Manual of Petroleum
Measurement Standards
Chapter 6.3A
Metering Assemblies—Pipeline and Marine Loading/
Unloading Measurement Systems
FIRST EDITION, JULY 2021
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Copyright © 2021 American Petroleum Institute
ii
Foreword
Revision of API MPMS Chapter 6, Metering Assemblies, First Edition (2021) is ongoing. The revision supersedes all
previous API MPMS Chapter 6 standards with the following four separate standards:
— API MPMS Chapter 6.1A, Metering Assemblies—General Considerations, First Edition (2021);
— API MPMS Chapter 6.2A, Truck and Rail Loading and Unloading Measurement Systems, First Edition (2021);
— API MPMS Chapter 6.3A, Pipeline and Marine Loading/Unloading Measurement Systems, First Edition (2021);
— API MPMS Chapter 6.4A, LACT Systems, First Edition (2021).
These standards supersede the previous API MPMS Chapter 6 standards as follows:
— API MPMS Chapter 6.1A, Metering Assemblies—General Considerations, First Edition (2021) specifies the
common requirements for all metering systems and does not supersede any previous API MPMS Chapter 6
standards.
— API MPMS Chapter 6.2A, Truck and Rail Loading and Unloading Measurement Systems, First Edition (2021),
supersedes API MPMS Chapter 6.2, Loading Rack Metering Systems, Third Edition (2004), which will be withdrawn
on the publication of API MPMS Chapter 6.2A.
— API MPMS Chapter 6.3A, Pipeline and Marine Loading/Unloading Measurement Systems, First Edition (2021),
supersedes API MPMS Chapter 6.5, Metering Systems for Loading Marine Bulk Carriers, Second Edition (1991),
and API MPMS Chapter 6.6, Pipeline Metering Systems, Second Edition (1991), and Section 5.3.5 of Chapter 6.3A
supersedes API MPMS Chapter 6.7, Metering Viscous Hydrocarbons, Second Edition (1991), all of which will be
withdrawn.
— API MPMS Chapter 6.4A, LACT Systems, First Edition (2021), supersedes API MPMS Chapter 6.1, Lease
Automatic Custody Transfer (LACT) Systems, Second Edition (1991), and Section 5.2 of Chapter 6.4A supersedes
API MPMS Chapter 6.7, Metering Viscous Hydrocarbons, Second Edition (1991), all of which will be withdrawn on
the publication of API MPMS Chapter 6.4A.
NOTE API MPMS Chapter 6.7 is superseded by both Chapter 6.3A and Chapter 6.4A. Therefore, API MPMS Chapter 6.7
will be withdrawn when both Chapter 6.3A and Chapter 6.4A are published.
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 product covered by letters patent. Neither should anything
contained in the publication be construed as insuring anyone against liability for infringement of letters patent.
The verbal forms used to express the provisions in this document are as follows.
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Should: As used in a standard, “should” denotes a recommendation or that which is advised but not required to
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May: As used in a standard, “may” denotes a course of action permissible within the limits of a standard.
Can: As used in a standard, “can” denotes a statement of possibility or capability.
This document was produced under API standardization procedures that ensure appropriate notification and participation
in the developmental process and is designated as an API standard. Questions concerning the interpretation of the
iii
content of this publication or comments and questions concerning the procedures under which this publication was
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Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A one-time
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Suggested revisions are invited and should be submitted to the Standards Department, API, 200 Massachusetts
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iv
Contents
Page
1
Scope............................................................................................................................................................. 1
2
Normative References................................................................................................................................... 1
3
3.1
3.2
Terms, Definitions, and Symbols................................................................................................................... 1
Terms and Definitions.................................................................................................................................... 1
Acronyms, Abbreviations, and Symbols........................................................................................................ 2
4
4.1
4.2
4.3
Metering System Overview............................................................................................................................ 2
Pipeline Metering Systems............................................................................................................................ 3
Marine Metering Systems.............................................................................................................................. 3
FPSO and FSO Marine Metering Systems.................................................................................................... 4
5
5.1
5.2
5.3
System Design and Installation Considerations............................................................................................ 4
Define Design Criteria.................................................................................................................................... 4
Metering Technology Selection...................................................................................................................... 5
Meter System Configuration.......................................................................................................................... 6
6
6.1
6.2
6.3
Prover Selection Considerations................................................................................................................. 12
General........................................................................................................................................................ 12
Stationary vs. Portable Provers................................................................................................................... 12
Prover Types................................................................................................................................................ 13
7
7.1
7.2
7.3
7.4
7.5
7.6
7.7
Quality Determination.................................................................................................................................. 14
General........................................................................................................................................................ 14
Sampling...................................................................................................................................................... 14
Density......................................................................................................................................................... 15
Sediment and Water (S&W) Determination................................................................................................. 15
Viscometers................................................................................................................................................. 15
Compositional Analysis................................................................................................................................ 15
Other Quality Considerations....................................................................................................................... 16
8
8.1
8.2
8.3
8.4
8.5
8.6
8.7
8.8
8.9
Additional Metering System Component Design Considerations................................................................ 16
Temperature................................................................................................................................................. 16
Pressure...................................................................................................................................................... 16
Flow Conditioning........................................................................................................................................ 17
Strainers...................................................................................................................................................... 17
Insulation/Heating Systems......................................................................................................................... 17
Valves.......................................................................................................................................................... 18
Air/Vapor Eliminators................................................................................................................................... 19
Automation and Controls............................................................................................................................. 20
Access......................................................................................................................................................... 21
9
9.1
9.2
9.3
9.4
9.5
9.6
Operational Considerations and Maintenance............................................................................................. 21
Volume or Mass Calculation........................................................................................................................ 21
Documentation and Records....................................................................................................................... 21
Strainers...................................................................................................................................................... 21
Valves.......................................................................................................................................................... 22
Volume/Mass Primary Measurement Devices............................................................................................. 22
Secondary Measurement Devices............................................................................................................... 22
v
Contents
Page
Bibliography.............................................................................................................................................................. 23
Figures
1
2
3
4
5
6
7
Typical Marine Unloading Multi-Meter Run System with a Stationary Prover System (Individual Outlet
Return)........................................................................................................................................................... 3
Typical Single Meter Run System with a Portable Prover............................................................................. 7
Typical Single Meter Run System with a Stationary Prover System.............................................................. 7
Typical Multi-Meter Run System with a Stationary Prover System (Common Return).................................. 9
Typical Multi-Meter Run System with a Stationary Prover System (Individual Return)............................... 10
Typical Bidirectional Metering System......................................................................................................... 11
Typical Meter Installation with Return Line for Maintaining Heat at the Meter............................................. 12
vi
Introduction
This standard serves as a guide in the selection, installation, and operation of pipeline and marine loading and
unloading, floating production, storage, and offloading (FPSO), and floating storage and offloading (FSO) metering
systems. This standard does not endorse or advocate the preferential use of any specific type of metering system or
meter.
In general, metering system installations have to meet certain fundamental requirements, including those that ensure
proper meter type, size, installation, and adequate protective and readout devices. Descriptions of metering system
components are included either in this standard or other API MPMS chapters.
Sections of Chapter 6 describe metering system design. Chapter 6.1A describes the general considerations applicable
to all metering systems and shall be consulted together with this standard (Chapter 6.3A) when designing pipeline and
marine loading and unloading meter systems. When aspects are covered under the scope of other chapters of the
API Manual of Petroleum Measurement Standards, and to avoid replication and conflict, they are not covered by this
standard. In these cases, this standard provides limited information and refers the user to those chapters.
Work sites and equipment operations may differ. Users are solely responsible for assessing their specific equipment
and premises in determining the appropriateness of applying the MPMS. At all times, users should employ sound
business, scientific, engineering, and judgment safety when using the MPMS.
The following scenarios are merely examples for illustration purposes only. (Each company should develop its own
approach.) They are not to be considered exclusive or exhaustive in nature. API makes no warranties, express or
implied, for reliance on or any omissions from the information contained in this document.
vii
Metering Assemblies—Pipeline and Marine Loading/Unloading
Measurement Systems
1 Scope
This standard is part of a set of documents that detail the minimum requirements for metering systems in single
phase liquid applications. This standard (Chapter 6.3A) details the specific requirements for the design, selection,
and operation of pipeline, marine loading and unloading, FPSO, and FSO metering systems.
LACT measurement, multiphase fluids, asphalts, wellhead, and subsea measurements are not covered by this
standard.
2 Normative References
The following referenced documents are indispensable for the application of this document. For dated references,
only the edition cited applies. For undated references, the latest edition of the referenced document (including
any amendments) applies.
API MPMS Chapter 6.1A, General Considerations
3 Terms, Definitions, and Symbols
3.1
Terms and Definitions
For the purposes of this document, the following terms and definitions apply. Terms of more general use may be
found in the API MPMS Chapter 1 Online Terms and Definitions Database.
3.1.1
floating production, storage, and offloading vessel
FPSO
A floating vessel designed to produce and process hydrocarbons from subsea sources or the collection of
produced oil from nearby platforms; store oil; and transfer the hydrocarbons to other vessels or pipelines for
transport.
3.1.2
floating storage and offloading vessel
FSO
A floating vessel designed to store produced hydrocarbons from nearby platforms or FPSOs, and transfer the
hydrocarbons to other vessels or pipelines for transport.
3.1.3
marine loading metering system
A metering system designed to measure hydrocarbons transferred from a shore terminal or refinery, or from
vessel to vessel.
3.1.4
marine metering system
A metering system designed to measure hydrocarbons from vessel to vessel, offshore platform to vessel, vessel
to shore facility, and shore facility to vessel for loading or unloading hydrocarbons.
3.1.5
marine unloading metering system
A metering system designed to measure hydrocarbons transferred from a vessel to a shore terminal, refinery, or
vessel.
1
2
API Manual of Petroleum Measurement Standards 6.3A
3.1.6
pipeline metering system
A metering system designed to measure hydrocarbons transferred between a pipeline and another pipeline,
terminal, or refinery.
3.1.7
turndown ratio
The ratio of the maximum capacity of a device (e.g., meter or metering system, transmitter) to the minimum
capacity of the device. Normally, the turndown ratio for a meter is determined by dividing the maximum normal
linear capacity by the minimum normal linear capacity. The turndown ratio for a transmitter is determined by
dividing the upper range value (URV) by the lower range value (LRV) (if nonzero).
3.1.8
vessel
A ship, barge, FPSO, FSO, tanker, or other watercraft used for the maritime storage or transportation of liquid
hydrocarbons.
3.1.9
viscous hydrocarbon
Any liquid hydrocarbon that resists flow because of high shear or tensile stress, and that therefore may require
special treatment or equipment in its handling or storage.
3.2
Acronyms, Abbreviations, and Symbols
DP
differential pressure
DB&B
double block and bleed
FPSO
floating production storage and offloading
FSO
floating storage and offloading
PLC
programmable logic controller
LPG
liquefied petroleum gas
NGL
natural gas liquid
4 Metering System Overview
A metering system is a combination of primary, secondary, and tertiary measurement components, along with
piping and other equipment and instrumentation necessary to determine the custody transfer quantity and data
documented on the measurement ticket. How the quantity on a ticket (also called quantity transaction record
(QTR), batch ticket, or measurement ticket) is calculated is dependent upon the type of meter used (volumetric
or mass) and the quantity units.
All metering systems in this section have the following general characteristics or functionality:
— flow meters to measure flow quantity;
— means to measure fluid properties or sample fluids for analysis of properties;
— means to inspect, verify, and calibrate devices and equipment that can affect custody transfer quantity
determination;
— accessibility for equipment maintenance;
— flow computation device(s).
Manual of Petroleum Measurement Standards Chapter 6.3A
4.1
3
Pipeline Metering Systems
A pipeline metering system is used for custody transfer measurement between a pipeline and connecting pipeline,
terminal, or refinery, and has the following characteristics:
— typically does not require large volume air eliminators. Small volume air eliminators should be considered for
applications where meters are installed vertically. A method of verifying the integrity of the high point bleeds
shall be provided;
— typically has reduced turndown considerations.
Refer to 5.3 for figures depicting various metering system designs.
4.2
Marine Metering Systems
4.2.1 General
A marine metering system is used for custody transfer measurement between a marine vessel and shore facility
or, for FPSOs and FSOs, between a marine vessel and other vessels or pipelines. Metering offers several
benefits, including minimum vessel turnaround time, increased reliability and accuracy, improved uncertainty,
traceable field standards (provers), automated reporting, and safety.
Figure 1—Typical Marine Unloading Multi-Meter Run System with a Stationary Prover System
(Individual Outlet Return)
4.2.2 Marine Loading and Marine Unloading Metering Systems
A marine loading metering system is designed to measure hydrocarbons transferred from a shore terminal,
refinery, or a vessel to a vessel. A marine unloading metering system is designed to measure hydrocarbons
4
API Manual of Petroleum Measurement Standards 6.3A
transferred from a vessel to a shore terminal, refinery, or a vessel. Figure 1 shows a typical marine unloading
measurement system; however, a marine loading measurement system is typically very similar, with the exception
that the air eliminator may not be required and the vessel loading system is downstream of the marine loading
measurement system. Some of the issues that need to be considered include the following:
— air elimination: required for marine unloading, may be required for loading. (see 8.7);
— line verification: reference API MPMS Chapter 17 for guidance on line verification:
— line displacement;
— compatibility with current cargo;
— quantity of line fill;
— typically have larger turndowns;
— minimization of vessel turnaround time.
4.3
FPSO and FSO Marine Metering Systems
FPSO and FSO marine metering systems are used to measure liquid hydrocarbon transferred from a floating
production and/or storage facility to a vessel. An FPSO or FSO marine metering system has the following
characteristics:
— Smaller footprint and weight are considerations;
— Equipment is typically mounted on self-contained skid.
— Vibration analysis is typically required.
— Additional offshore regulatory requirements may apply.
5 System Design and Installation Considerations
5.1
Define Design Criteria
Metering systems can have various configurations, depending on flow rate, intermittent or continuous operation,
maintenance requirements, redundancy requirements, economics, proving requirements, and prover design.
Metering systems are designed based on the fluid properties (density, viscosity, vapor pressure), operating
parameters (flow range, pressure, temperature, batch [parcel] sizes, etc.), and other requirements (available
utilities, bi-directional vs. unidirectional operation, etc.) associated with the application. Meter types are chosen
based on the meter’s ability to measure the fluid accurately over the required flow range. Meters are sized
depending on the overall system flow rate and meter run configuration (single or multiple meters). All system
components (meter, prover, sampling system, etc.) shall be designed to operating ranges, including pressure,
flow rate, and temperature ranges.
With all metering system configurations, lines to and from the prover should be sized so that aligning the meter to
the prover results in minimal flow rate change. Additionally, the design should allow for maintaining the operating
flow rate while the meter is being proved. This can be done by using control valves to balance flow.
To ensure accurate meter factors, metering systems shall be designed so that all the liquid that passes through
the meter passes through the prover, and there is no addition or removal of liquid between the meter and prover
during meter proving.
Manual of Petroleum Measurement Standards Chapter 6.3A
5
The number of vents, drains, and thermal relief valves on the piping connections between a meter(s) and prover
connection(s), and between a meter(s) and the point of custody transfer, should be kept to a minimum. If installed
in either of these locations, each vent, drain, or thermal relief valve shall be provided with a means to permit
examination for, or prevention of, leakage. Refer to API MPMS Chapter 6.1A for additional information.
If pressure relief is needed to protect the meter run, it should not be installed between the meter and the prover.
While it is not recommended, if pressure relief needs to be installed between the meter and the prover, a means
shall be in place to assure that the pressure relief is not leaking during proving operations, as this will greatly
affect meter factors attained from the proving. Refer to API MPMS Chapter 6.1A for additional information.
In Coriolis and ultrasonic meter applications, provisions for meter isolation should be considered in the design
to allow for periodic meter downtime to permit verification and, if required, adjustment of the zero of each meter.
5.2
Metering Technology Selection
Without precluding new technologies that may become available in the future, the following four technologies are
considered acceptable for use in custody transfer pipeline, marine, FPSO, and FSO metering systems:
— displacement meter;
— turbine meter;
— Coriolis force mass meter;
— ultrasonic meter.
Reference API MPMS Chapter 5.1 for guidelines for selecting meter types. Also, reference meter manufacturers’
and company measurement policy recommendations on meter flow ranges, pressure drop, and process fluids.
The following application characteristics may influence the meter technology selection:
— High viscosity:
— The use of displacement meters with high viscosity clearances should be considered.
— The use of conventional turbine meters without appropriate viscosity correction in this service is not
recommended.
— The increased pressure drop associated with a Coriolis meter should be considered in meter selection.
— High abrasiveness/contamination/paraffinic:
— Meter technology selection should consider the impact of erosion on the metering elements. The decision
should consider the type of contamination and degree of abrasiveness and its effect on the meter’s
metallurgy.
— Applications with high paraffin content may lead to a buildup on the meter internals and lead to a reduced
meter performance.
— High temperatures:
— May affect associated electronics that are close-coupled. Remote mounting of electronics should be
considered.
— Different clearances of mechanical meters may be required.
6
5.3
API Manual of Petroleum Measurement Standards 6.3A
Meter System Configuration
5.3.1 General
Typically, a metering system design consists of the following elements:
— inlet and outlet isolation valve;
— strainer;
— pressure, temperature, and density instrumentation;
— other liquid quality measurement devices, including sampling system;
— meter with applicable flow conditioning upstream and downstream piping;
— prover main-line block valve;
— prover inlet and outlet valve;
— stationary or portable prover;
— flow control/backpressure valve.
See Sections 7 and 8 for a more thorough discussion of each of the above.
5.3.2 Single Meter Run Systems
The single meter system design should be considered when the flow rate is in a consistent range within the linear
portion of the meter and can meet the turndown ratio of the meter, prover, sampling system, or other applicable
components.
If a single meter is provided and maintenance is required (e.g., for out-of-tolerance meter factor, mechanical
or electronic issue, etc.), either the custody transfer shall be halted or flow shall be diverted through a bypass
with an alternate means of custody transfer. Installation and use of a bypass should be undertaken only with
agreement by all parties involved with the custody transfer, including any government regulators. If a bypass is to
be provided, it shall incorporate a double block and bleed valve or other means (e.g., spectacle blind) to assure
that flow is not bypassing the meter when the meter is in operation. See Figures 2 and 3 for examples of typical
single meter run systems.
Manual of Petroleum Measurement Standards Chapter 6.3A
7
Figure 2—Typical Single Meter Run System with a Portable Prover
Figure 3—Typical Single Meter Run System with a Stationary Prover System
5.3.3 Multiple Meter Run Systems
Metering systems with multiple parallel meters are particularly well suited for applications that require a wide
range of flow rates. The operating range of each meter can be limited by selecting the number of meters operating
based on the total flow rate at any given time. Additionally, multiple meter run systems may have the added
advantage of being more cost effective, particularly in applications with large flow rates. See Figures 4 and 5 for
examples of typical multiple meter run systems.
8
API Manual of Petroleum Measurement Standards 6.3A
Additional advantages that multiple meter run systems have over single meter systems include:
— operational flexibility;
— improved system uncertainty;
— increased system turndown;
— system redundancy;
— optimized prover sizing;
— future system expansion.
The product flow can be aligned to flow through one or more of the meters at any one time using valve
alignment. The multiple meter run systems can have meters of the same size or multiple sizes depending on flow
requirements.
When designing multiple parallel meter run systems, control valve(s) may be required to regulate flow rate
through the meter during normal operations and proving operations. The meter shall be operated within the
manufacturer’s recommended operating range. Proving shall take place only when flowing conditions are stable
and near the normal operating conditions.
All multiple meter run systems shall include the capability to determine the flowing temperature and pressure for
the quantity of fluid that passes through each meter run.
Multiple meter run systems may include provisions to automatically enable or disable individual meter runs to
accommodate varying system flow rates.
Manual of Petroleum Measurement Standards Chapter 6.3A
Figure 4—Typical Multi-Meter Run System with a Stationary Prover System (Common Return)
9
10
API Manual of Petroleum Measurement Standards 6.3A
Figure 5—Typical Multi-Meter Run System with a Stationary Prover System (Individual Return)
5.3.4 Bidirectional Measurement Systems
In applications where a metering system is used for both deliveries and receipts, the measurement can be
achieved by use of crossover piping configurations, or by use of a bidirectional metering technology.
The recommended method for addressing measurement in bidirectional flow situations is through the installation
of crossover piping, with double block and bleed valves between the upstream and downstream piping of a
unidirectional metering system. With this arrangement, flow through the meters and prover is always in the same
direction and the instrumentation and other system components are optimally located.
While not recommended, some applications use a bidirectional meter. For bidirectional meter runs, several
issues have to be addressed:
— If required, the typical flow conditioner and flow conditioning sections are designed for operation in one
direction only, making it necessary to provide duplicate systems.
— Sampling systems are generally designed for one direction, so duplicate systems may be required.
— Strainers are generally designed for one direction, so duplicate systems may be required.
— Instrumentation, such as pressure and temperature measurement, may need to be duplicated.
— Flow control valves may need to be duplicated.
— Proving connections may need to be duplicated.
Manual of Petroleum Measurement Standards Chapter 6.3A
11
— Meter factors shall be obtained for flow in each direction.
— For some meter technologies, care has to be taken to position the prover connections so that the flow profile
through the meter is properly maintained in both directions.
Figure 6 shows the typical valve configuration using four double block and bleed valves to achieve bidirectional
flow through a unidirectional measurement system. To flow from point A to point B on Figure 6, valves V1 and V4
would be open and valves V2 and V3 would be closed. To flow from point B to point A on Figure 6, valves V3 and
V2 would be open and valves V1 and V4 would be closed.
Figure 6—Typical Bidirectional Metering System
5.3.5 Viscous Metering Systems
Viscous hydrocarbons present a higher resistance to flow, and therefore may require special treatment or
equipment to facilitate proper measurement. Many viscous liquids may need to be heated to lower the viscosity,
and/or blended with a less viscous hydrocarbon to reduce viscosity and facilitate handling.
Special consideration should be taken for meters, auxiliary equipment, and fittings to accommodate or mitigate
the effects of high temperatures during handling of heated liquids.
For heated viscous hydrocarbon systems, the following issues should be considered:
— Installation of insulation on the system to maintain temperature control and for personnel safety.
— Temperature limitations of, and effects on, system equipment.
— It is important that the temperature of the liquid be maintained within a reasonably close range because meter
accuracy is affected by variations in temperature and by the resultant viscosity change.
— Changes in temperature and viscosity may necessitate viscosity indexing, Reynolds number indexing,
and/or more frequent proving.
— Care should be taken when heating the liquid to ensure the product remains in the single phase.
— It is difficult to separate entrained air or vapor from most viscous liquids. As viscosity increases, the time
required for separating fine bubbles of air or vapor from the liquid increases. The removal of entrained bubbles
requires a large air eliminator to effect separation.
12
API Manual of Petroleum Measurement Standards 6.3A
— The type or size of air eliminator equipment depends on the amount of air to be encountered, the form in
which it will occur, the pumping rate, the viscosity of the liquid, and the overall accuracy requirements of
the installation.
Figure 7 shows one method to maintain heat in the measurement system by circulating the liquid through a return
line. The return line should tee off as close to the meter inlet as possible. In some applications, circulating the
liquid through the entire meter system might be advisable; in such cases, appropriate steps shall be taken to
ensure the measurement ticket reflects the amount returned. Valves should be located in the return line to allow
easy control of flow.
Figure 7—Typical Meter Installation with Return Line for Maintaining Heat at the Meter
6 Prover Selection Considerations
6.1
General
The first step when selecting a proving system is to determine whether to use a portable (mobile) prover or a
stationary prover for the meter or meter system. This may depend on company measurement policy, connection
agreements, and economics.
Once this decision has been made, selecting the type of prover is the next step. The selection of prover type will
be based on the required uncertainty, frequency of proving, required proving flow rates and turndown, physical
properties of the hydrocarbon liquid, available space and prover weight, environmental factors, installation
considerations, maintenance requirements, and regulatory requirements.
Although API MPMS Chapter 4 addresses centralized proving, this will not be discussed in this standard as it is
not typical for pipeline, marine, FPSO, or FSO applications.
6.2
Stationary vs. Portable Provers
Stationary provers are typically considered for applications involving the following:
— multiple meter runs;
— high proving frequency;
Manual of Petroleum Measurement Standards Chapter 6.3A
13
— remote location;
— wide process or fluid property changes;
— contractual requirements;
— product quality contamination;
— health, safety, environmental, and regulatory considerations.
Portable provers are typically considered for applications involving the following:
— single meter run;
— using a prover at multiple meter facilities;
— less frequent proving;
— single product lines;
— availability and accessibility of the proving operator;
— contractual requirements where allowed;
— health, safety, environmental, and regulatory considerations.
6.3
Prover Types
6.3.1 General
There are three types of provers used for meter calibration in the petroleum industry: displacement provers, tank
provers, and master meter provers.
6.3.2 Displacement Provers
The three types of displacement prover are bidirectional, unidirectional, and captive displacement. The
displacement prover is typically used for pipeline, marine, FPSO, or FSO applications. It is recommended that
a design factor be applied when sizing the prover to ensure a minimum of 1 in 10,000 resolution. Typically, the
design factor (e.g., 0.95) would be applied to the meter manufacturer’s nominal K-factor for sizing the prover
calibrated volume.
To ensure full compatibility, it is recommended that the prover size be selected based on the maximum normal
linear flow rate of the largest meter to be proved and the minimum design capacity for the smallest meter to be
proved.
When using meters with manufactured pulses (i.e., Coriolis and ultrasonic meters), it is recommended to consult
the meter and prover manufacturers when sizing displacement provers.
Refer to API MPMS Chapter 4.2[1] for additional details on displacement provers.
6.3.3 Tank Provers
Tank provers are not typically used in pipeline, marine, FPSO, or FSO applications because of limited volume
capacity and non-continuous flow operation.
Refer to API MPMS Chapter 4.4[2] for additional details on tank provers.
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API Manual of Petroleum Measurement Standards 6.3A
6.3.4 Master Meter Provers
Master meter proving is used when proving by the direct method is impractical due to meter characteristics,
logistics, time, space, economic, and safety considerations. However, it also allows for a much larger proving
volume, which may be helpful when calibrating meters having a non-uniform pulse output.
Some aspects to consider when using master meter provers:
— With the added uncertainty associated with the master meter, the overall measurement uncertainty for the
custody transfer quantity is increased relative to other proving technologies.
— The master meter accuracy could be affected by liquid viscosity, flow rate, density, temperature, or pressure.
— Ideally, master meters should be calibrated on the same fluid and flowing conditions that will be experienced
by the line meter. Proving conditions that deviate from actual operating conditions will introduce uncertainty
and inaccuracies.
Refer to API MPMS Chapter 4.5[3] for additional details on master meter provers.
7 Quality Determination
7.1
General
Product quality information (sediment and water, density, product composition, etc.) is required for determining
the meter factor and the custody transfer quantity. See API MPMS Chapter 6.1A for more details.
7.2
Sampling
7.2.1 General
Depending upon the purpose, samples may be collected proportional to flow using an automatic sampling system
or on a spot basis manually.
7.2.2 Automatic Sampling
Automatic sampling is used to collect a sample that represents the overall custody transfer quantity. The results
when physical property tests of such a sample are used to determine the net quantity of the transfer and are
typically documented on the measurement ticket.
There are two types of automatic sampling systems: inline sampling and sample loop. Both systems can produce
representative samples if properly designed and operated. An automatic sampling system consists of stream
conditioning (if required), a sample extraction device, a means of pacing the sampler proportional to flow or
time, and the delivery of the extracted sample to a container or an analyzer. Please refer to API MPMS Chapter
8.2[11] (low vapor pressure hydrocarbons), API MPMS Chapter 8.5[12] (volatile crude oil, condensates, and liquid
products), and GPA 2174[23] or ASTM D3700[22] (LPG) for more detailed discussions concerning the design of
automated sampling systems and the need for and implementation of a calibration and verification procedure for
sampling systems.
7.2.3 Manual Sampling
Manual sampling is used to collect a spot sample of a hydrocarbon liquid at a particular point in time or in
conjunction with a particular activity, such as meter proving. In the case of meter proving, the result from a density
test is used to determine the meter factor and is documented on the meter proving report.
Manual of Petroleum Measurement Standards Chapter 6.3A
15
Refer to Section 8.4 of API MPMS Chapter 8.1[10] (low vapor pressure hydrocarbons), ASTM D1265[21] (LPG),
and GPA 2174[23] or ASTM D3700[22] (LPG) for more information related to the design and operation of manual
sampling systems.
7.3
Density
7.3.1 General
Refer to API MPMS Chapter 6.1A for general guidance on density determination.
7.3.2 Density Meters
7.3.2.1 General
Reference API MPMS Chapter 9.4[13] for guidance on online density meter selection, design, operation, installation,
and calibration methods. Several common online density meter applications are addressed below.
7.3.2.2 Mass Determination
Density meters can be used for inferred mass measurement or direct mass measurement of NGL or LPG. Refer
to API MPMS Chapter 14.7[17] for guidance on the two mass measurement methods.
7.3.2.3 Volume Correction Factor Determination
Volumetric flow meter systems require density to determine correction factors for the effects of temperature and
pressure. Refer to the applicable sections of API MPMS Chapter 11[14] and API MPMS Chapter 12[15].
7.3.2.4 Product Quality
Density measurement may be used to determine fluid density over a batch or detect changes in fluid density.
7.3.2.5 Interface Detection
Density measurement may be used during batch operations to identify product changes to initiate the opening or
closing of the measurement ticket. Density readings may need to be corrected to standard conditions to prevent
false interface readings due to changes in temperature or pressure.
7.4
Sediment and Water (S&W) Determination
Refer to API MPMS Chapter 6.1A for information for S&W determination.
7.5
Viscometers
Viscometers are online instruments used to measure flowing viscosity. Viscometers can be used for viscosity
indexing or to initiate meter provings on viscosity changes.
7.6
Compositional Analysis
It is a requirement in the measurement of certain NGL and LPG streams to obtain a compositional analysis
that represents the individual hydrocarbon components of the metered product (refer to API MPMS Chapter
14.7[17]/GPA 8182[25] for more details). The compositional analysis is performed to quantify the component volume
metered and the subsequent value of the product. Each hydrocarbon component (i.e., methane, ethane, propane,
etc.) has a different monetary value that has to be calculated from the composition (refer to API MPMS 14.4[16]
for more details).
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API Manual of Petroleum Measurement Standards 6.3A
Where composite NGL and LPG samples are taken, they shall be analyzed using a recognized international
standard, such as GPA Method 2177[24]. In some cases, alternate methods of sampling may be acceptable, such
as spot sampling, or by the use of an online chromatograph.
7.7
Other Quality Considerations
Additional sampling may be requested or required to measure and/or verify product characteristics, such as
sulfur, RVP, octane, and flash point. Sampling and quality determination should be in accordance with industry
standards and contractual agreements.
8 Additional Metering System Component Design Considerations
8.1
Temperature
8.1.1 General
Temperature measurements are required for calculation of liquid quantities, prover volumes, and flowing density
at standard temperature. Refer to API MPMS Chapters 6.1A, 7.4[9], 9.4[13], and applicable sections of API MPMS
Chapter 12[15] and API MPMS Chapter 21.2[19].
8.1.2 Temperature Measurement at the Meter(s)
The objective when determining the temperature of metered liquid is to obtain an accurate liquid temperature
inside the meter body.
The temperature sensor is preferably installed downstream of the meter consistent with any flow conditioning
requirements. However, under certain circumstances, the temperature sensor can be installed on the inlet
manifold in accordance with API MPMS Chapter 7.4[9].
8.1.3 Temperature Measurement at the Prover
The goal is to determine the liquid temperature in the calibrated section of the prover. Reference API MPMS
Chapter 4 for temperature requirements on proving systems.
For displacement provers, the preferred location of the temperature measurement is not more than five pipe
diameters from the prover inlet and not more than five pipe diameters from the prover outlet. Additionally,
consideration should be given to installing the temperature measurement equidistant from the prover inlet/outlet
such that their average better represents the liquid temperature.
If a captive displacement prover is used, the temperature of the piston rod is required.
8.1.4 Test Thermowells
Test thermowell requirements are defined in API MPMS Chapter 6.1A.
8.2
Pressure
8.2.1 General
Pressure measurements are required for calculation of liquid quantities, prover volumes, and flowing density at
standard pressure. Refer to API MPMS Chapter 6.1A and applicable sections of API MPMS Chapter 12[15].
8.2.2 Pressure Measurement at the Meter(s)
The objective when determining the pressure of metered liquid is to obtain an accurate liquid pressure inside the
meter body.
Manual of Petroleum Measurement Standards Chapter 6.3A
17
The pressure sensor shall be installed downstream of the meter and as close to the meter as possible, preferably
no further than five pipe diameters from the meter run.
8.2.3 Pressure Measurement at the Prover
The goal is to determine the liquid pressure in the calibrated section of the prover. Reference API MPMS Chapter
4 for pressure requirements on proving systems.
Consideration should be given to installing the pressure measurement equidistant from the prover inlet/outlet
such that their average better represents the liquid pressure. If the prover inlet and outlet pressures are nearly
the same, one pressure sensor is acceptable providing it is installed on the prover outlet.
8.2.4 Pressure Calibration and Verification
Pressure devices should be installed so that in situ calibration and verification can be readily conducted. A
possible method of meeting this recommendation is installation of a gauge valve with quick connect fitting to
facilitate connection for the calibration or verification device.
8.2.5 Other Pressure Considerations
It is important to maintain adequate pressure in the measurement system to prevent cavitation or flashing. Refer
to API MPMS Chapter 6.1A for additional information on backpressure control.
8.3
Flow Conditioning
For meter types that are dependent on flow profile, the measurement system shall include a flow conditioning
section upstream and downstream of each meter per manufacturer recommendations. Refer to API MPMS
Chapter 5.3[6] and Chapter 5.8[8] for a full description of the arrangement and details for each meter technology.
8.4
Strainers
Strainers are recommended upstream of the meter to remove contaminants from the flow stream that may cause
fouling or damage to meters, valves, instrumentation, sampling equipment, and the prover. The strainer should
be designed to minimize pressure drop at maximum flow rate and viscosity. A maximum pressure drop between
15 kPa and 35 kPa (2 psi to 5 psi) is commonly used for design considerations.
A means of monitoring the differential pressure across the strainer is recommended. Increased differential
pressure could indicate that the strainer requires cleaning and could cause a flow profile distortion. Possible
methods of meeting this recommendation is a pressure sensor/gauge located on both sides of the strainer or a
single differential pressure transmitter/gauge installed across the strainer.
Ensure the design of the strainer does not influence the type of metering technology selected (consult meter
manufacturer). The strainer basket perforations and/or mesh size should be sized in accordance with the meter
manufacturer’s recommendations. A means should be provided to ensure the strainer basket is locked in position
for meters that are influenced by flow profile disturbances.
Consideration should be given to the method of lifting the basket from the strainer and the collection of drips
when lifted. Opening the strainer will require depressurizing and draining. The valve isolation requirements for
these operations should take into consideration if the metering system is in operation as pressure isolation and
hazardous area requirements may change.
8.5
Insulation/Heating Systems
8.5.1 Insulation
Insulation of the system may be required to maintain proper process liquid temperature, or for personnel safety. It
can be installed to maintain process liquid temperature between the temperature instrumentation and the meter
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API Manual of Petroleum Measurement Standards 6.3A
or the verification thermowells, as well as between the meter and prover. It can also be installed to maintain
system equipment within recommended temperature limits.
8.5.2 Heating
In addition to insulation, it may be necessary to add a heat source to maintain the process liquid and/or the
equipment within required temperature range.
If a heat source is added, ensure that there is no adverse effect on the process flow temperature between the
measurement point and the meter.
8.6
Valves
8.6.1 General
Anywhere a leak through a valve will cause a measurement error (e.g., prover mainline block valves, meter and
prover drain valves, prover diverter or interchange valves, relief valves, bypass valves), a means to verify the
valve integrity shall be provided.
8.6.2 Isolation Valves
For maintenance and isolation of meter runs, valves should be installed at both ends of each meter assembly
so that the meter and other components can be maintained without having to shut down product flow. The valve
upstream of the measurement device should be chosen to ensure negligible disturbance to the flow profile, which
could adversely affect the meter performance.
8.6.3 Prover Manifold Valves
Prover manifold valves (prover mainline block, inlet and outlet valves) are used to direct the flow to and from
the prover, and to ensure all liquid from the meter under test passes through the prover, and no fluid is being
introduced between the meter and the prover. All valves between the meter and the prover shall be a double
block and bleed arrangement or type, which provide a means of verifying positive isolation.
8.6.4 Bypass Valves
Bypass valves are a means of diverting the liquid flow around the meter for either equipment maintenance or
problems with the flowing stream. All bypass valves shall be double block and bleed type, which provide a means
of verifying positive isolation. Please refer to API MPMS Chapter 6.1A.
8.6.5 Double Block and Bleed Valves
A double block and bleed valve is a single valve with two seating surfaces that, in the closed position, provides a
seal against pressure from both ends of the valve, with a means to vent or bleed the cavity between the seating
surfaces to ensure valve integrity. The valve cavity should have a thermal relief to prevent valve damage.
8.6.6 Prover Four-way or Interchange Valves
The bidirectional prover four-way or unidirectional interchange valve shall establish complete liquid sealing while
the prover displacer travels through the prover calibrated section. The four-way or interchange bleed port should
be configured to verify valve integrity and should allow for visual or electronic means of seal verification. Refer to
API MPMS Chapter 4.2[1] for additional details on displacement provers.
Manual of Petroleum Measurement Standards Chapter 6.3A
19
8.6.7 Control Valves
8.6.7.1 General
Control valves are used for back pressure control, flow balancing, and flow control during proving operations.
Refer to API MPMS Chapters 5.2[5], 5.3[6], 5.6[7], and 5.8[8] for specific requirements.
8.6.7.2 Backpressure Control Valves
Backpressure control valves are used to ensure the liquid in the measurement system remains above the
equilibrium vapor pressure.
8.6.7.3 Flow Control Valves
Control of flow may be necessary in some applications, such as marine loading. Flow control is sometimes
required to ensure meters are maintained within their rated capacity, particularly where meters of different sizes
are provided in a multiple meter run system. Control of the flow rate during meter proving can be accomplished
using control valves on opposing meters (meters other than the one being proved) in multiple meter run systems.
NOTE
control.
If properly selected, a single control valve can be used to provide the required minimum backpressure and flow
8.6.8 Check Valves
A check valve is commonly provided to prevent back flow through the meter and/or prover.
8.6.9 Drain Valves
Metering system designs should include taps at low points so that the system may be drained before maintenance.
Use of drains between the meter and the prover should be minimized. Any drain that can affect measurement
accuracy shall be equipped with a means to prevent leaks or verify that no leaks exist.
8.6.10 Vent Valves
Metering system design should include high point vents to eliminate air, vapors, or non-condensable gases. Use
of vents between the meter and the prover should be minimized. Use of vents in the calibrated section of a pipe
prover should be avoided if possible. Any vent that can affect measurement accuracy shall be equipped with a
means to prevent leaks or verify that no leaks exist.
8.6.11 Pressure-relief Valves
Relief valves protect the system from the effects of overpressuring. Installation of thermal relief valves between
the meter and prover and between the metering system and the custody transfer point should be minimized.
If required in one of these locations, a thermal relief valve should be provided with a means to detect leakage.
Refer to API MPMS Chapter 6.1A for more details related to installation and leak detection.
8.7
Air/Vapor Eliminators
8.7.1 General
Each metering system shall be designed to prevent air or vapor from passing through it. If necessary, air/vapor
elimination equipment should be installed upstream of the metering system. Refer to API MPMS Chapter 6.1A
for more details.
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API Manual of Petroleum Measurement Standards 6.3A
8.7.2 Pipeline Operations
In a metering station, if a high vacuum (negative head) condition could exist, a block and/or check valve should
be installed in vent lines to prevent air from being drawn into the air eliminator. Operating and maintenance
procedures should be developed and followed to minimize the introduction and retention of air into metering
systems.
8.7.3 Marine Loading and Unloading Vessel Requirements
Marine loading does not generally present a severe air problem because tankage, manifolds, and lines are
normally kept full of liquid. However, air/vapor elimination equipment may still be required.
During marine unloading, air may be introduced each time load-arm connections are made to the carrier. Air/
vapor may also be introduced during a vessel’s stripping operations. For marine unloading, operations shall
ensure the piping from the vessel to the air eliminator is full of product prior to start of the transfer. Refer to API
MPMS Chapter 17.6[18] for further details. The air eliminator should also be equipped with a means of determining
level before and after the unloading operation.
Sizing of the air eliminator capacity is based both on the quantity of air and the liquid flow rate. For example,
air introduced in stripping operations will be introduced at the vessel stripping rates, and air introduced from
switching to empty vessel manifolds would be expected to occur at full flow rates. The air eliminator vessel
size will be a function of the air rising time in the particular product and the hold time it has to rise. The venting
capacity of the air eliminator will be a function of the rate that air is introduced, with some cushion from the
holding capacity of the vessel. It is uncommon that a meter run strainer body could provide adequate hold times
for air to rise through the fluid.
8.8
Automation and Controls
8.8.1 Flow Computers
A flow computer receives inputs from the primary device and the secondary devices. This data is either processed
in the flow computer or transferred to a central measurement calculation system to determine and document the
quantity transferred. Signals can be analog, digital, or digital communication protocol. The flow computer may be
used to provide control signals to automatic samplers and control valves, or initiate and perform meter proving
operations. For further information on flow computers, refer to API MPMS Chapter 21.2[19]. Due to the complexity
of calculations and strict requirements on processing time, the use of flow computers is recommended.
8.8.2 PLCs
Programmable logic controllers (PLCs) in pipeline and marine loading/unloading measurement systems are
typically used to monitor and control the portions of the metering system that are not directly involved in the
measurement of liquid hydrocarbons. Motor-operated meter isolation and prover routing valves are generally
separated from the flow measurement computer and connected to a PLC. This arrangement allows the separation
of operation and measurement functionality. Thus, the PLC often controls valve sequencing, brings meter runs
on line and off line, and aligns the proving device. Because the PLC has logic capability, it can manage alarm
conditions that could affect measurement, such as strainer high differential pressure. Furthermore, the PLC may
be used to control auxiliary equipment such as pumps, control valves, or sample extractors.
8.8.3 Supervisory and Control Systems
A supervisory system is optional and is most often used on larger and more complex applications. The supervisory
system is a computer-based or panel-type operator interface to an individual or multiple meter run systems. The
HMI may provide a graphical representation of the metering system to the operator. The supervisory system may
be used to perform manual or automatic operations, such as setting sample rate, printing and archiving tickets,
initiating provings, selecting and sequencing meter runs, generating reports, and other functions. In addition to
the flow computer, certain functions (e.g., measurement ticket, events/alarm report) of the supervisory systems
may form part of the measurement system audit trail.
Manual of Petroleum Measurement Standards Chapter 6.3A
21
8.8.4 Local Totalizers
Local totalizers can be used to back up the primary totalizers and provide a local indication of totalized flow to
the operator.
8.9
Access
Special considerations for accessing valves, equipment, and instrumentation are needed in FSO and FPSO
applications. It is typical that these metering stations are raised 3 m (10 ft) above the deck of the vessel. Extended
valve handles, additional walkways, and platforms are typically required.
9 Operational Considerations and Maintenance
9.1
Volume or Mass Calculation
Calculations used to produce a measurement ticket are selected based on the measured liquid fluid properties and
whether volumetric or mass measurement techniques are being applied. API MPMS Chapter 21.2[19] (volume),
API MPMS Chapter 21.2, Addendum 1[20], Section 2 (mass), and GPA 8182[25] outline calculation requirements.
Users should consider verification of measurement ticket calculations in accordance with API MPMS Chapter
12[15] and GPA 8182[25] and verification of flow computer configuration on a user-defined frequency: typically,
annually, or after changes to the configuration.
9.2
Documentation and Records
Provisions should be included to capture and retain documents and records (e.g., alarm event logs) as defined
by company policy, the connection, or other agreements and/or applicable government regulations.
An audit trail defines the documents and records necessary to allow the measurement ticket to be audited (refer
to API MPMS Chapter 21.2[19]). Elements of the audit trail may include:
— configuration logs;
— event and alarm log;
— pressure, temperature, and density verification records;
— prover calibration certificate;
— chromatograph calibration records (if applicable);
— calibration standard certificates.
9.3
Strainers
A maintenance program should be followed for inspection and cleaning of strainer baskets if no differential
pressure indication is provided.
If a means of monitoring differential pressure is provided, the pressure across the strainer should be monitored
regularly. High differential pressure is an indication that the basket contains debris and should be cleaned. Zero
or abnormally low differential pressure could be an indication that the basket may be ruptured and the strainer is
not providing adequate protection for downstream equipment.
22
9.4
API Manual of Petroleum Measurement Standards 6.3A
Valves
9.4.1 Double Block and Bleed Valves
All DB&B valves shall be verified at a user-defined frequency. If a valve fails to seal, the valve should be repaired.
9.4.2 Prover Four-way or Interchange Valves
Verify that the prover four-way or interchange valve is sealed during proving operation at a user-defined frequency.
If the valve fails to seal, the proving shall be aborted and the valve inspected. For further guidance, refer to API
MPMS Chapter 4.8[4].
9.5
Volume/Mass Primary Measurement Devices
Reference the appropriate section of API MPMS Chapter 5 for the applicable operation and maintenance
considerations for the selected metering technology.
9.6
Secondary Measurement Devices
9.6.1 Provers
Refer to API MPMS Chapter 4.8[4] for operation and maintenance requirements for provers.
9.6.2 Sampling Systems
Refer to API MPMS Chapter 8.2[11] for operation and maintenance requirements for sampling systems.
9.6.3 Density Meters
Refer to API MPMS Chapter 9.4[13] for operation and maintenance requirements—including the determination of
density meter factors (DMF)—for density meters.
9.6.4 Temperature and Pressure Devices
The verification or calibration of temperature and pressure-measuring devices is necessary to ensure they comply
with company, regulatory, or contractual requirements. See API MPMS Chapter 6.1A for further information.
9.6.5 Online Gas Chromatographs
Refer to GPA Method 2177[24] for operation and maintenance requirements for online gas chromatographs.
9.6.6 Tertiary Measurement Devices
Tertiary measurement devices consist of a flow computer. A flow computer maintenance program may include:
— verification of the configuration by comparing a previous configuration against the current configuration;
— verification of the flow computer’s input/output wiring.
Bibliography
[1] API MPMS Chapter 4.2, Displacement Provers
[2] API MPMS Chapter 4.4, Tank Provers
[3] API MPMS Chapter 4.5, Master Meter Provers
[4] API MPMS Chapter 4.8, Operation of Proving Systems
[5] API MPMS Chapter 5.2, Measurement of Liquid Hydrocarbons by Displacement Meters
[6] API MPMS Chapter 5.3, Measurement of Liquid Hydrocarbons by Turbine Meters
[7] API MPMS Chapter 5.6, Measurement of Liquid Hydrocarbons by Coriolis Meters
[8] API MPMS Chapter 5.8, Measurement of Liquid Hydrocarbons by Ultrasonic Flow Meters
[9] API MPMS Chapter 7.4, Dynamic Temperature Measurement
[10] API MPMS Chapter 8.1, Manual Sampling of Petroleum and Petroleum Products
[11] API MPMS Chapter 8.2, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products
[12] API MPMS Chapter 8.5, Standard Practice for Manual Piston Cylinder Sampling of Volatile Crude Oils,
Condensates, and Liquid Petroleum Products
[13] API MPMS Chapter 9.4, Continuous/On-line Density Measurement and Applications
[14] API MPMS Chapter 11 (All sections), Physical Properties Data
[15] API MPMS Chapter 12 (All sections), Calculation of Petroleum Quantities
[16] API MPMS Chapter 14.4, Converting Mass of Natural Gas Liquids to Equivalent Liquid Volumes
[17] API MPMS Chapter 14.7, Mass Measurement of Natural Gas Liquids and Other Hydrocarbons
[18] API MPMS Chapter 17.6, Guidelines for Determining Fullness of Pipelines Between Vessels and Shore
Tanks
[19] API MPMS Chapter 21.2, Electronic Liquid Volume Measurement Using Positive Displacement and Turbine
Meters
[20] API MPMS Chapter 21.2, Addendum 1, Flow Measurement Using Electronic Metering Systems, Inferred
Mass
[21] ASTM D1265, Standard Practice for Sampling Liquefied Petroleum (LP) Gases (Manual Method)
[22] ASTM D3700, Standard Practice for Obtaining LPG Samples Using a Floating Piston Cylinder
[23] GPA 2174, Obtaining Liquid Hydrocarbon Samples for Analysis by Gas Chromatography
[24] GPA 2177, Analysis of Natural Gas Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas
Chromatography
[25] GPA 8182, Standard for Mass Measurement of Natural Gas Liquids
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