On October 1, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA) finalized a rule for gas transmission lines which has been in development for over eight years. This rule, referred to by many as the “Gas Mega Rule”, is considered to be the most significant change to the existing gas pipeline regulations since 1970 and will have a significant impact on the operation of gas transmission assets in the United States. Extensive modifications have been applied to the existing pipeline regulations for 49 CFR Parts 191 and 192 and four modifications at minimum will have a significant impact for US gas transmission pipeline operators as detailed below.
Moderate Consequence Area
To address the mandate from Congress to expand integrity management requirements beyond currently defined High Consequence Areas (HCAs), PHMSA has introduced a new definition – Moderate Consequence Area (MCA). An MCA is generally defined as the area within a Potential Impact Circle (similar to the Potential Impact Circle currently applied for establishing HCAs) that either contains 5 or more buildings or alternatively contains a major roadway (e.g. Interstate highway, freeway, expressway and other 4-lane roadways) and does not already meet the definition of an HCA.
Based on the definition of the MCA, it is possible that for some operators, the pipeline mileage in MCAs could be greater than the mileage currently within HCAs. Several other requirements within the rule (including for Pipeline Assessments, and MAOP verification) will apply to MCAs, substantially increasing the potential impact to gas transmission operators.
Pipeline Assessments in Non-HCAs
To address the mandate from Congress to expand integrity assessment and management requirements beyond HCAs, PHMSA has expanded requirements for performing pipeline assessments outside of HCAs in section §192.710. Specifically, these requirements will apply to pipe segments exhibiting a maximum allowable operating pressure of greater than or equal to 30% of the specified minimum yield strength (SMYS) that are present in Class 3 or 4 locations or in MCAs that also can accommodate an inline inspection (ILI) tool, and that are not already part of existing HCAs. The rule requires gas transmission operators to perform initial assessments on all such pipeline segments in accordance with §192.710, and based on a risk prioritization schedule, no later than July 3, 2034.
For pipelines segments that meet the applicability of §192.710 (e.g. due to change in class location or an area becomes an MCA), the rule requires that an initial assessment is performed as soon as practicable and within a time period not to exceed 10 years after the pipeline segment meets the applicability requirements. Reassessments are required at minimum intervals of 10 years or less based on the nature and type of anomaly discovered on the pipeline segment. Assessment methods selected must be capable of identifying anomalies associated with each of the threats to which a pipeline segment is susceptible. For example, the rule allows Direct Assessment 11 to be used to assess external corrosion, internal corrosion, and stress corrosion cracking (ECDA, ICDA and SCCDA). Pressure Tests and ILI are also permitted as assessment methods, as applicable.
Maximum Allowable Operating Pressure (MAOP) Reconfirmation
To address mandates from Congress as well as NTSB recommendations, the rule requires that MAOP is reconfirmed for pipelines where pressure test records are not traceable, verifiable or complete (TVC) and are in an HCA, or Class 3 or 4 location, as well as where the pipeline’s MAOP was established by the “grandfather clause” (i.e. §192.619(c)), and the MAOP is greater than or equal to 30% of SMYS, and is in an HCA, a Class 3 or 4 location, or an MCA that can accommodate ILI. The rule requires gas transmission operators to develop procedures for completing all actions in §192.624 by July 1, 2021. Operators must ensure that the MAOP is reconfirmed for 50% of applicable pipelines by July 3, 2028, and for 100% of applicable pipelines by July 2, 2035. Five of the six methods allowed by the rule for MAOP reconfirmation include; Pressure Test, Pressure Reduction, Engineering Critical Assessment (ECA), Pipe Replacement and Alternative Technology.
It is worth noting that the rule has outlined detailed requirements for the ECA method. Based on Dynamic Risk’s experience of performing ECA for operators, this effort involves extensive data availability, robust tools for data integration, as well as advanced knowledge in analysis using fracture mechanics. Another method for MAOP Reconfirmation is only applicable for pipelines with a Potential Impact Radius of less than 150ft. For these pipeline segments, the rule would allow the MAOP to be established at a pressure at least 1.1 times the highest pressure in the previous 18 months but would also require conducting increased patrols and leakage surveys. Even though the rule allows for a time period of approximately fifteen years to complete MAOP verification, this requirement could represent a challenge for those gas transmission operators operating pipeline systems containing extended mileage of untested pipe or pipeline segments lacking TVC pressure test records.
To address The National Transportation Safety Board (NTSB) recommendations, the records for selected pipe material properties must be confirmed as TVC wherever required by 49 CFR 192 (e.g. for certain methods used for MAOP verification (§192.624), and in analyzing predicted failure pressure (§192.712)). These requirements are applicable to pipe, and for selected components such as fittings, valves, flanges, etc.
The Mega Rule requires that operators develop procedures for performing destructive and non-destructive tests in order to verify material properties. For all above ground pipe locations, the rule requires operators to conduct tests to address a lack of pipe material property records. For below ground pipe, operators must opportunistically verify the physical properties during exposure of underground facilities, such as during pipe replacements and integrity excavations, in order to determine that material properties have been verified in accordance with §192.607.
In the final rule published in the Federal Register, PHMSA clarifies that material properties verification requirements are not deemed to be retroactive, mandating the creation and retention of records as operators execute the methodology in § 192.607 on a prospective basis. Operators who have not verified material property records in accordance with this methodology prior to the effective date of this rule will not be subject to enforcement action based on § 192.607. Pipeline operators missing or inadequate records post the effective date, must however follow the verification methodology stipulated within § 192.607, e.g. for certain methods used for MAOP reconfirmation (§192.624), for analyzing predicted failure pressure (§192.712), and whenever an MAOP is established, including for new construction (§192.619).
A significant data review and integration effort may be required by operators to first determine the extent of the record gaps, and as a basis for developing and implementing a potentially extensive ongoing material verification program.