Accurate Determination of the Maximum Allowable Operating Pressure (MAOP) of Oil and Gas Pipelines

Maximum allowable operating pressure (MAOP) is the maximum pressure a pipeline can safely operate. The pipe wall thickness (t), Specified Minimum Yield Stress (SMYS), and pipe outer diameter (OD) are used to calculate the MAOP of a pipe.

MAOP = (Factors of safety × SMYS × t) / OD

Pipeline operators are keenly aware of the MAOP of their lines and understand that exceeding the maximum pressure could result in a catastrophic failure with the risk of infrastructure damage and loss of life. Therefore, a margin of safety is used in the calculation of MAOP. Accurate determination of MAOP is a serious problem for undocumented pipelines.

The factors of safety are chosen from the US Code of Federal Regulations (49 CFR, Parts 192 and 195), the wall thickness can be measured non-destructively using an ultrasound thickness gage instrument, the OD can be measured using a pipe OD caliper, and the SMYS is taken from the pipe grade certification — a serious situation when documentation is missing or not verified, as is the case for thousands of miles of transmission oil and gas pipelines currently in-service in the USA and abroad.

The specified minimum yield strength (SMYS) is the yield strength specified for the steel when purchased and must be documented in the grade certification. When a pipeline is constructed the operator specifies the SMYS required for the project. The actual pipe received often exceeds the minimum because pipe manufacturers make multi-grade pipe joints with a single certificate specifying multiple grades. However, the operator cannot run their pipeline at pressures higher than what the pipeline was designed for.

SMYS is integral in the calculation of the maximum allowable operating pressure of a pipe. A factor of safety of 0.72 or lower of the SMYS is used in the MAOP calculation. When documentation (grade certificate or material test report “MTR”) is missing, the operator must measure the mechanical properties of the pipeline or assume a low/conservative value of 24 ksi for the yield strength or the SMYS for the unknown pipeline.

For improved efficiency, the mechanical properties can be measured using destructive tensile specimens (which is cost prohibitive and requires disruption of transmission service due to shut-down to cut pipe portions, weld replacement and machine and test strap tensile specimens) or to conduct in-situ nondestructive Automated Ball Indentation (ABI®) tests.

The ABI® test follows ASTM Standard E636-14 and is verified on pipelines in a six-laboratory interlaboratory study that included PRCI (Report Number L52280, April 2007). The ABI® test method with its precision values is described on pages 36–60 of this report.

The ABI® test provides direct-properties-measurements (not estimates) on in-service (live) oil and gas pipelines and satisfies the NDT requirements of 49 CFR §192.607.

Grade is determined by the chemical composition and mechanical properties of a specific pipe steel. The chemical composition of steel used in the manufacture of pipe must conform with standards defined in the American Petroleum Institute (API) Specification 5L (API 5L). The chemical analysis of pipe steel must include measurement of the following elements: carbon, manganese, phosphorus, sulfur, chromium, columbium, copper, molybdenum, nickel, silicon, titanium, and vanadium.

Since the in-situ ABI® test determines the complete tensile properties including yield strength and ultimate tensile strength, these are used for pipe grade determination. When an operator needs both the chemical and mechanical properties of the pipeline, portable XRF measurements of the pipe chemistry are used in conjunction with the ABI® test for reliable pipe grade determination.