Applies to pipelines and piping systems within the ASME B31 transportation pipeline codes: B31.4 (liquid hydrocarbons), B31.8 (gas transmission and distribution), B31.11 (slurry transportation), and B31.12 (hydrogen pipelines).

Covers metal loss in ductile pipe body materials operating within specified temperature ranges and allowable design hoop stresses.

Applicable to pipelines located belowground, aboveground, or offshore.

Excludes crack-like defects, mechanical damage not removed by grinding, metal loss causing radial distortion exceeding 6% of pipe diameter, grooving corrosion, selective corrosion, metal loss in fittings (except bends/elbows), and metal loss in brittle materials or pipes operating outside recognized temperature ranges or creep conditions.

Level 0: Table-Based Assessment Utilizes extensive tables of allowable corrosion length and depth for quick field screening. Suitable for rapid decisions without detailed calculations. The tables cover pipe sizes from NPS 2 to NPS 60 and metric equivalents, providing maximum allowable longitudinal corrosion lengths for various corrosion depths and wall thicknesses. Metal loss less than or equal to 10% of nominal wall thickness is not length-limited, while metal loss exceeding 80% should not be evaluated using these tables.

Level 1: Simplified Calculations Employs simple formulas based on maximum corrosion depth and length, suitable for field use by trained personnel. It calculates failure stress using flow stress definitions (typically 1.1 × SMYS or SMYS + 10 ksi for carbon steels) and a magnification factor based on corrosion length. This level balances simplicity with reasonable conservatism.

Level 2: Effective Area Method Involves detailed measurement of the corrosion profile along the defect length and iterative calculations to estimate failure pressure more accurately. It requires multiple measurements of metal loss or remaining wall thickness and considers multiple plausible corrosion profiles for statistical confidence. Level 2 evaluations are typically supported by specialized software.

Level 3: Advanced User-Defined Analysis Allows detailed finite element analysis (FEA) or other user-defined methods considering complex loadings, boundary conditions, material properties, and fracture mechanics. This level is intended for specialists and critical assessments requiring the highest accuracy.

Levels 0 through 2 use specified minimum material properties such as Specified Minimum Yield Strength (SMYS) and Specified Minimum Tensile Strength (SMTS) at ambient or operating temperatures.

Level 3 may incorporate actual material test data from mill test reports or laboratory testing if available and reliable.

The standard defines "flow stress" variably, commonly as 1.1 × SMYS or SMYS + 10 ksi for carbon and low-alloy steels.

Material ductility and toughness considerations include effects of operating temperature, sour environments, and other factors influencing fracture initiation.

Electric resistance welded (ERW) seams and certain weld types are considered to have adequate ductile fracture initiation properties if workmanship flaws are not present in proximity to corrosion.

A minimum safety factor of 1.25 is recommended, aligning with the ratio of minimum hydrostatic test pressure to Maximum Allowable Operating Pressure (MAOP) or Maximum Operating Pressure (MOP).

Safety factors may be adjusted based on risk, operational controls, or pipeline location, with higher factors in areas of greater public or environmental risk. Regulations can require more margin than 1.25: on onshore gas transmission lines, 49 CFR 192.933 (covered segments in HCAs) and 192.714 (other onshore transmission pipe) set repair deadlines from the predicted failure pressure as a multiple of MAOP, by class location.

A corrosion defect is acceptable if the calculated failure stress exceeds the operating hoop stress multiplied by the safety factor.

The standard cautions users to consider measurement accuracy, corrosion growth rates, surge control reliability, and external risk factors when selecting safety factors.

Metal loss areas within three times the pipe wall thickness (3t) longitudinally or circumferentially are considered interacting and must be evaluated as a single combined flaw.

Helically oriented corrosion patterns less than 45° to the pipe axis are evaluated for the full longitudinal length; those at 45° or greater are assessed based on the most severe longitudinal section.

Circumferential corrosion adjacent to welds is evaluated similarly to helical corrosion at angles over 45°.

These criteria ensure conservative assessment of clustered or oriented corrosion defects.

Measurement Accuracy: Corrosion depth and length measurements must be accurate and representative; errors can lead to unsafe acceptance or unnecessary repairs.

High Corrosion Depths: Metal loss exceeding 80% of nominal wall thickness should not be evaluated with Level 0 tables. On onshore gas transmission lines, 49 CFR 192.933 (covered segments in HCAs) and 192.714 (other onshore transmission pipe) treat metal loss greater than 80% of nominal wall, regardless of dimensions, as an immediate repair condition, so a more detailed calculation does not clear it.

Complex Defect Geometry: Irregular or multiple interacting pits require Level 2 or Level 3 evaluations for reliable assessment.

Material Property Uncertainty: Using actual material test data when available improves accuracy; otherwise, conservative minimum properties should be used.

Operating Conditions: Temperature extremes, sour environments, and creep conditions may invalidate standard assumptions and require specialized assessment.

Safety Factor Selection: Inappropriate safety factors can either expose the pipeline to risk or lead to excessive conservatism and cost.

Quickly screen corrosion defects using tables (Level 0) or simple calculations (Level 1).

Perform detailed profile-based assessments with the Effective Area Method (Level 2).

Employ advanced finite element or fracture mechanics analyses for critical defects (Level 3).

Incorporate material properties, operating conditions, and safety factors into acceptance decisions.

Evaluate interacting and oriented corrosion defects conservatively.

ASME B31G-2023: Manual for Determining the Remaining Strength of Corroded Pipelines (American Society of Mechanical Engineers)

API 579-1/ASME FFS-1: Fitness-for-Service Standard

NACE SP0169: Control of External Corrosion on Underground or Submerged Metallic Piping Systems

DNV RP-F101: Recommended Practice for Corroded Pipelines

49 CFR Part 192 Subpart O: Gas Transmission Pipeline Integrity Management