Natural Gas Flow Measurement: AGA3, ISO 5167 and Custody Transfer

AGA Report No. 3, incorporated into API MPMS Chapter 14.3, covers orifice metering of natural gas and related hydrocarbon fluids through separate parts for equations and uncertainty, specification and installation, natural-gas applications, and supporting implementation information. The calculation is iterative because discharge coefficient depends on Reynolds number and Reynolds number depends on the resulting flow. Implement the convergence criterion, property method, base conditions, unit conventions, and rounding rules required by the selected edition and flow-computer specification; do not combine clauses from AGA3 and ISO 5167 without a documented project basis.

Allocation and custody-transfer requirements are set by contracts, regulations, measurement manuals, and risk. They may differ in uncertainty target, redundancy, audit trail, sealing, verification, and calibration, but there is no universal relaxed allocation percentage or audit interval. Document the governing method and uncertainty budget for the actual station.

The compressibility factor Z quantifies real-gas departure from ideal behavior and can materially affect density and flow. AGA8 offers detailed and gross characterization methods with different input requirements and application ranges. Choose the method required by the governing measurement agreement and verify that the gas composition, pressure, and temperature lie within its validity range. Include composition sampling, analyzer performance, reference-gas uncertainty, and temporal representativeness in the uncertainty analysis.

Gas chromatography frequency, calibration interval, failure substitution, probe location, sample conditioning, transport lag, and dew-point margin must follow the station measurement manual and applicable standards. The sampling system must deliver a representative single-phase sample to the analyzer without selective condensation or contamination. Avoid universal weekly, 24-hour, center-third, or fixed-temperature-margin rules unless they are the documented project requirement.

AGA3/API MPMS 14.3 and ISO 5167-2 have related technical foundations but are not interchangeable line by line. Differences can include scope, terminology, meter-tube and installation requirements, property and base-condition conventions, uncertainty treatment, and implementation details. The contract should name one governing framework and edition, with any additional requirements stated explicitly. A phrase such as “AGA3 or ISO 5167” is ambiguous and should be resolved before sizing or flow-computer configuration.

Custody transfer is governed by the sales agreement, regulation, and operator measurement manual. Define the uncertainty target and coverage factor, primary and secondary instrumentation, flow-computer algorithm and audit trail, security and sealing, property measurement, verification and calibration intervals, data substitution, alarms, reporting, dispute handling, and document retention. Dual transmitters, periodic wet calibration, a particular straight-run column, or an online chromatograph may be required for some stations but are not universal requirements for every jurisdiction or contract.

Natural-gas density depends on absolute pressure, temperature, and composition. Select instrument ranges and uncertainties from the station uncertainty budget rather than fixed percentages. Design taps, transmitter elevation, impulse-line slope, tubing, valves, tracing, insulation, and drainage for the actual risk of liquid, compressor oil, hydrates, ambient exposure, response time, pressure class, and maintenance. Thermowell location and insertion require both metering-disturbance and mechanical wake-frequency checks. Redundancy and alarm thresholds should follow a documented diagnostic strategy; a discrepancy alone does not identify blockage or leakage.

Provide gas composition and expected variation; water and hydrocarbon dew points; standard-volume reference conditions; minimum, normal, maximum and upset flow; operating and design pressure and temperature; measured pipe ID, material, schedule and roughness basis; available straight run with every disturbance; allowable permanent loss; sour-service and material requirements; measurement purpose; governing standard and edition; property method; and required uncertainty. Ask the supplier to return β, bore, C, ReD, ΔP, permanent loss, expansibility and property basis, standard-limit and straight-run checks, uncertainty budget, drawings, material records, and a clause-specific compliance statement.

Natural-gas DP measurement requires one coherent, named calculation and installation framework plus representative fluid properties, suitable instruments, maintained impulse systems, and an auditable data chain. Confirm the standard and edition, base conditions, composition method, pressure and temperature basis, meter-run geometry, operating range, uncertainty, and maintenance controls. Send the gas composition, operating conditions, and piping arrangement through our Contact page for a preliminary standards and sizing review.