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API MPMS 6.6 1991 (R2012): Design and Operation of Metering Systems for Pipeline Custody Transfer
An in-depth technical overview of the American Petroleum Institute Manual of Petroleum Measurement Standards Chapter 6.6, covering scope, key requirements, and compliance considerations.
Scope and Applicability
API MPMS 6.6 1991 (R2012), officially titled Metering System for Pipeline Metering, is the definitive standard for the design, installation, operation, and maintenance of metering systems used in hydrocarbon pipeline transportation. It is part of the broader API Manual of Petroleum Measurement Standards and applies specifically to custody transfer and inventory control metering where liquid petroleum products are transferred through pipelines.
The standard covers systems measuring crude oil, refined products, and other liquid hydrocarbons at pipeline terminals, delivery points, and interconnections. It addresses meter types including turbine, positive displacement (PD), and, by extension, Coriolis and ultrasonic meters when used in pipeline applications. The document provides criteria for ensuring measurement accuracy within ±0.25% of reading for custody transfer, consistent with API MPMS Chapter 13 and AGA standards for gas.
Originally published in 1991 and reaffirmed in 2012 without technical changes, the standard remains a foundational reference for operators, regulators, and EPC contractors worldwide. Its requirements are frequently cited in pipeline tariff filings and measurement agreements between shippers and carriers.
Important: While reaffirmed in 2012, this standard does not incorporate recent advances in metering technologies (e.g., Coriolis master meters or ultrasonic flowmeters). Users should supplement it with API MPMS Chapter 5 updates and relevant ISO standards for modern installations.
Key Technical Requirements
Meter Selection and Installation
The standard mandates that each metering system be designed to minimize measurement uncertainty under normal pipeline operating conditions. Meter selection must consider fluid properties (viscosity, density, vapor pressure), flow range, pressure, and temperature. For turbine meters, inlet flow conditioners (straightening vanes) are required to eliminate swirl and asymmetric velocity profiles. The minimum upstream straight pipe length is specified as 20 pipe diameters for turbine meters and 10 diameters for PD meters, measured from the nearest upstream disturbance (valve, tee, elbow).
Proving System Requirements
API MPMS 6.6 requires that each metering system be equipped with a prover capable of calibrating the meter at flow rates equivalent to normal operating conditions. The standard accepts two prover types: pipe provers (unidirectional and bidirectional) and, where approved by contractual agreement, master meter provers. Prover volume must be such that the proving run yields repeatability of ±0.02% or better over four consecutive runs. The prover must be temperature-compensated and pressure-corrected according to API MPMS Chapter 12 procedures.
Measurement and Correction
For custody transfer, the standard requires continuous measurement of flowing temperature and pressure at the meter location, with correction to reference conditions (normally 60 °F and 0 psig) using API MPMS Chapter 11.2.2 (or its successors) for crude oil and Chapter 11.1 for refined products. Density measurement must be performed either by a dedicated density meter inline or through periodic sampling and laboratory analysis, with density values reduced to 60 °F using API MPMS Chapter 9 or 11.2.1.
| Parameter | Required Measurement | Accuracy / Tolerance | Reference |
|---|---|---|---|
| Flow Rate | Continuous meter output | ±0.25% (Custody Transfer) | API MPMS 6.6 |
| Temperature | Flowing temperature at meter | ±0.5 °F (0.3 °C) | API MPMS 7 |
| Pressure | Flowing pressure at meter | ±0.33% of span | API MPMS 7 |
| Density | Inline or grab sample | ±0.5 kg/m³ (before correction) | API MPMS 9 / 11.2.1 |
| Prover Volume | Calibration certificate | ±0.02% repeatability | API MPMS 4.8 |
Implementation Highlights
When deploying a metering system in accordance with API MPMS 6.6, several practical aspects must be addressed:
- Flow conditioning: Even when the standard only explicitly mandates conditioners for turbine meters, it is good practice to install them for all meter types to ensure fully developed flow profiles. ISO 10790 and API MPMS 5.8 provide additional guidance for ultrasonic and Coriolis meters.
- Prover validation: The prover must be re-calibrated by a certified laboratory at least once every five years or whenever physical changes occur (repairs, coating modification, pipe replacement). Water draw tests per API MPMS 4.8 are used to confirm prover volume.
- Sampling: For crude oil and refined products, the standard requires reliable automatic sampling systems (API MPMS 8.2) unless the fluid is homogeneous and non-volatile. Flow-proportional samplers are preferred; time-proportional samplers are only acceptable for steady-flow applications.
- Secondary instrumentation: Temperature transmitters, pressure transmitters, and the flow computer should be calibrated on a schedule defined in a quality assurance plan, with at least annual verification to traceable standards.
Implementation Tip: When designing a new pipeline metering station, consider future expansion needs and allow adequate space for adding a second prover or a master meter loop. API MPMS 6.6 does not mandate redundancy, but many operational agreements require a backup proving system to minimize downtime.
Compliance and Reaffirmation Notes
Although API MPMS 6.6 was reaffirmed in 2012, operators must be aware that it reflects the state of the art as of 1991. Regulatory bodies such as the Pipeline and Hazardous Materials Safety Administration (PHMSA) in the United States, and many international jurisdictions, accept this standard as meeting the minimum requirements for measurement under federal pipeline safety regulations (49 CFR 195/192). However, for new installations, many operators voluntarily adopt later editions or supplementary standards to reduce measurement uncertainty further.
Auditors typically verify compliance by reviewing:
- Meter proving records (date, repeatability, prover ticket) for each metering run (required at least quarterly).
- Calibration certificates for all temperature, pressure, and density instrumentation.
- Software validation evidence for flow computers (GDP, meter factor linearization, correction factors).
- Straight-pipe lengths and flow conditioner geometry per as-built drawings.
Compliance Note: Many industry measurement contracts require adherence to the “API MPMS 6.6” as a minimum. If your agreement cites the 1991 (2012) edition, you must meet its specific requirements; however, you may also agree to adopt newer sections (e.g., 6.6.1 for turbine meters, 6.6.2 for PD meters) where they exist. Always check the contract language carefully.
Frequently Asked Questions
Q: Does API MPMS 6.6 1991 (2012) apply to gas pipeline metering?
A: No. This standard is specific to liquid hydrocarbon measurement in pipelines. For natural gas or other gaseous fluids, refer to API MPMS Chapter 14 (Natural Gas Fluids Measurement) or AGA reports.
A: No. This standard is specific to liquid hydrocarbon measurement in pipelines. For natural gas or other gaseous fluids, refer to API MPMS Chapter 14 (Natural Gas Fluids Measurement) or AGA reports.
Q: How often must meters be proved under API MPMS 6.6?
A: The standard requires that each meter be proved at least once every three months (quarterly) for custody transfer applications. More frequent proving is recommended if the meter exhibits drift, or if flow conditions change significantly. The proving frequency can be adjusted by mutual agreement between the operator and the shipper, subject to regulatory approval.
A: The standard requires that each meter be proved at least once every three months (quarterly) for custody transfer applications. More frequent proving is recommended if the meter exhibits drift, or if flow conditions change significantly. The proving frequency can be adjusted by mutual agreement between the operator and the shipper, subject to regulatory approval.
Q: Can I use a Coriolis meter as a meter prover?
A: While API MPMS 6.6 itself does not explicitly address Coriolis meters as provers, the practice of using a Coriolis master meter as a transfer prover is accepted per API MPMS 5.6 (Proving Systems). For full compliance, the master meter method must be agreed upon by all parties and the master meter must be proved against a primary standard (pipe prover) at regular intervals.
A: While API MPMS 6.6 itself does not explicitly address Coriolis meters as provers, the practice of using a Coriolis master meter as a transfer prover is accepted per API MPMS 5.6 (Proving Systems). For full compliance, the master meter method must be agreed upon by all parties and the master meter must be proved against a primary standard (pipe prover) at regular intervals.
Q: What is the difference between API MPMS 6.6 and API MPMS 6.7 (LPG Metering)?
A: API MPMS 6.6 is designed for liquid pipelines with typical operating pressures up to 1,500 psi (10,342 kPa) and fluids that remain liquid under all expected conditions. API MPMS 6.7 specifically covers LPG and other volatile products that require vapor pressure corrections and special handling to avoid vaporization during measurement. The principles overlap, but the detailed requirements for prover design and density correction differ significantly.
A: API MPMS 6.6 is designed for liquid pipelines with typical operating pressures up to 1,500 psi (10,342 kPa) and fluids that remain liquid under all expected conditions. API MPMS 6.7 specifically covers LPG and other volatile products that require vapor pressure corrections and special handling to avoid vaporization during measurement. The principles overlap, but the detailed requirements for prover design and density correction differ significantly.
Disclaimer: This article is for informational purposes and does not replace reading the full standard. Always refer to the official API publication for authoritative requirements. | Publication year in footer: 2026