston travel. The piston and sealing are corrosion resistant to the product being sampled. Stainless device must be nonreactive to (a) the sample; (b) the back- steel containers are recommended to minimize problems of pressure gas; (c) the cleaning solvents; and (d) expected cor- absorption and/or adsorption of heavy components (hexanes rosive components in the gas. and heavier components) and to minimize the reaction of All valves and safety devices must meet the appropriate contaminants with the container. If the container is to be material and pressure requirements for safe design. The pres- transported, it must meet DOT speciÞcations and be labeled sure relief valves may be of spring or rupture-disc type. These according to DOT hazardous materials regulations and appli- allow a partial or complete loss of contents due to thermal cable state regulations. See 14.1.15, Safety, Labeling, Han- expansion or overpressurization. Should relieving occur, the dling, and Transportation of Cylinders. sample is likely to be compromised and must be discarded. The container may be of the one-valve or two-valve type Some piston-type cylinders are fabricated from nonmag- (depending upon the sampling procedure selected). Sample netic materials such as 300 Series Stainless Steel. The piston, containers and valves must have a working pressure equal to likewise, is fabricated of stainless steel, but has magnets or exceeding the maximum pressure anticipated in sampling, attached to the precharge side of the piston. As the piston storage or transportation of the sample container. Soft-seated moves the length of the cylinder, the magnetic Þeld generated valves are preferable to those having metal-to-metal seats. All by the magnets ßips a series of bicolored ßags. This system valves and safety devices must meet the appropriate material (or systems of similar conÞgurations) indicates the piston and pressure requirements for safe design. The pressure relief position and volume of sample in the cylinder. valves may be of spring or rupture-disc type. These allow a Some piston-type cylinders are fabricated with a rod partial or complete loss of contents due to thermal expansion attached to the piston that extends through the end cap on the or overpressurization. Should relieving occur, the sample is inert gas back-pressure chamber with appropriate sealing likely to be compromised and must be discarded. The size of devices to prevent the inert gas back-pressure from leaking. the container depends both upon the amount of sample The travel rod provides an indication of the piston position required for the laboratory tests that are to be made and the and the volume of the cylinder Þlled with the sample. Again, volume required to obtain a representative sample from com- some modiÞcations of this style may exist. posite sampling systems based on time or ßow. Smaller con- Some types of constant pressure cylinders are equipped tainers will be easier to handle. with electronic tracking devices to provide for local and/or remote indication of the pistonÕs position relative to full/ 14.1.9.2.2 Floating Piston Cylinders empty. Other types of ßoating piston cylinders are available which These cylinders are also known as constant pressure cylin- have no visual method of determining the sample volume ders. An example is shown in Figure 7. directly. For these cylinders, a magnet or some other type of A ßoating piston cylinder container is constructed of locating device is necessary to follow the movement of the metal tubing, honed and polished on the inside surface. The piston. cylinder should be closed with removable end caps to pro- vide access to remove and service the moving piston. The end caps are drilled and tapped for valves, gauges, and relief 14.1.10 Materials for Sweet and Sour Gas valves. The complete cylinder assembly must be designed to Service withstand the maximum pressure and temperature antici- 14.1.10.1 GENERAL CONSIDERATIONS pated during sampling, transportation and analysis and to be non-reactive to (a) materials being sampled; (b) the pressur- The types of materials used in a sample system will depend izing ßuid; (c) the cleaning solvents; and (d) the expected on the gas being sampled. Generally, it is recommended that corrosives. The volume of the cylinder will depend on the 304 or 316 stainless steels be used for all wetted surfaces. amount of sample needed for the laboratory analysis. If the Valve seats, O-rings and piston seals should be made of elas- container is to be transported, it must meet DOT speciÞca- tomers appropriate for the intended service. Sampling of H2S, tions and be labeled according to the federal hazardous CO2, wet- and high-temperature gases, present additional materials regulations and applicable state regulations. See material problems. These types of gases will sometimes 14.1.15, Safety, Labeling, Handling, and Transportation of require special materials and coatings in the sampling system. Cylinders. It is recommended that sample cylinders used in sour and/ The cylinder itself contains a moving piston equipped or corrosive gas service should be specially-lined or coated with O-rings, PTFE (Teßon¨) rings or other devices to (e.g., epoxy). Occasionally, sample cylinders may be glass or effect a leak-free seal between the sample and the inert, ceramic-lined, however, such cylinders may be absorptive or back-pressure gas and still allow the piston to move freely adsorptive under certain conditions. Other coating materialsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 26. 16 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT Product Inlet Purge Valve Mixing ball (or other mixing system) Piston Magnetic volume indicator assembly (or other volume indication) 1/ " NPT Inlet valve 4 Relief device Purge outlet Purge Pressure Precharge Purge valve valve gauge inlet Relief device Figure 7—Typical Floating Piston Cylinder and/or passivation may be acceptable. Very reactive compo- 14.1.10.2 CARBON STEEL nents, such as hydrogen sulÞde (H2S), should be analyzed on- Carbon steel and other relatively porous materials may site when practical since even coated containers may not retain heavier components and contaminants such as CO2, eliminate all absorption or reaction of the contaminants. N2, and H2S in the natural gas sample source stream and The use of soft metals such as brass, copper, and aluminum should not be used in a sampling system. Reaction of car- (except hard anodized) should be avoided in a sample system, bon steel with the components frequently found in natural because of excessive corrosion rates and other metallurgical gas will cause errors in the gas analysis. Sample valves and and sampling problems. Corrosion rates and the possibility of cylinders made from this material display dangerously high sulÞde stress corrosion cracking for each sampling system corrosion rates. These problems are particularly acute in must be considered and the service life of the equipment wet sour gas sampling. Corrosion rates in a carbon steel reduced to account for corrosion. NACE standards or other sample system may be sufÞcient to cause particulate con- appropriate standards for materials should be applied to the tamination of the sampling system valves, Þlters and analy- containers and sampling systems. sis equipment.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 27. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 17 14.1.10.3 DISSIMILAR MATERIALS d. Floating piston cylinder method. Using dissimilar materials in a sample system may cause e. Water displacement method. increased rates of corrosion and may result in sampling f. Glycol displacement method errors. When taking several samples of a gas for comparative g. PurgingÑÞll and empty method analysis, the same cylinder material should be used. Using the same material reduces the likelihood that the gas will h. PurgingÑcontrolled rate method react differently with each sample cylinder, but does not guar- The evacuated container method, the reduced pressure antee that the sample will not be distorted. method, and the helium pop method all require evacuating the sample container to 1 mm Hg (1/2 inch H2O or 3.39 kPaabs) 14.1.11 Other Apparatus or less, absolute pressure. See 14.12.2, Evacuated Container 14.1.11.1 TIMERS Method; 14.12.3, Reduced Pressure Method; and 14.12.4, Helium Pop Method. Timers are used on time-proportional sampling systems to The ßoating piston cylinder method, the glycol displace- actuate the sample system and collect a sample at the desired ment method, and the water displacement method are con- intervals. See 14.1.14.2, Composite Sample Intervals. stant pressure methods, and are good choices when the pressure within the sample cylinder must remain equal to the 14.1.11.2 FLOW COMPUTERS stream pressure during the sampling procedure. See 14.12.5, Floating Piston Cylinder Method, 14.12.6, Water Displace- Flow computers or ßow indicators may be used on a sam- ment Method, and 14.12.7, Glycol Displacement Method. ple system to provide an indication of the ßow rate to a ßow- proportional sample system. Flow computers and ßow indica- The user must expect degradation in accuracy with any of tors must meet all appropriate electrical standards for the the methods when the temperature of the source gas stream areas of their intended use. and/or all parts of the sampling system are not at or above the hydrocarbon dew point temperature. See Appendix C, Les- sons Learned During Sampling in Hydrocarbon Saturated 14.1.11.3 POWER SUPPLIES and 2-Phase Natural Gas Streams. Systems requiring a power supply must meet appropriate electrical standards and should have a backup power source 14.1.12.2 EVACUATED CONTAINER METHOD available in case the primary power source fails. The evacuated container method requires a vacuum of 1 mm Hg (1/2 inch H2O or 3.39 kPaabs) or less, absolute pres- 14.1.11.4 PRESSURE GAUGES sure. When using the evacuated container method, the valves Gauges should be calibrated or compared to a certiÞed and Þttings on the sample cylinder must be in good condition pressure standard on a regular schedule to ensure accuracy. and there must be no leaks. This is particularly important in reduced pressure sampling This method can produce results within ±0.14% of true methods. heating value (HV) and density values when the sample gas temperature and all parts of the sampling system are main- 14.1.12 Spot Sampling Methods tained according to 14.1.6.6, General Discussion of Heating. 14.1.12.1 GENERAL 14.1.12.3 REDUCED PRESSURE METHOD The standard procedures recommended for spot sampling The reduced pressure method is similar to the evacuated are contained in the latest revision of GPA Standard 2166. container method except that instead of allowing the cylinder The scope of GPA Standard 2166 does not include composite to come up to line pressure, it is slowly Þlled to a point gas sampling, on-line gas sampling, or mobile gas sampling. approximately one-third line pressure. GPA Standard 2166 allows eight different methods that, with This method can produce results within ±0.12% of true HV certain comments and cautions, are accepted by API. SAM- and density values when the sample gas temperature and all PLE CYLINDERS SHOULD BE CLEAN PRIOR TO parts of the sampling system are maintained according to EMPLOYING ANY OF THE METHODS. See Section 14.1.6.6, General Discussion of Heating. 14.1.6.5, Cleanliness, for more information. Since the hydrocarbon dew point temperature of the gas The methods are: changes with pressure, Þlling the cylinder to one-third line a. Evacuated container method. pressure does not guarantee that there will be no condensa- tion. Consider a cylinder at a temperature of 20¡F (Ð7¡C), b. Reduced pressure method. used to sample an unknown stream at a pressure of 1500 psig c. Helium pop method. (10.3 MPa). The reduced pressure method speciÞes Þlling theCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 28. 18 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT cylinder to approximately 500 psig (3.4 MPa). However, the c. PTFE (Teßon¨) seals or equivalent, which require no mixture may still condense at a pressure of 500 psig (3.4 grease for sealing or smooth operation of the ßoating piston, MPa), and a temperature of 20¡F (Ð7¡C). should be used. d. Silicon grease or other piston lubricants that may absorb 14.1.12.4 HELIUM POP METHOD or contaminate the sample should not be used. The helium pop method requires preparing the cylinder by e. The precharge side of the cylinder should be loaded with evacuating the sample container to 1 mm Hg (1/2 inch H2O or an inert gas that is different from the components in the 3.39 kPaabs) or less, absolute pressure. The helium pop stream being sampled and that will not affect analytical method is similar to the evacuated container method except results should a leak occur. that a helium charge is used to keep the container free of air Before the sampling operation is begun, the sample con- prior to sampling. tainer and the associated piping should be purged by the Þll Use of the Helium Pop method will reduce the un-normal- and empty method or by a built-in purge valve. Then the pre- ized total percent that is calculated during a gas chromato- charge side of the cylinder is Þlled to line pressure to move graphic analysis. Therefore, the un-normalized total percent the ßoating piston to the starting position. Care should be cannot be used as a gas chromatograph diagnostic when taken to avoid condensation and contamination during the employing this method. purge procedure. This method can produce results within ±0.15% of true HV and density values when the sample gas temperature and all 14.1.12.6 WATER DISPLACEMENT METHOD parts of the sampling system are maintained according to 14.1.6.6, General Discussion of Heating. CAUTION: For the water displacement method, water may absorb or desorb CO2, H2S, and other components depending 14.1.12.5 FLOATING PISTON CYLINDER METHOD on the water quality and the contact time. Using distilled water will prevent de-sorption, but not absorption, of CO2 or other The constant pressure cylinder is designed to maintain the components. The displacement ßuid may also contaminate the sample at pipeline pressure. The sample cylinder should be chromatograph sample systems and columns. This method reheated in the laboratory to a temperature necessary to should not be used when sampling for water content determi- ensure complete vaporization of any liquids in the cylinder as nation or when the ambient temperature is below 32¡F (0¡C). described in 14.1.6.6.4, Sample Containers. It is also criti- cally important to ensure that the cylinder is properly cleaned This method can produce results within ±0.13% of true HV before sampling, particularly if there is a suspicion that previ- and density values when the sample gas temperature and all ous samples condensed within the cylinder, or if the cylinder parts of the sampling system are maintained according to made contact with any liquid hydrocarbons such as slugs or 14.1.6.6, General Discussion of Heating. compressor oil (see 14.1.6.5, Cleanliness). The piston sealing mechanism (normally o-rings or lip 14.1.12.7 GLYCOL DISPLACEMENT METHOD seals) requires that the piston totally separate the sampled nat- CAUTION: For the glycol displacement method, water may ural gas from the pre-charge gas. The material used for the absorb or desorb CO2, H2S, and other components depending sealing mechanism and the lubricant used must not adsorb or on the water quality and the contact time. Using distilled in any other way distort any of the components in the natural water will prevent desorption, but not absorption, of CO2 or gas mixture. Adsorption or absorption of hydrocarbon com- other components. The displacement ßuid may also contami- ponents can cause leakage and/or seal failure. nate the chromatograph sample systems and columns. This This method can produce results within ±0.14% of true HV method should not be used when sampling for water content and density values when the sample gas temperature and all determination. parts of the sampling system are maintained according to 14.1.6.6, General Discussion of Heating. This method can produce results within ±0.10% of true HV and density values when the sample gas temperature and all Floating piston cylinders should have the following fea- parts of the sampling system are maintained according to tures (see 14.1.9.2.2, Floating Piston Cylinders): 14.1.6.6, General Discussion of Heating. a. They must be of sturdy construction and non-absorptive to the sample. Their design pressure rating should exceed the 14.1.12.8 PURGING—FILL AND EMPTY METHOD highest pressure available at the facility where they may be The purgingÑÞll and empty method requires several used. cycles of Þlling and emptying the sample cylinder in order to b. A piston position indicator, which is a method to detect remove residual impurities. Table 1 shows the number of Þll leakage of precharge gas, must be provided. and empty cycles required to sufÞciently remove residualCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 29. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 19 Table 1—Fill and Empty Purge Cycles Maximum Gas Pressure in Container Number of Fill psig (kPa) and Empty Cycles 15Ð29 (100Ð200) 13 30Ð59 (200Ð405) 8 60Ð89 (405Ð615) 6 90Ð149 (615Ð1025) 5 150Ð500 (1025Ð3450) 4 >500 (>3450) 3 impurities from the cylinder. This method can produce results 14.1.12.10 VACUUM–GATHERING SYSTEM within ±0.12% of true HV and density values when the sam- METHOD ple gas temperature and all parts of the sampling system are maintained according to 14.1.6.6, General Discussion of In rich, low-pressure, or vacuum-gathering systems, the Heating. use of a vacuum pump is recommended. One method involves a pump drawing gas from the sample point and dis- This method requires that: charging into the sample system (see Figure 9a). An alternate 1. The cylinder is coupled to the sample point as shown in method, not evaluated in the research program (see Figure Figure 8. 9b), involves drawing the sample through a helium-Þlled sample cylinder with the pump. With either method, before 2. A ÒpigtailÓ is attached to the outlet of the cylinder as the sample is collected, both the oxygen content and the rela- shown in Figure 8. tive density of the stream should be measured using a porta- 3. A drilled plug restriction is installed at the end of the ble oxygen analyzer and a portable gravitometer to ensure the ÒpigtailÓ as shown in Figure 8. The key consideration is sample is representative of earlier samples and free of air con- that the cooling produced by the Joule-Thomson effect tamination due to leaks. For the method shown in Figure 9a, should be located at the end of the Òpigtail.Ó once the oxygen and gravity values are recorded and accepted, the sample is collected using any of the following Note: The results mentioned above were achieved using a 0.020 GPA Standard 2166 methods: inch (0.51 mm) diameter oriÞce. 4. The cylinder is purged of residual impurities using the ¥ Fill and Empty, correct number of Þll and empty cycles (Table 1). ¥ Evacuated Container, 14.1.12.9 PURGING—CONTROLLED RATE ¥ Helium Pop, or METHOD ¥ Glycol Displacement. The controlled rate method described in GPA Standard Pressure within the sample cylinder is maintained at less 2166 employs a continuous purge. than 20 psig (13.8 kPa). Without sufÞcient heat input, This method can produce results within ±0.18% of true HV increased sample pressure may cause condensation to and density values when the sample gas temperature and all occur. Sample cylinders larger than 300 cm3 (18 in.3) may be parts of the sampling system are maintained according to required to contain enough material to analyze. It is 14.1.6.6, General Discussion of Heating. extremely important that samples from such streams be CAUTION: For the purgingÑcontrolled rate methodÑliquid heated in accordance with the recommendations in 14.1.6.6, may accumulate in the sample cylinder and in the coiled General Discussion of Heating, if analytical results are to be extension tubing on the outlet of the sample cylinder. This repeatable and reproducible. Refer to Appendix A, The Phase will cause an enrichment of the gas sample and thereby an Diagram, for general discussion of phase changes due to overstatement of the heating value and density of the gas in pressure increases. the pipeline. This liquid accumulation should not occur if all Samples of compositions characteristic of vacuum-gather- parts of the sampling equipment are kept above the hydrocar- ing systems (very high HV content) demonstrate a greater bon dew point temperature in accordance with 14.1.6.6, Gen- degree of uncertainty in the analytical results due to the sus- eral Discussion of Heating. ceptibility of the heavy ends to condense.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 30. 20 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT Close-coupled Sample container (see 14.1.9) Sample “Pigtail” container (see 14.1.12.11) (see 14.1.9) Pipeline Sample probe (see 14.1.7) Purge valve and drilled plug assembly (see 14.1.12.11) Direct mount (preferred when the sample source is at or near the hydrocarbon dew point) “Pigtail” (see 14.1.12.11) Purge valve and Note: Insulation and heat tracing are not shown. See 14.1.6.6, drilled plug assembly General Discussion of Heating for gas temperature requirements. (see 14.1.12.11) Figure 8—API-Recommended Spot Sampling Apparatus for Fill and Empty Method. Close-Coupled and Direct MountCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 31. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 21 Vacuum pump Sample cylinder Sample probe Connect oxygen analyzer or Pipeline gravitometer to verify representative sample Figure 9a—Vacuum Gathering System ModelCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 32. 22 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT Connect oxygen analyzer or gravitometer to verify representative sample Vacuum pump Sample cylinder Use of GPA separator (optional) Sample probe Flow Pipeline Figure 9b—Alternate Method of Sampling from a Vacuum-Gathering SystemCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 33. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 23 14.1.12.11 USE OF AN EXTENSION TUBE / lation may be required to avoid condensation. If the sample “PIGTAIL” system does not provide a continuous ßow of sample, the sampler should purge itself prior to pumping a sample incre- Extension tubes or Pigtails are simply long pieces of tubing ment into the collection cylinder. (See Section 14.1.6.6, Gen- at least 36 inches (0.91 m) long that extend from the sample eral Discussion of Heating, and Appendix A, The Phase cylinder outlet valve to the purge valve and drilled plug Diagram, for further information.) assembly on the end of the pigtail. If it is coiled to make the When using displacement samplers, either constant vol- sampling apparatus easier to handle, there must be a sufÞcient ume or constant pressure cylinders may be used. When using air gap between adjacent coils to minimize heat transfer from regulator samplers, constant volume cylinders are required. coil to coil. Refer to GPA Standard 2166 for details. The pur- pose of the extension tube is to thermally de-couple the throt- 14.1.13.2 CONTINUOUS SAMPLING SYSTEMS tling process from the sample cylinder. Without an extension FOR ON-LINE ANALYZERS tube, the sample cylinder outlet valve will cool and the sam- ple cylinder itself will be cooled, since it is thermally coupled 14.1.13.2.1 General to the outlet valve (via conduction). If the throttling process For on-line analyzers, such as chromatographs and gravito- chills the sample cylinder, the sample may be chilled below meters, the sample system will consist of components to its hydrocarbon dew point temperature and become non-rep- extract, condition and deliver a representative sample of natu- resentative. ral gas to the analyzer. The sample delivery system must not interfere with the integrity of the primary metering system. To 14.1.13 Automatic Sampling avoid the possibility of system interference, it is generally 14.1.13.1 COMPOSITE SAMPLERS recommended that on-line sampling systems be dedicated to a single device. 14.1.13.1.1 General Composite samples are automatically taken over an 14.1.13.2.2 System Considerations extended period of time with the sampling rate proportional The sample lines should be kept as short as possible. to ßow rate or time. There are several composite samplers The sample delivery system must meet the requirements of commercially available. For streams with variable ßow rate 14.1.6.6, General Discussion of Heating, which may require and composition, a ßow-proportional sampler is recom- heating and insulation to avoid sample condensation. The sys- mended. tem should also be designed to facilitate cleaning. See Sec- Condensation in the sample system must be avoided. Tests tion 14.1.6.5, Cleanliness, and Appendix A, The Phase conducted under actual Þeld operating conditions have shown Diagram, for further information. The ßow rate through the that composite samplers cannot be reasonably expected to sample system should be designed to achieve the appropriate provide representative samples when exposed to ambient lag time in the system. For example, in real time process con- conditions below the sample gas hydrocarbon dew point. See trol, the lag time must be very short relative to the require- 14.1.6.6, General Discussion of Heating, for further informa- ments for a monthly average analysis. tion. 14.1.14 Sampling Intervals 14.1.13.1.2 Regulator Samplers 14.1.14.1 GENERAL CONSIDERATIONS A specially designed pressure regulator increases the deliv- ery pressure of the sample to the sample cylinder from atmo- A sampling system should provide a sample representative spheric pressure to a maximum of line pressure during the of the gas ßowing in the pipeline. Since pipeline ßow rates sample period. Regulator samplers are not recommended for and compositions may vary with time, a sampling interval, low-pressure lines or variable ßow rates. time or ßow proportional, should be carefully chosen so that the collected sample reßects these variations. 14.1.13.1.3 Displacement Samplers 14.1.14.2 COMPOSITE SAMPLE INTERVALS A positive displacement pump extracts a sample at line In choosing the method to be used in pacing the sampler, pressure and discharges it into a sample cylinder during the the sample source stream is the primary concern. Flow pro- sampling period. portional composite sampling systems are most likely to pro- duce a representative sample. If the stream has a constant 14.1.13.1.4 System Considerations composition or ßow rate, a time pacing mechanism may be The sample line between the sampling device and the col- used. Provisions in time based systems must be made to stop lection cylinder should be of minimum length. Heat and insu- sampling when there is no ßow.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 34. 24 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT 14.1.14.3 SPOT SAMPLING INTERVALS high-sulfur-content crude oil, crude oil fractions, associ- ated gas and associated waters. Since H2S is heavier Generally, gas pipeline composition will have daily, than air, it can collect in low places in still air. It is color- monthly, semi-annual, and seasonal variations. Composi- less and has a foul, rotten-egg odor. In low concentra- tional variations will also occur because of surface equipment tions, it is detectable by its characteristic odor. Smell and gas reservoir changes. All of these environmental and cannot be relied upon to forewarn of dangerous con- operational considerations must be taken into account when centrations however, because exposure to high concen- selecting a sampling interval for a spot sample. Spot samples trations of the gas (greater than 100 parts per million) will produce accurate and representative compositions only if rapidly paralyzes the sense of smell. A longer exposure the product composition is stable within the accounting time to lower concentrations has a similar desensitizing frame. effect on the sense of smell. If the sense of smell is ren- dered ineffective by hydrogen sulÞde (H2S), the result 14.1.15 Safety, Labeling, Handling, and can be an individual failing to recognize the presence Transportation of Cylinders of dangerously high concentrations. Utilize H2S moni- toring systems to accurately determine H2S levels. 14.1.15.1 SAFETY Excessive exposure to hydrogen sulÞde (H2S) causes Precaution should be taken to ensure that safe practices death by poisoning the respiratory system at the cellu- are employed. All applicable Occupational Safety and lar level. There is some indication that the presence of Health Administration (OSHA) and DOT regulations should alcohol in the blood aggravates the effects of H2S in acute be consulted. poisoning cases. At low concentrations (10 to 50 parts per Sample probes, cylinders, lines, sampling separators and million), H2S is irritating to the eyes and respiratory tract. valves must have working pressures above the sample source Closely repeated, short-term exposures at low concentra- pressure. The material used in the construction of each of the tions may lead to irritation of the eyes, nose and throat. components in the sample system must not be affected by the Symptoms from repeated exposures to low concentrations components in the gas sampled. Pressure and velocities in the usually disappear after not being exposed for an appropri- ßowing pipeline must be carefully considered when specify- ate period of time. Repeated exposures to low concentra- ing hardware for the sampling system. Copper tubing and Þt- tions that do not produce effects initially can eventually tings can be hazardous and should be avoided. If copper lead to irritation if the exposures are frequent. tubing and Þttings are used, they must be used with caution and inspected frequently for bad connections, ßattening, and 14.1.15.2 LABELING kinks. Systems with pressures over 1,000 psi (6.9 MPa) or gas containing hydrogen sulÞde (H2S) should be constructed Labels or tags must be completed and attached to each with stainless steel or other appropriate tubing, Þttings and sample cylinder with the following information: components. ¥ Sample source. During sampling, sample transfer and especially during purging, a total commitment to safety precautions is manda- ¥ Sample collection method. tory. Smoking, open ßames, vehicles with motors running, ¥ Pressure and temperature of the sampled source stream use of matches and use of non-explosion proof electrical near the sample point. devices in the area is not permitted. Caution must be exer- cised when purging and sampling to prevent forming a haz- ¥ Date and time of collection. ardous atmosphere. Special precautions should be taken if ¥ Field technician name. hydrogen sulÞde (H2S) is present (see Appendix D, Hydrogen SulÞde Warning). Additional information may be required, such as: The transportation and construction of the sample cylinder ¥ Hydrocarbon dew point. is strictly regulated by DOT, 49 Code of Federal Regulations, the U.S. Coast Guard, the Federal Aviation Administration ¥ Water dew point. and various other regulatory agencies. TRANSPORTATION OF THESE CYLINDERS MUST ADHERE TO THE ¥ Flow rate. GUIDELINES SET FORTH IN THEIR REGULA- ¥ Relative density. TIONS. Inhalation of hydrogen sulÞde (H2S) at certain con- ¥ Oxygen concentration. centrations can lead to injury or death. H2S is an ¥ CO2 concentration. extremely toxic, ßammable gas which may be encoun- tered in the production and processing of gas well gas, ¥ H2S concentration.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 35. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 25 Labels or tags must be securely attached to the sample cyl- the cylinder must be oriented vertically. As a minimum, inders, but should not interfere with the utilization of the cyl- calibration standard gas blends must be gravimetrically inder. Figure 10 gives an example of typical label prepared and traceable by weight to the National Institute information. of Standards and Technology (NIST), or equivalent stan- US DOT CFR 49 includes speciÞc requirements for label- dards body. It is not recommended that a standard be used ing. for more than one (1) year. The calibration standard shall be heated for a minimum period of 4 hours after the skin 14.1.15.3 HANDLING AND TRANSPORTATION OF temperature of the cylinder reaches a temperature 20¡F CYLINDERS (11.1¡C) above the calculated hydrocarbon dew point. The intent of this requirement is to ensure that the core temper- Sample cylinders containing natural gas samples must be ature of the calibration standard has reached a temperature handled carefully due to their pressure, ßammability and/or of at least 20¡F (11.1¡C) above the calculated hydrocarbon contents. dew point of the calibration gas. Vaporization of the heavy The following actions shall be performed in conjunction components will occur more rapidly at higher temperatures with handling and transporting a sample: above the calculated hydrocarbon dew point. It is generally ¥ Check valves and Þttings for leaks. not necessary to exceed 50¡F (27.8¡C) above the calculated hydrocarbon dew point. Heating the calibration standard ¥ Inspect, repair or replace valves as required. for a longer period or continuously will not cause deteriora- tion of the standard. The sample lines from the calibration ¥ Plug or cap sample cylinder inlet and outlet valves prior standard to the chromatograph and any regulators in the to transportation. system must also be maintained at a temperature at least 20¡F (11.1¡C) above the calculated hydrocarbon dew point ¥ Avoid creating an unsafe situation due to over-tighten- plus the expected temperature reduction due to the pressure ing valves. Hand tightening of valves is sufÞcient. reduction (approximately 7¡F (3.9¡C) per 100 psi (690 ¥ Protect sampling equipment from damage. kPa) of pressure reduction). See 14.1.6.6, General Discus- sion of Heating. ¥ Properly restrain sample containers during transport. REFERENCES Consider that depressurizing sample containers may pro- duce low temperatures, high ßuid velocities and hazardous 1. American Society for Testing and Materials, 100 Barr vapors. Harbor Drive, West Conshohoken, Pennsylvania, 19428- It is recommended that all sample cylinders incorporate an 2959. over-pressure relief device, approved by the appropriate regu- latory agency. The transportation and construction of the sam- 2. DOT (U.S. Department of Transportation). The Code of ple container is strictly regulated by the DOT, 49 Code of Federal Regulations is available from U.S. Government Federal Regulations, the U.S. Coast Guard, the Federal Avia- Printing OfÞce, Washington, D.C. 20001. tion Administration and other regulatory agencies. TRANS- PORTATION OF THESE CYLINDERS MUST 3. Gas Processors Association, 6526 E. 60th Street, Tulsa, ADHERE TO THE GUIDELINES SET FORTH IN Oklahoma 74145. THEIR REGULATIONS. 4. National Association of Corrosion Engineers, 1440 14.1.16 Guidelines For Analysis South Creek Drive, Houston, Texas 77218-8340. All laboratories must meet the operational requirements of 5. Metering Research Program: Natural Gas Sample Col- the GPA standards for the type of gas analysis conÞguration lection and Handling-Phase I, Behring, K.A. III and being used. All analyses should be performed in accordance Kelner, E. GRI Topical Report No. GRI-99/0194. with procedures set forth in GPA publications or other accepted industry standards. 6. Metering Research Program: Natural Gas Sample Col- The API Laboratory Inspection Checklist developed by the lection and Handling-Phase II, Kelner, E. GRI Topical API Chapter 14.1 Working Group is a useful tool for evaluat- Report No. GRI-XX/XXXX. ing the performance and systems of analytical laboratories. (See Appendix E) 7. Metering Research Program: Natural Gas Sample Col- It is required that gas samples be heated prior to lection and Handling-Phase III, Kelner, E. GRI Topical analysis. When the sample is withdrawn for injection, Report No. GRI-XX/XXXX.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 36. 26 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT SAMPLE FORM Facility Name: ____________________________________________________________________________ Company Name: __________________________________________________________________________ Agreement Number: _______________________________________________________________________ Sample Location: _________________________________________________________________________ Sampled By: _____________________________________________________________________________ Date: ____________________________________________________________________________________ Time: ____________________________________________________________________________________ Sampled From: Composite ______________ Pipeline ________________ Storage _________________ Other __________________ Sample Conditions: Pressure ________________ Temperature ____________ Relative Density (Specific Gravity) _____________________ BTU ____________________ (If Known) Sampling Method: Purge/Fill ________________ Waterdraw ______________ Piston ___________________ Other __________________ The following information to be filled out by laboratory: Name of Laboratory: ______________________________________________________________________ Date Sample Received: ____________________________________________________________________ Date Sample Analyzed By: _________________________________________________________________ Sample Condition: ________________________________________________________________________ Witnessed By: ____________________________________________________________________________ Figure 10—Typical Sample FormCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 37. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 27 8. Hydrocarbon Phase Behavior, Ahmed, T., Gulf Publish- 11. Prediction of Horizontal Tubeside Condensation of Pure ing Company, Houston, TX, 1989. Components Using Flow Regime Criteria, Breber, G., Palen J.W., Taborek, J. Presented at the 18th National 9. The Properties of Petroleum Fluids, McCain, W.D. Jr., Heat Transfer Conference, San Diego, 1979. Also pub- PennWell, Tulsa, Oklahoma, 1990. lished in Condensation Heat Transfer, ASME Publica- tion No. 100123. 10. Introduction to Fluid Mechanics, Fox, R.W and McDonald, A.T., Wiley & Sons, New York, 1973.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 38. COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 39. APPENDIX A—THE PHASE DIAGRAM A.1 Phase Changes in General When connected, the dew points, bubble points, and criti- cal point form a region called the 2-phase region. In this The importance of avoiding condensation during gas sam- region, liquid and gas coexist in relative quantities ranging pling is discussed throughout this standard because phase from just under 100 percent gas, to just under 100 percent changes have a signiÞcant impact on the accuracy of a gas liquid. sample. When a hydrocarbon mixture undergoes a phase If the dew point and bubble point pressures and tempera- change process during sampling, the composition of the col- tures are plotted on a pressureÑtemperature diagram, the lected sample will not be the same as the composition of the result is a single line known as the P-T diagram, phase dia- ßowing gas stream. The errors in composition resulting from gram, or vapor pressure curve. Figure A1 shows a typical a phase change can be large. vapor pressure curve for a single component. The upper sec- The phase diagram is a useful tool for modeling the phase tion corresponds to the liquid phase and the lower section cor- behavior of a hydrocarbon mixture. The phase diagram illus- responds to the gaseous phase. Gas and liquid will coexist at trates the change in dew point and bubble point temperatures the pressure/temperature points on the curve. The vapor pres- with changes in the gas pressure. sure curve for a single component does not show the relative Since pressure changes are impossible to avoid during the amounts of each phase. sampling process (i.e., getting a sample of gas from the source, to the analyzer), an understanding of the gas mixtureÕs A.3 Mixture Phase Behavior phase behavior provides guidance in the design and applica- Now consider the piston-cylinder device Þlled with a mix- tion of sampling systems and sampling methods. ture of components, such as hydrocarbons. If the mixture is For the purposes of this discussion, only liquid and gas compressed isothermally, as in the previous example, the phases are considered. mixture will go from a gaseous phase, to a mixture of gas and liquid, then to liquid, as shown on the T1 isotherm of Figure A.2 Single Component Phase Behavior A2. This can be repeated at progressively higher temperatures until the critical temperature is reached. The line connecting Consider the piston-cylinder device shown in Figure A1 the dew points, bubble points and the critical point forms the and Þlled with a single component (e.g., CO2, N2, He) in the 2-phase region. gaseous phase. The pressure, temperature, and volume of the The general phase behavior of a mixture, such as a hydro- substance are represented by the letter A. If the substance is carbon mixture, is similar to that of a single component, with compressed isothermally (i.e., at constant temperature, T1), two important exceptions. First, the dew point pressure does there will be a decrease in the cylinder volume. This decrease not equal the bubble point pressure at a given temperature. in volume and the associated increase in pressure will con- Second, gas and liquid can coexist at pressures and tempera- tinue until liquid begins to condense. The pressure at which tures above the critical point of a mixture. condensation begins is called the dew point, and is shown in If the dew point and bubble point pressures and tempera- Figure A1 as point B. tures are plotted on a P-T diagram as shown in Figure A2, the Once condensation begins, additional decreases in volume result is the mixture phase diagram. The region enclosed by produce more and more condensation (C and D) until only an the bubble points and dew points is the 2-phase region, also inÞnitesimal amount of gas remains in the mixture. This pres- known as the phase envelope. sure is called the bubble point pressure. In Figure A1, it is Natural gas engineering is primarily concerned with mix- point E. For a single component, the dew point pressure is ture temperatures that are above the critical temperature. equal to the bubble point pressure when the temperature is held constant. The substance is entirely in the liquid phase at A.4 Retrograde Condensation and volumes below the bubble point volume. Vaporization If this process is repeated for a temperature, T2 greater than T1, similar pressureÑvolume behavior occurs. This can The vapor pressure curve for a single component was dis- be repeated at higher and higher temperatures until no distinct cussed earlier and is shown in Figure A1. This curve repre- phase-change occurs. This happens at the critical tempera- sents the pressures and temperatures where 2-phases of a ture. The pressure associated with the critical temperature is single component coexist. At a given temperature, the phase called the critical pressure. The critical point (CP) is the inter- change process for a single component occurs at a constant section of the critical temperature and critical pressure. Gas pressure. and liquid cannot coexist above the critical point of a single Mixture phase behavior is different than single component component. phase behavior. There is a pressure change during the phase 29COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 40. 30 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT change process. This pressure change appears on the phase The line A-B is the section of the phase diagram known as diagram (P-T curve) as two saturation pressures for a given the bubble point curve. When the pressure is lowered isother- temperature (Figure A2). mally to the bubble point, an inÞnitesimal amount of gas Focusing on the section of the phase diagram with temper- begins to evolve. As the pressure is reduced further, more and atures above the critical temperature (Figure A3), one can see more gas is liberated from the mixture, increasing the total that during an isothermal pressure drop, from point A to point concentration of gas in the 2-phase mixture. E, the mixture starts completely in the gas phase, then begins The line B-E is the dew point curve. This section of the to condense as it reaches the point labeled as the Òupper dew phase diagram represents the pressures and temperatures point.Ó This ÒretrogradeÓ condensation is counter to the associated with the condensation of an inÞnitesimal amount behavior that occurs with a single component. of liquid from the gas mixture. As the pressure continues to drop, more of the mixture The line C-D is sometimes referred to as the retrograde condenses, until the percent of condensed liquid in the mix- dew point line. The dew points along line C-D are referred to ture reaches a maximum (determined by the composition of as the upper or retrograde dew points. the original mixture). Once the maximum is reached, further The line D-E is sometimes referred to as the normal dew pressure reduction causes a vaporization of the liquid until the point curve. The dew points along line D-E are referred to as Òlower dew pointÓ is reached. The mixture is entirely in the the lower or normal dew points. gas phase at pressures below the lower dew point pressure. Point C is the cricondenbar. It is the highest pressure on the The opposite will occur during an isothermal pressure phase envelope. Point D is the cricondentherm. It is the high- increase. It may also occur when gas from a vacuum-gather- est temperature on the phase envelope. ing system is compressed into the sample cylinder. Retrograde phase changes can also occur when the temper- ature is changed at pressures above the critical pressure and A.6 Limitations of the Phase Diagram within the phase envelope. The accurate determination of a hydrocarbon mixtureÕs phase behavior depends on the accuracy of the compositional A.5 Natural Gas Mixture Phase Diagrams analysis, the equation of state used, the amount of ÒheavyÓ Figure A4 shows a phase diagram for a typical natural gas (C6+) fractions, and the accuracy of physical properties such mixture. Several sections of the curve are labeled. The com- as the critical temperature and critical pressure. position of the hydrocarbon mixture being modeled is also These limitations must be considered when using a phase shown. diagram for gas sampling system or method design.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 41. Infinitesimal Infinitesimal amount of amount of gas liquid SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 100% Gas Gas Gas Liquid 100% Gas Liquid Liquid Liquid A B C D E F 2-Phase region CP CP Liquid Pressure Pressure Tc F T2 > T1 Gas T1 E D C B A Volume Temperature Figure A1—Pressure—Volume and Pressure—Temperature Diagrams for a Pure Component 31COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 42. 32 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT 100% Gas Gas Gas 100% Liquid Liquid Liquid A B C D Natural Oil Gas 2-Phase region CP CP Dew point curve Pressure Pressure Bubble point curve Tc D T2 > T1 2-Phase region C T1 B A Volume Temperature Figure A2—Pressure—Volume and Pressure—Temperature Diagrams for a MixtureCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 43. 100% Gas 75% Gas X% Gas 75% Gas SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 100% Gas 25% Liquid Y% Liquid 25% Liquid A B C D E A Upper dew point CP B Pressure C D Lower dew point E Temperature Figure A3—Retrograde Condensation 33COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 44. 34 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT kPa psia – 2000 – Composition 13000 1900 – Supercritical N2 = 2.05533 – Fluid CO2 = 0.5132 12000 1800 – C1 = 82.6882 – 1700 – Cricondenbar C2 = 6.9665 11000 Dew point curve (maximum pressure) C3 = 4.5441 1600 – (line B–E) i-C4 = 1.1559 – 10000 1500 – n-C4 = 1.2856 1400 – C Retrograde dew point curve i-C5 = 0.3983 – Liquid 9000 (line C–D) nC5 = 0.2624 1300 – 2-Phase Region C6 = 0.0836 – 1200 – B Pressure 8000 Critical C7 = 0.0273 1100 – Region C8 = 0.0167 – 7000 C9 = 0.0009 1000 – – Bubble point curve 6000 900 – Cricondentherm (line A–B) (maximum temperature) – 800 – 5000 D 700 – – 600 – Vapor 4000 2-Phase 500 – Region – 3000 400 – (Vapor/Liquid) – 300 – 2000 Normal dew point curve 200 – A (line D–E) – 1000 100 – E – 0– –200 –180 –160 –140 –120 –100 –80 –60 –40 –20 –0 20 40 60 80 100 120 140 °F –120 –100 –80 –60 –40 –20 –0 20 40 60 °C Temperature Figure A4—Examples of Thermodynamic Processes of Natural GasCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 45. APPENDIX B—FLUID MECHANICAL CONSIDERATIONS IN GAS SAMPLING B.1 General macroscopic mixing of adjacent ßuid layers. To illustrate, if a thin Þlm of dye were to be injected into a laminar ßow, the It is important to understand the types of ßow perturbations dye would appear to be a single line, with no dispersion of the that can occur in a pipeline and how these can affect the accu- dye throughout the ßow Þeld (except for slow dispersion due racy of a gas sample. For instance, some piping elements or to molecular motion). conÞgurations can create re-circulation zones or eddies in the Figure B1 qualitatively illustrates laminar ßow at the ßow stream. The zone immediately downstream of an oriÞce entrance region of a pipe. In this example, the ßow velocity plate is a prime example. The gas composition in these eddies (Uo) is uniform at the pipe entrance. The velocity of the gas at may be measurably different from the gas composition of the the wall of the pipe is always zero and the pipe wall exerts a bulk ßow. Other types of ßow restrictions or expansions can retarding shear force on the ßowing gas. The result is that the create localized thermodynamic changes in the gas stream. gas velocity near the pipe wall is reduced in the axial direc- An example would be the ßow from a gas-liquid separator. In tion and the effect of the pipe wall is felt farther out in the that case, the gas will be near its hydrocarbon dew point and a ßow stream as the gas progresses downstream. This phenom- reduction in line temperature will likely cause some conden- enon creates a boundary layer along the pipe wall. At some sation to occur, resulting in the ßow becoming two phases. In distance downstream of the pipe entrance, the boundary layer other cases, a pipeline may be operating in a multiphase equi- grows to the point that it reaches the pipe centerline. The librium, in which case both gas and liquid are continually length required for the boundary layer to reach the pipe cen- present in the pipe. Obtaining an accurate gas sample under terline is called the entrance length. Beyond the entrance these conditions can be quite challenging. length, the velocity proÞle does not change with increasing It is not the objective of this document to explain in full distance and the ßow is said to be fully developed. The veloc- detail how ßow effects can adversely affect the gas sampling ity proÞle of fully-developed laminar pipe ßow has a para- process. There is a large body of information on this subject bolic shape. available in the open literature, to which the reader is referred (see References). Instead, the following general overview Turbulent ßow in a pipe is generally characterized by a seeks to make the reader aware of potential ßow-related prob- general swirling nature in the ßow Þeld involving indistinct lems that may need to be addressed when selecting appropri- lumps of ßuid called eddies or vortices. There is typically a very wide range in the size of the eddies occurring at the same ate gas sampling locations or troubleshooting existing sampling sites. time or at the same place in the turbulent region. The instanta- neous boundary region between the turbulent core ßow region and non-turbulent ßow region near the pipe wall is B.2 Single-Phase Flow sharp. Turbulent ßow is also a randomly unsteady process, The preferred ßow regime is single-phase, turbulent ßow with effective frequencies ranging over several orders of mag- away from major restrictions to the ßowing stream that might nitude. The irregular variations in the motion of the gas produce condensation. Single-phase ßow is natural gas ßow- stream are not small with respect to either time or space. Fur- ing at a temperature at or above the hydrocarbon dew point thermore, the turbulence is always three-dimensional, even if and free of compressor oil, water or other contaminants in the the bulk ßow is two-dimensional. To illustrate, if a dye Þla- ßow stream. In general, it is preferred that the single phase ment were to be injected into a turbulent ßow, the dye would gas in the pipeline be in the turbulent ßow regime, because break up into myriad entangled threads and disperse quickly the ßuid turbulence creates a well-mixed, representative ßuid. throughout the entire ßow Þeld. Laminar ßow is not normally found in gas pipeline appli- Figure B2 illustrates the differences in velocity proÞles for cations because the gas viscosity is relatively low and the gas laminar and turbulent pipe ßow. In this case, the pipe Rey- velocity is usually high enough to ensure that this ßow regime nolds number (i.e., the non-dimensional ratio of inertial to does not occur. However, depending on the design of the gas viscous forces) is 4 x 103. Both proÞles have the same aver- sampling system, laminar ßow can occur in low-ßow-rate age velocity and, thus, the same ßow rate. Notice, however, sampling lines. that the laminar and turbulent velocity proÞles do not have the Laminar ßow is the simplest class of pipe ßow, in which same centerline velocity and that the turbulent proÞle has a streamlines form an orderly, ßow pattern. A streamline is the much steeper proÞle near the wall of the pipe. trajectory traced out by a moving ßuid particle. In laminar Some piping conÞgurations (e.g., headers, single elbows, ßow, viscous forces control the movement of the gas as it multiple elbows in series, etc.), ßow control elements (e.g., moves through the pipe. The gas may be thought of as ßow- valves, regulators, Þlters, etc.), or ßow metering devices ing along in a series of layers or laminates, with smoothly (e.g., oriÞce ßow meters, turbine ßow meters, etc.) may dis- varying velocity from laminate to laminate. There is also no tort the gas ßow Þeld in a pipe, producing velocity proÞle 35COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 46. 36 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT r u Uo x Fully-developed Entrance length velocity Note: Figure excerpted from Introduction to Fluid Mechanics, Fox and McDonald. Figure B1—Laminar Flow in the Entrance Region of a Pipe Turbulent r r R Turbulent R Laminar Laminar Pipe centerline u V u U Note: Figure excerpted from Introduction to Fluid Mechanics, Fox and McDonald. Figure B2—Comparison of Laminar and Turbulent Velocity Profiles for Flow in a PipeCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 47. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 37 asymmetry, swirl, a combination of proÞle asymmetry and B.3 Multiphase Flow swirl or a phenomenon known as ßow separation. Flow sep- aration occurs when the momentum of the ßuid in the Sampling of multiphase ßow is outside the scope of this boundary layer is insufÞcient and the ßuid layers adjacent to standard. Sampling of multiphase (gas and liquid) mix- the solid surface (e.g., the pipe wall or an obstruction pro- tures is not recommended and should be avoided if at all truding in the pipeline, such as a reduced port valve, ßow possible. In the multiphase ßow, the ideal system would regulator, or an oriÞce plate) separate from the surface. Sep- mix the gas and liquid ßows uniformly and collect a sam- aration results in the formation of a relatively low pressure ple of the true mixture ßowing in the line by using a prop- region downstream of the separation point or behind the erly designed sample probe and an isokinetic sampling obstruction that produces the ßow separation. This low- system. Current technology of natural gas sampling is not pressure region is called the wake. Large scale eddies or sufÞciently advanced to accomplish this with reasonable ßow re-circulation zones often develop in wake regions that accuracy. When sampling a multiphase liquid-gas ßow, the form in a pipe ßow. recommended procedure is to eliminate the liquid from the These ßow distortions may also produce thermodynamic sample. The liquid product that ßows through the line changes (e.g., pressure or temperature changes) that result in should be determined by another method. The liquid frac- non-equilibrium conditions. For instance, thermodynamic tion of the multiphase ßow may contain water and hydro- effects may cause phase changes in the gas mixture. Care carbons. The hydrocarbons can contribute signiÞcantly to should be taken to select gas sampling locations that are free the energy (measured in British thermal units) content of of ßow distortion, since these distortions may cause composi- the gas and their presence in the gas line must not be over- tional changes in the gas mixture. looked.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 48. COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 49. APPENDIX C—LESSONS LEARNED DURING SAMPLING IN HYDROCARBON SATURATED AND 2-PHASE NATURAL GAS STREAMS During the late 1980Õs, industry made a commitment to the boundary and enter the two-phase region, resulting in BLM to complete a full set of consensus standards covering entrained and free liquids sometimes being present in the all the measurement-related practices in common use by the ßow loop. industry for custody transfer measurement. As a result of this The Þnal scope of the project does not include recommen- commitment, several new standards were developed and sev- dations for sampling in the two-phase region. The test plan eral existing standards were upgraded. Examples include deÞned by the Working Group for CEESI was performed standards covering Allocation Measurement, Electronic Gas under such severe conditions in the hope that recommenda- and Liquid Measurement, Coriolis Meters, Natural Gas Sam- tions could be made concerning the best methods to be used pling, Inferred Mass Liquid Measurement, etc. at or near the phase boundary. The data indicated that some As a part of the effort, API Chapter 14.1 was expanded methods might be capable of allowing sampling below the during the early 1990Õs to include composite sampling of hydrocarbon dew point, but with higher uncertainties. The natural gas. During the drafting of the upgraded standard, data also clearly demonstrated that under some severe operat- the Working Group realized that many of the consensus rec- ing conditions, when free liquids are present, none of the cur- ommendations contained in the standard for both spot and rent methods are capable of obtaining a representative composite sampling were not well supported by sufÞcient sample. documented and qualiÞed data. Following the balloting and Other areas investigated during the course of the research approval of the standard in 1992, a research project was included probe location, spot and composite sampling system eventually deÞned and implemented to produce enough design, heating and insulation requirements, laboratory high-quality data to make future recommendations techni- inspection procedures and performance criteria, GPA separa- cally defensible. tors and visual observation of free liquids (when operating the As originally scoped, the research project was to consist of loop below the hydrocarbon dew point). two basic test phases. The Laboratory Phase, conducted at the Southwest Research Institute, was intended to evaluate spot The work at CEESI showed that probe location is not criti- sampling methods under carefully controlled conditions. The cal if ßow is single-phase (above the hydrocarbon dew point). Field Phase was intended to evaluate the performance of the For ßow conditions at or near the hydrocarbon dew point, the most promising sampling methods identiÞed during the Lab- probe location should not be placed within or immediately oratory Phase at actual operating locations. The Field Phase following ßow disturbances. was to be conducted twice, once during Summer conditions, The uncertainty of a portion of the Field Phase data is high, then again under Winter conditions. The Field Phase was to especially when the gas stream was below the hydrocarbon contain evaluations for composite sampling as well. dew point. However, some data during these periods did Once the project had begun, Colorado Engineering Experi- reßect a general trend. For example, the constant pressure dis- ment Station, Inc. (CEESI) commissioned a wet-gas ßow placement method tended to be biased slightly low, the Þll facility that offered the Working Group the option of perform- and empty method appeared to work fairly well as much as ing the Field Phase under more controlled conditions, but still 10¡F (5.6¡C) below the hydrocarbon dew point and the at operating conditions typical of many Þeld locations. The helium pop method had a slight negative bias compared to the facility offered the option of performing tests with the ßow- reference. ing stream at, above or below the hydrocarbon dew point of In spite of the best intentions of the Working Group and the stream. CEESI, there were difÞculties in collecting and interpreting The CEESI wet-gas loop provided the ability to blend dif- the data. Examples include: ferent compositions of gas in order to evaluate both the repeatability and accuracy of various sampling methods. The ¥ Some of the test procedures were found to involve more gas blends were generally prepared using pipeline gas, then than one uncontrolled variable, weighing-in additional heavy components as required. ¥ Changes in the reference sample point location during Since the project intended to evaluate methods in the wet- the investigations into sample point location and sam- gas loop that were often below the hydrocarbon dew point, ple method tests, many of the data sets were collected under severe operating conditions where it was fully expected that achieving good ¥ Calibration problems with the online gas chromato- repeatable analytical results was not likely. The Working graph (peak gates not set properly during the initial test Group intentionally designed the tests to penetrate the phase series), 39COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 50. 40 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT ¥ Unstable chromatographic results during consecutive Conclusion: analyses (analyses that failed to reach equilibrium and/ ¥ When the simulated Þeld conditions were below or analyses that exhibited poor repeatability), hydrocarbon dew point, it was difÞcult to draw clear ¥ Large variations in the analyzed nitrogen concentration conclusions from the data. The Helium pop and Þll during various series of analyses, and empty methods showed promise under these adverse conditions. ¥ Sample size variations during analysis, due to atmo- spheric pressure variations and wind effects during the ¥ Trends reßected in the laboratory results were also initial test series, generally reßected in the simulated Þeld studies, even though the absolute values exhibited a higher ¥ Portions of a single test series being run with the ßow- uncertainty due to the differences between the refer- ing stream at times above and at times below the hydro- ence point and the spot sample method caused by carbon dew point temperature, operating below the hydrocarbon dew point in the ¥ Not knowing exactly how the operating conditions sample loop. related to the phase boundary at different locations within the ßow loop during some tests.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 51. APPENDIX D—HYDROGEN SULFIDE WARNING Inhalation of hydrogen sulÞde (H2S) at certain concentrations can lead to injury or death. H2S is an extremely toxic, ßammable gas that may be encountered in the produc- tion and processing of gas well gas, high-sulfur-content crude oil, crude oil fractions, asso- ciated gas and associated waters. Since H2S is heavier than air, it can collect in low places in still air. It is colorless and has a foul, rotten-egg odor. In low concentrations it is detect- able by its characteristic odor. Smell cannot be relied upon to forewarn of dangerous con- centrations however, because exposure to high concentrations of the gas (greater than 100 parts per million) rapidly paralyzes the sense of smell. A longer exposure to lower concen- trations has a similar desensitizing effect on the sense of smell. Utilize H2S monitoring systems to accurately determine H2S levels. Excessive exposure to hydrogen sulÞde (H2S) causes death by poisoning the respiratory system at the cellular level. There is some indication that the presence of alcohol in the blood aggravates the effects of H2S in acute poisoning cases. At low concentrations (10 to 50 parts per million), H2S is irritating to the eyes and respiratory tract. Closely repeated, short-term exposures at low concentrations may lead to irritation of the eyes, nose and throat. Symptoms from repeated exposures to low concentrations usually disappear after not being exposed for an appropriate period of time. Repeated exposures to low concentrations that do not produce effects initially can eventually lead to irritation if the exposures are frequent. The sense of smell may be rendered ineffective by hydrogen sulÞde (H2S), which can result in an individual failing to recognize the presence of dangerously high concentrations. 41COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
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  • 53. APPENDIX E—API LABORATORY INSPECTION CHECKLIST Lab Number: Date: Survey Team Members: Sample Handling & Conditioning YES NO Are sample cylinders heated? If sample cylinders are heated, to what temperature? Is the sample cylinder temperature monitored? Is the sample heated for at least 2 hours? Is time monitored for sample cylinder heating? What is the length of time used for heating sample cylinders? (# hours) Are samples taken immediately from heater to analyzer if manually transferred? What method is used to insulate heated sample cylinders during analysis? Insulated Blanket Heated Cabinet Other (Specify in Comments) Physical Facility YES NO Is the analyzer room heated? Is the analyzer room Air-conditioned? Filters, Connections, and Hardware YES NO Are Þlters used between sample and analyzer? Type: Size: Replacement Interval: What are the size, length and material of sample line and Þttings? Are connections, lines, and hardware between sample cylinder and analyzer insulated? Are connections, lines & hardware between sample cylinder and analyzer heated? Sample loop size is: 0.25 cc 0.50 cc 1.00 cc Other (specify size) 43COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 54. 44 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT Injection System YES NO Is the sample system a vacuum injection system? Is the sample system a purge injection system? If purge injection system, is there back pressure? Can the purge rate be read or measured? What is the purge rate? Analyzer YES NO What is the analyzer brand? What is the analyzer model? What is the analyzerÕs serial number? Is this an isothermal run? If ÒYES,Ó record temperature in ¡C If ÒNO,Ó secure a copy of the temperature program. Are the columns conÞgured per GPA 2261? If ÒNO,Ó list the conÞguration Integration method is: Peak Height Area Data logging: Manual Electronic Highest carbon number component analyzed is: C6 C6+ C7 C7+ Other (Specify) Calibration schedule is: Daily Weekly Monthly Other (Specify) Analysis frequency is: Daily Weekly Monthly Other (specify)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 55. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 45 Carrier Gas YES NO What is used as the carrier gas? What is the purity of the carrier gas? Is the carrier gas pressure monitored? Is the carrier gas ßow rate monitored? If yes, carrier gas ßow rate in cc/minute: Is a carrier gas drier used? If yes, type of drier material used: Replacement interval of carrier gas drier material: Calibration Standard Gas YES NO Manufacturer of calibration standard Is calibration standard age less than a year old? If ÒNO,Ó list the date blended Is the calibration standard heated continuously? If no, list the length of time heated before use: To what temperature is the calibration standard heated? Is an insulation blanket or heated cabinet used for the calibration standard? Can the cylinder pressure of the calibration standard be monitored? If yes, record the pressure in PSIG before and after each test. Does the lab have calibration standards required for the test program? Is the hydrocarbon dew point for the calibration standard available? If yes, hydrocarbon dew point: Has or could the calibration standard ever been exposed to a tempera- ture below the hydrocarbon dew point?COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 56. 46 API MANUAL OF PETROLEUM MEASUREMENT STANDARDS, CHAPTER 14—NATURAL GAS FLUIDS MEASUREMENT Calculation YES NO Are the component constants used in accordance with the latest GPA 2145? If ÒNO,Ó what constants are used? Can the constants be veriÞed? Are the calculations performed in accordance with the latest version of GPA 2172? Other methods used: Values for C6+ or other heavy fraction: C6 C6+ C7 C7+ Other (Specify) Composition of fraction: C6 C7 C8+ Other (Specify) Quality Control Program YES NO Does a Quality Control Program exist? Can a copy of the Quality Control Program be obtained? NOTE: Rating by Team Documentation YES NO Secured area counts and response factors? Secured chromatograms and results? Secured copy of analysis report for calibration standards? Secured relative density? Secured HVÑsaturated and unsaturated both real and ideal? Secured mol% both normalized and unnormalized? Secured starting and ending pressures for both labÕs calibration stan- dard and audit groupÕs standards. NOTE: Normal heating time for sample cylinders is 24 hr (±2 hr)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 57. SECTION 2—COLLECTING AND HANDLING OF NATURAL GAS SAMPLES FOR CUSTODY TRANSFER 47 Repeatability and Reproducibility The table below lists API-recommended laboratory repeatability and reproducibility criteria. The repeatability is deÞned, using the API deÞnition, as the comparison of back to back runs, using the same sample, chromatograph and operator. Reproducibility can be deÞned in two ways, using either the API deÞnition of reproducibility as the comparison of results between two labs on the same sample, or using ÒWarren Reproducibility,Ó which is deÞned as the comparison between the gravi- metrically determined composition of the calibration standard and the analysis from the lab. Reproducibility Criteria Repeatability Criteria (Using API or Warren DeÞnition) Mol % Max.Allowed Deviation Mol % Max.Allowed Deviation Concentration (± Mol%) Concentration (± Mol %) 0 to 1 0.02 0 to 1 0.04 > 1 to 5 0.10 > 1 to 5 0.13 > 5 to 15 0.18 > 5 to 15 0.26 > 15 to 30 0.28 > 15 to 30 0.38 > 30 to 50 0.40 > 30 to 50 0.50 > 50 0.52 > 50 0.63COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
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