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Measurement of Crude Oil During Submerged Turret Loading: A Guide to API MPMS 19.3H (1998, Reaffirmed 2002)
Understanding the scope, technical requirements, and compliance aspects of API MPMS 19.3H for custody transfer in offshore STL systems
Scope and Purpose of API MPMS 19.3H
API MPMS 19.3H is part of the American Petroleum Institute’s Manual of Petroleum Measurement Standards (MPMS). It provides comprehensive guidelines for the measurement and custody transfer of crude oil and petroleum products during loading operations through Submerged Turret Loading (STL) systems. These systems are commonly used in offshore fields to connect tankers to subsea pipelines via a turret buoy anchored to the seabed.
Originally published in 1998 and reaffirmed in 2002, the standard addresses the unique challenges of measuring multiphase or wet crude oils that may contain gas, water, and sediment. The document focuses on ensuring accurate, traceable, and repeatable mass and volume measurements, which are critical for fiscal metering and maintaining contractual integrity between sellers and buyers.
The standard applies to fixed, floating, and mobile STL installations and covers both conventional and dynamic loading operations. It is intended for use by operators, measurement specialists, auditors, and regulatory bodies involved in offshore crude oil transfer.
Important note: API MPMS 19.3H (1998, reaffirmed 2002) should be used in conjunction with other relevant MPMS chapters, especially Chapter 5 (Metering) and Chapter 12 (Calculation of Petroleum Quantities). The standard does not supersede statutory requirements of the jurisdiction where the STL system operates.
Technical Requirements for STL Measurement Systems
Meter Types and Installation
The standard specifies the use of positive displacement (PD) meters or turbine meters as primary devices for STL loading measurement. The meter selection must account for the high flow rates (often above 10,000 barrels per hour) and the presence of entrained gases that can cause measurement errors. API MPMS 19.3H requires that:
- Meters shall be installed upstream of any fluid separation equipment, where the fluid is still in a single-phase or stable two-phase condition.
- Flow straighteners or conditioning devices must be installed in accordance with manufacturer recommendations and API MPMS Chapter 5.3.
- Pressure and temperature transmitters shall be located at the meter body or no more than 5 pipe diameters downstream.
- Additional check meters (e.g., Coriolis mass flow meters) are recommended for verification purposes.
Sampling and Quality Determination
Accurate measurement of crude oil quality parameters such as API gravity, water content (BS&W), and sediment is essential for net standard volume computation. The standard mandates:
- Automatic sampling: A proportional-to-flow automatic sampler shall be installed on the main loading line. The sample probe must be located in a region of uniform flow and high turbulence.
- Sample handling: Samples shall be collected and stored according to API MPMS Chapter 8 (Sampling) and maintained at pressure and temperature conditions representative of the flowing stream.
- Laboratory analysis: Testing for API gravity (ASTM D287 / D1298), water content (ASTM D4006 / D4377), and sediment (ASTM D473) must follow standardized methods with specified precision.
| Parameter | Instrument / Method | Maximum Permissible Error (MPE) |
|---|---|---|
| Flow rate (volume) | PD meter / Turbine meter | ±0.25% (prover calibration) |
| Temperature | RTD / Thermocouple | ±0.2 °C of reading |
| Pressure | Pressure transmitter | ±0.1% of full scale |
| API gravity (laboratory) | Hydrometer / Digital density meter | ±0.1 °API |
| Water content (BS&W) | Automated sampler + Karl Fischer titration | ±0.05% for low water cuts |
Calculation of Net Standard Volume
API MPMS 19.3H adopts the standard calculation methodology from API MPMS Chapter 12 for converting gross metered volume to net standard volume at base conditions (60 °F, 14.696 psia). The standard outlines a step-by-step procedure that includes:
- Application of meter correction factor from prover runs
- Temperature and pressure corrections using API MPMS Chapter 11.1 (tables 5A/6A)
- Deduction of sediment and water (S&W) based on laboratory analysis or online BS&W monitors
- Conversion of mass to volume (if Coriolis meters are used) via calculated density at base conditions
Best practice: To reduce uncertainties, the standard recommends that the entire measurement system (meter, prover, sampling, and analyzers) be subjected to a comprehensive uncertainty analysis in accordance with ISO/IEC Guide 98-3 (GUM). A target combined uncertainty of no more than ±0.35% for net standard volume is commonly adopted by industry.
Implementation Highlights
Proving and Calibration
Regular proving of liquid meters using a bidirectional pipe prover or compact prover is mandatory. The standard requires that provers themselves be certified to an uncertainty of ±0.02% and be traceable to national standards. Proving intervals should be every 6 months or after every 1,000,000 barrels (whichever comes first), unless trend analysis or regulatory mandates dictate more frequent checks.
Gas Entrainment Detection
Because crude oil in STL systems can contain dissolved or free gas, the standard stresses the need for online gas void fraction (GVF) monitoring. If GVF exceeds 2%, the measurement accuracy degrades significantly. Operators should install gas eliminators or multiphase metering systems to correct for the effect.
Critical: Failure to correctly account for free gas can lead to measurement errors exceeding 5% and subsequent revenue loss or contractual disputes. API MPMS 19.3H advises installing a gas detection and measurement system upstream of the fiscal meter.
Environmental Considerations
The standard includes recommendations for vapor recovery and emission monitoring during STL operations to meet local environmental regulations. It also specifies that all measurement equipment be suitable for hazardous area classification (Zone 1 / Zone 2) and be resistant to the harsh marine environment.
Compliance and Auditing Notes
Compliance with API MPMS 19.3H is often a contractual requirement for producers and traders involved in offshore crude sales. Key compliance aspects include:
- Documentation: Maintain complete records of meter calibration, prover certificates, sample analyses, and all corrective actions. Records must be retained for at least 2 years or as required by the regulatory authority.
- Third-Party Verification: The standard recommends that an independent metering inspector (e.g., from a recognized surveying company) witness loading operations, perform gauge readings, and prepare a bill of lading (BOL) based on the measurement data.
- Audit Trail: All measurement data, including raw pulse counts, temperature, pressure, and calculated volumes, should be logged by a certifying electronic flow computer or SCADA system with non-repudiable audit trails.
- Regulatory Alignment: While voluntary, many offshore jurisdictions (e.g., Norway, UK, Gulf of Mexico) require or adopt API MPMS 19.3H as the basis for fiscal metering. Operators must also check local requirements for measurement accuracy, prover validation, and reporting frequency.
Tip: When facing disputes over custody transfer volumes, refer to the disputed quantity resolution procedure described in API MPMS 19.3H Appendix C. This includes re-calibration of meters, re-sampling, and independent laboratory analysis to reconcile differences.
Periodic Reviews and Updates
The 1998 edition was reaffirmed in 2002, meaning the technical content was reviewed and deemed still current at that time. Since then, some sections may have been updated or superseded by later editions, such as API MPMS 19.3.1 for general loading. Operators should always verify that they are using the latest version applicable to their STL system and consult with the API for any addenda or corrections.
Frequently Asked Questions
Q: Does API MPMS 19.3H apply to all offshore loading systems, or only STL?
A: It is specifically designed for Submerged Turret Loading systems. However, many of its principles—such as the need for gas discrimination, accurate sampling, and robust prover calibration—are also applicable to other offshore loading configurations like SPM (Single Point Mooring) or CALM buoys. For generic offshore loading measurement, refer to API MPMS Chapter 19.3 (main body).
A: It is specifically designed for Submerged Turret Loading systems. However, many of its principles—such as the need for gas discrimination, accurate sampling, and robust prover calibration—are also applicable to other offshore loading configurations like SPM (Single Point Mooring) or CALM buoys. For generic offshore loading measurement, refer to API MPMS Chapter 19.3 (main body).
Q: What is the recommended meter type for high-GOR (gas-oil ratio) crude in STL service?
A: For crude with high GOR, the standard suggests using a Coriolis mass flow meter as the primary fiscal meter, as it is less affected by gas entrainment compared to PD or turbine meters. Alternatively, a two-phase (wet gas) metering system can be configured with a PD meter and an online gas fraction analyzer to correct the measured volume.
A: For crude with high GOR, the standard suggests using a Coriolis mass flow meter as the primary fiscal meter, as it is less affected by gas entrainment compared to PD or turbine meters. Alternatively, a two-phase (wet gas) metering system can be configured with a PD meter and an online gas fraction analyzer to correct the measured volume.
Q: How often should the automatic sampler be validated?
A: API MPMS 19.3H recommends testing the sampler’s proportional-to-flow capability at least once per year, using a dynamic flow loop or by collecting a known volume of liquid and comparing the sample volume to the total metered volume. Additionally, after any maintenance or significant flow pattern changes, the sampler should be requalified.
A: API MPMS 19.3H recommends testing the sampler’s proportional-to-flow capability at least once per year, using a dynamic flow loop or by collecting a known volume of liquid and comparing the sample volume to the total metered volume. Additionally, after any maintenance or significant flow pattern changes, the sampler should be requalified.
Q: Does the standard require a density measurement for mass-to-volume conversion if using a PD meter?
A: Yes. Even when using a volumetric meter, the standard mandates either an online densitometer or laboratory density measurements from a proven sample to calculate standard density. This density is then used to convert the gross measured volume to mass and then to net standard volume, following the API MPMS Chapter 12 calculation procedures.
A: Yes. Even when using a volumetric meter, the standard mandates either an online densitometer or laboratory density measurements from a proven sample to calculate standard density. This density is then used to convert the gross measured volume to mass and then to net standard volume, following the API MPMS Chapter 12 calculation procedures.
Article compiled from API MPMS 19.3H (1998, reaffirmed 2002) – Manual of Petroleum Measurement Standards. For authoritative use, always refer to the latest published edition.
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