This standard describes the minimum specifications for electronic gas measurement systems used in the measurement and recording of flow parameters of gaseous phase hydrocarbon and other related fluids for custody transfer applications utilizing industry recognized primary measurement devices.

Electronic gas measurement (EGM) systems may be comprised of a number of components which work together to measure and record gas flow as shown in Figure 1. The components contained in the cloud are considered part of the EGM system. The components may be considered individually or be integral parts of the EGM system and the calculations may be performed onsite and/or off-site.

This standard provides the minimum reporting and change management requirements of the various intelligent components required for accurate and auditable measurement. The requirements can be met by a combination of electronically and/or manually recorded configuration, test reports, change record reporting of the electronic gas measurement system components and flow parameters. It is recognized that diagnostic capabilities of the newer meter and transmitter technologies are important but due to the device specific complexity, intelligent device diagnostics are out of scope for this standard.

For all existing installations, the decision to upgrade the system to satisfy the current standard is at the discretion of the parties involved

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General

This document defines the application criteria for UFMs and addresses the appropriate considerations regarding the liquids to be measured. This document addresses the installation, operation, and maintenance of UFMs in liquid hydrocarbon service.

Field of Application

The field of application of this standard is the dynamic measurement of liquid hydrocarbons. While this document is specifically written for custody transfer measurement, other acceptable applications may include allocation measurement, check meter measurement, and leak detection measurement. This document only pertains to spool type, multi-path ultrasonic flow meters with permanently affixed acoustic transducer assemblies.

This standard can be purchase via the American Petroleum Institute (API) website www.api.org 

This test method covers the determination, using a glass thermohydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids and having a Reid vapor pressures of 101.325 kPa (14.696 psi) or less. Values are determined at existing temperatures and corrected to 15 °C or 60 °F by means of a series of calculations and international standard tables. 

The initial thermohydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a thermohydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of calculations and Adjunct to D1250 Guide for Use of the Petroleum Measurement Tables (API MPMS Chapter 11.1). 

Readings determined as density, relative density, or API gravity can be converted to equivalent values in the other units or alternate reference temperatures by means of Interconversion Procedures (API MPMS Chapter 11.5) or Adjunct to D1250 Guide for Use of the Petroleum Measurement Tables (API MPMS Chapter 11.1), or both, or tables as applicable. 

The initial thermohydrometer reading shall be recorded before performing any calculations. The calculations required in Section 9 shall be applied to the initial thermohydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination). 

Annex A1 contains a procedure for verifying or certifying the equipment of this test method. 

The values stated in SI units are to be regarded as standard. 

Exception—The values given in parentheses are for information only. 

This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. 1.8 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.

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This standard establishes the basic concepts and procedures to estimate and report meter performance uncertainty in consistent and comparable ways.

This standard is available for purchase at the API Publication Store: https://www.apiwebstore.org/standards/13_2

This standard reviews basic statistical concepts and uses such to establish a methodology to develop uncertainty analyses for use in writing API Manual of Petroleum Measurement Standards (MPMS) documents that are consistent with the ISO GUM and NIST Technical Note 1297.

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The purpose of this standard is to provide a comprehensive guideline for properly collecting, conditioning, and handling representative samples of natural gas that are at or above their hydrocarbon dew point.

The standard considers spot, composite, continuous, and mobile sampling systems. This standard does not include sampling of liquid streams.

This standard includes comments identifying special areas of concern or importance for each sampling method included. It is intended for custody transfer measurement systems and may be applicable to allocation measurement systems.

The accuracy of moisture determinations from samples collected using the recommendations in this standard has not been determined.

This standard is available for purchase at the API Publication Store: https://www.apiwebstore.org/standards/14_1 

This standard covers the level measurement of liquid hydrocarbons in stationary, aboveground, atmospheric storage tanks using automatic tank gauges (ATGs). The standard discusses automatic tank gauging in general, accuracy, installation, commissioning, calibration, and verification of ATGs that measure either innage or ullage. It covers both intrusive and non-intrusive ATGs used for either custody transfer or inventory control. The standard also covers the requirements for data collection, transmission, and receiving.

This standard does not cover the following:

a) Hydrocarbons having a Reid vapor pressure above 15 pounds per square inch (in.) absolute (100 kPa).

b) Measurement of weight or mass with ATG equipment. This is covered in Chapter 3.6 and Chapter 16.2 of the Manual of Petroleum Measurement Standards.

c) Measurement of the level in underground tanks or in pressurized tanks storing liquid hydrocarbons.

d) Conversion of the tank level to liquid volume this is covered in Chapter 12.1 of the Manual of Petroleum Measurement Standards.

e) Measurement of temperature, sampling, density, and sediment and water (S and W), which are discussed in Chapters 7–10 of the Manual of Petroleum                 Measurement Standards.

Safety and material compatibility precautions should be taken when using ATG equipment. Manufacturers’ recommendations on the use and installation of the equipment should be followed. Users should comply with all applicable codes and regulations, API standards, and the NFPA National Electrical Code.

 This standard is available for purchase at the API Publication Store: https://www.apiwebstore.org/standards/3_1B

This standard describes the following:

a) the procedures for manually gauging the liquid level of petroleum and petroleum products in nonpressure fixed-roof, floating-roof tanks and marine tank vessels;

b) procedures for manually gauging the level of free water that may be found with the petroleum or petroleum products;

c) methods used to verify the length of gauge tapes under field conditions and the influence of bob weights and temperature on the gauge tape length; and

d) influences that may affect the position of gauging reference point (either the datum plate or the reference gauge point).

Throughout this standard the term petroleum will be used to denote petroleum, petroleum products, or the liquids normally associated with the petroleum industry.

This standard is applicable for gauging quantities of liquids having Reid vapor pressures less than 103 kPa (15 psia).

The method used to determine the volume of tank contents from gauge readings is not covered in this standard.

The determination of temperature, density, API gravity, and suspended sediment and water of the tank contents are not within the scope of this standard; however, methods used for these determinations may be found in the API Manual of Petroleum Measurement Standards (MPMS).

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This test method covers the determination of the density or relative density of light hydrocarbons including liquefied petroleum gases (LPG) having Reid vapor pressures exceeding 101.325 kPa (14.696 psi). 

The prescribed apparatus should not be used for materials having vapor pressures higher than 1.4 MPa (200 psi) at the test temperature. This pressure limit is dictated by the type of equipment. Higher pressures can apply to other equipment designs. 

The initial pressure hydrometer readings obtained are uncorrected hydrometer readings and not density measurements. Readings are measured on a hydrometer at either the reference temperature or at another convenient temperature, and readings are corrected for the meniscus effect, the thermal glass expansion effect, alternate calibration temperature effects and to the reference temperature by means of calculations and Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1) or API MPMS Chapter 11.2.4 (GPA TP-27), as applicable. 

Values determined as density or relative density can be converted to equivalent values in the other units or alternative reference temperatures by means of Interconversion Procedures API MPMS Chapter 11.5, or Adjunct to D1250 Guide for Petroleum Measurement Tables (API MPMS Chapter 11.1) or API MPMS Chapter 11.2.4 (GPA TP-27), as applicable. 

The calculations required in Section 11 shall be applied to the initial pressure hydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (measurement ticket calculation, meter factor calculation, or base prover volume determination). 1.6 Annex A1 contains a procedure for verifying or certifying the equipment for this test method. 

The values in SI units are to be regarded as the standard. US Customary values shown in adjacent parentheses are for information only and may not be exactly equivalent. Both SI and customary units have been rounded so that they may not be exactly equivalent. 

This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. 

This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.
 

This standard can be purchase via the American Petroleum Institute (API) webstore: https://www.apiwebstore.org/standards/9_2

These intraconversion tables are applicable to all crude oils, petroleum products, and petrochemicals.

This standard can be purchase via the American Petroleum Institute (API) webstore:  https://www.apiwebstore.org/standards/11_5_1