This part provides standardized calculation methods for the determination of meter factors under defined conditions, regardless of the point of origin or destination or units of

measure required by governmental customs or statute. The criteria contained here will allow different entities using various computer languages on different computer hardware (or by manual calculations) to arrive at identical results using the same standardized input data. 

This document also specifies the equations for computing correction factors, including the calculation sequence, discrimination levels, and rules for rounding to be employed in the calculations. No deviations from these specified equations are permitted, since the intent of this document is to establish a rigorous standard.

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1.1 This standard describes the procedures for calibrating upright cylindrical tanks used primarily for the storage of petroleum liquids. It first addresses procedures for making necessary measurements to determine total and incremental tank volumes and then presents the recommended procedures for computing volumes.

1.2 Both SI (metric) and U.S. customary (USC) units are presented where appropriate in the document. SI and USC conversions may not necessarily be exact. The SI units often reflect what is available in commercial equipment.

1.3 The standard also provides guidelines for recalibration and for computerization of capacity tables.

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This chapter outlines the essential elements of provers that do, and also do not, accumulate a minimum of 10,000 whole meter pulses between detector switches, and provides design and installation details for the types of displacement provers that are currently in use. The provers discussed in this chapter are designed for proving measurement devices under dynamic operating conditions with single-phase liquid hydrocarbons. These provers consist of a pipe section through which a displacer travels and activates detection devices before stopping at the end of the run as the stream is diverted or bypassed.

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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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