This chapter specifies the characteristics of stationary (fixed) or portable tank provers that are in general use and the procedures for their calibration. Guidelines are provided for the design, manufacture, calibration and use of new and/or replacement tank provers, and are not intended to make any existing tank provers obsolete. 

More specific design criteria are available in NIST1 Handbook 105-3, Specifications and Tolerances for Graduated Neck-Type Volumetric Field Standards (includes Provers, per Section 1.1 of NIST 105-3). Consideration must also be given to the requirements of any weights and measures authority that may be involved.

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This section of API MPMS Chapter 5 covers the unique installation requirements and performance characteristics of turbine meters in liquid-hydrocarbon service.

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1.1 This standard is applicable to custody transfer applications for liquid hydrocarbons. Topics covered are: 

a. Applicable API standards used in the operation of Coriolis

meters.

b. Proving and verification using both mass- and volume based

methods.

c. Installation.

d. Operation.

e. Maintenance.

1.2 The mass- and volume-based calculation procedures for proving and quantity determination are included in Appendix E.

1.3 Although the Coriolis meter is capable of simultaneously determining density, this document does not address its use as a stand-alone densitometer. See API MPMS Chapter 14.6 for this type of application. The measured density from the Coriolis meter is used to convert mass to volume.

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This publication describes the metering function of a LACT unit and is intended to complement API Specification 11N, Specification for Lease Automatic Custody Transfer (LACT) Equipment. LACT equipment includes a meter (either displacement or turbine), a proving system (either fixed or portable), devices for determining temperature and pressure and for sampling the liquid, and a means of determining nonmerchantable oil. Many of the aspects of the metering function of a LACT unit are considered at length in other parts of this manual and are referenced in 6.1.4.

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This chapter describes the methods, equipment, and procedures for determining the temperature of petroleum and petroleum products under both static and dynamic conditions. This chapter discusses temperature measurement requirements in general for custody transfer, inventory control, and marine measurements. The actual method and equipment selected for temperature determination are left to the agreement of the parties involved.

Temperatures of hydrocarbon liquids under static conditions can be determined by measuring the temperature of the liquid at speciÞc locations. Examples of static vessels are storage tanks, Þeld gathering tanks, ships, barges, tank cars, tank provers, and test measures. Three methods are available for determining average static tank temperatures for custody transfer.

• Automatic method using fixed electronic temperature sensors.

• Manual method using portable electronic thermometers.

• Manual method using mercury-in-glass thermometers.

The automatic method covers the determination of temperature using Þxed automatic tank temperature (ATT) systems for hydrocarbons having a Reid Vapor Pressure at or below 101 kPa (15 pounds per square inch absolute). ATT systems include precision temperature sensors, Þeld-mounted transmitters for electronic signal transmission, and readout equipment.

The manual method covers:

• nonpressurized tanks and marine vessels

• blanketed tanks and marine vessels

• tanks and marine vessels that have been made inert and are under pressures of less than 21 kPa (3 pounds per square inch gauge)

It does not cover hydrocarbons under pressures in excess of 21 kPa (3 pounds per square inch gauge) or cryogenic temperature measurement, unless the tank is equipped with a thermowell.

Temperatures of hydrocarbon liquids under dynamic conditions can be determined by measuring the temperature of the liquid as it is flowing through a pipe. Dynamic temperature can be determined automatically or manually using electronic temperature devices or mercury-in-glass thermometers. The use of thermowells may be required in dynamic measurement to isolate the liquid material from the temperature sensor.

The requirements of this chapter are based on practices for crude oils and petroleum products covered by API MPMS Chapter 11.1 (ASTM D 1250). Requirements in this chapter may be used for other fluids and other applications. However, other applications may require different performance and installation specifications.

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This practice covers procedures and equipment for manually obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container are described. Procedures are also included for the sampling of free water and other heavy components associated with petroleum and petroleum products.

This practice also addresses the sampling of semi-liquid or solid-state petroleum products. For the sampling of green petroleum coke, see Practice D8145. For the sampling of calcined petroleum coke, see Practice D6970.

This practice provides additional specific information about sample container selection, preparation, and sample handling.

This practice does not cover sampling of electrical insulating oils and hydraulic fluids. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3).

The procedures described in this practice may also be applicable in sampling most non-corrosive liquid industrial chemicals provided that all safety precautions specific to these chemicals are followed. Also, refer to Practice E300. The procedures described in this practice are also applicable to sampling liquefied petroleum gases and chemicals. Also refer to Practices D1265 and D3700. The procedure for sampling bituminous materials is described in Practice D140. Practice D4306 provides guidance on sample containers and preparation for sampling aviation fuel.

Units—The values stated in SI units are to be regarded as the standard. USC units are reflected in parentheses.

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, health, and environmental 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.
 

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This practice describes general procedures and equipment for automatically obtaining samples of liquid petroleum and petroleum products, crude oils, and intermediate products from the sample point into the primary container. This practice also provides additional specific information about sample container selection, preparation, and sample handling. If sampling is for the precise determination of volatility, use Practice D5842 (API MPMS Chapter 8.4) in conjunction with this practice. For sample mixing and handling, refer to Practice D5854 (API MPMS Chapter 8.3). This practice does not cover sampling of electrical insulating oils and hydraulic fluids.

Units—The values stated in either SI units or US Customary (USC) units are to be regarded separately as standard. The values stated in each system may not be exact equivalents; therefore, each system shall be used independently of the other. Combining values from the two systems may result in non-conformance with the standard. Except where there is no direct SI equivalent, such as for National Pipe Threads/diameters, or tubing.

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, health, and environmental 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.
 

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This test method covers the laboratory determination using a glass hydrometer 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 pressure 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 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, alternative calibration temperature effects and to the reference temperature by means of the Petroleum Measurement Tables; values obtained at other than the reference temperature being hydrometer readings and not density measurements.

Readings determined as density, relative density, or API gravity 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 both, or tables, as applicable.

The initial hydrometer readings determined in the laboratory shall be recorded before performing any calculations. The calculations required in Section 10 shall be applied to the initial hydrometer reading with observations and results reported as required by Section 11 prior to use in a subsequent calculation procedure (ticket calculation, meter factor calculation, or base prover volume determination).

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

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

Exception—The values given in parentheses are provided 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.

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 test method describes the laboratory determination of water and sediment in crude oils by means of the centrifuge procedure. This centrifuge method for determining water and sediment in crude oils is not entirely satisfactory. The amount of water detected is almost always lower than the actual water content. When a highly accurate value is required, the revised procedures for water by distillation, Test Method D4006 (API MPMS Chapter 10.2) (Note 1), and sediment by extraction, Test Method D473 (API MPMS Chapter 10.1), shall be used.

NOTE 1—Test Method D4006 (API MPMS Chapter 10.2) has been determined to be the preferred and most accurate method for the determination of water.

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. Specific warning statements appear in 6.1, 8.3, and A1.5.4.

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