Impacts of PHMSA’s Gas Mega Rule Part 2 for Gas Transmission Operators
What is RIN-2?
PHMSA’s Gas Mega Rule is a set of new pipeline safety regulations published in three parts. Part 1 was effective on July 1, 2020 and was focused on onshore gas transmission pipelines and included MAOP reconfirmation and material verification requirements. Part 3 was effective on May 16, 2022 and related to safety of Gas Gathering Pipelines. Part 2 of the PHMSA Gas Mega Rule, also known as “RIN‑2”, is effective on May 24, 2023 and comprises additional changes to pipeline safety regulations for onshore gas transmission.
The RIN-2 rule has increased regulatory requirements in 49 CFR 192 for operations and maintenance and integrity management, and pipeline operators will need to operationalize the requirements into systems, processes and procedures to ensure compliance.
What are the major changes in RIN-2?
There are extensive changes in RIN-2 that revise or add sections in 49 CFR 192, broadly covering the following:
- Corrosion control for both external and internal corrosion;
- Inspections following extreme weather events;
- Repair criteria and response;
- Management of change;
- Direct assessment for internal corrosion and stress corrosion cracking;
- Threat assessment and data integration;
- Risk assessment; and,
- Additional prevention and mitigation measures.
While all the changes to requirements need to be considered, four of these are highlighted below that will have major impact on pipeline operators: Management of Change; Repair and Response Criteria; Data Integration; and Risk Assessment.
Management of Change (MOC)
MOC is not a new concept to our industry, but with the new rule there is a now the added requirement to develop and follow an MOC process for segments outside High Consequence Areas (HCAs) for changes to pipeline or processes, whether permanent or temporary, including: Technical, Design; Physical; Environmental; Procedural; Operational; Maintenance; and Organizational. This MOC process must be implemented in non-HCAs by February 26, 2024, but may be extended by 1 year through notification to PHMSA with sufficient technical justification. Specific MOC requirements for both HCAs and Non-HCAs are now prescribed with the regulations (previously the regulations referenced ASME B31.8S for MOC requirements within HCAs).
Repair and Response Criteria
There are new requirements that specify repair criteria and anomaly response for pipe outside of HCAs. Immediate response criteria are the same for HCAs and non-HCAs, while the scheduled response criteria are the same but with different response times. In combination with the changes already promulgated in Part 1, the response criteria for cracks are also defined and require consideration of ILI tolerance and conservative toughness values.
Part 2 also requires pipeline operators to develop a procedure to perform Engineering Critical Assessment (ECA) for evaluation of dents and mechanical damage to establish critical strain values.
The changes in RIN-2 substantially increase the requirements for data gathering and integration. The rule expands requirements beyond ASME B31.8S and prescribes more than 50 data elements that must be integrated by February 26, 2024, but may be extended by 1 year with notification to PHMSA with sufficient technical justification. Operators must use validated data to the extent practicable. Control measures must be in place for any subject matter expert (SME) input to assure consistency (e.g., SME training or independent expert reviews), along with documentation of names and qualifications of individuals that approvement SME input. Additionally, there are new requirements for operators to identify and analyze spatial relationship of anomalous information.
The requirements for risk assessment have been significantly expanded. In addition to the analyzing the likelihood of failure due to individual threats, the rule also emphasizes the analysis of potential consequences of an incident for each covered segment. Beginning on February 26, 2024, operators must ensure the validity of the risk assessment methods, that risk characterization is consistent with operator’s and industry experience, considers the incident, leak, and failure history of the segments and other historical information, and include a sensitivity analysis of the factors used to characterize the likelihood and the consequences of an incident. In addition, risk assessments must evaluate potential risk reduction activities, including preventative and mitigative measures, and anomaly remediation and reduced assessment intervals.
How is Dynamic Risk poised to support operators with this rule?
Dynamic Risk has followed the rulemaking process even before the first part of the Gas Mega Rule was published in 2020 and have been supporting pipeline operators in managing the change and implementing previous regulation updates, in particular related to technical and practical issues associated with MAOP Reconfirmation, Material Verification, and Engineering Critical Assessment. Specific to RIN-2, Dynamic Risk has extensive experience and expertise in the following areas:
- Performing independent compliance assessments, to confirm that operating processes and procedures have been developed or updated to meet the new regulations.
- In addition to compliance, Dynamic Risk can support the operationalization of the rule requirements, to enhance the effectiveness of operating processes and procedures.
- Supporting data integration, including spatially aligned data, through comprehensive review of current state and development of road maps for data integration processes and systems.
- Performing consequence analysis, as part of risk analysis, to evaluate impacts of potential failures, and identify additional mitigation measures to reduce overall risk.
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About the Author:
Curtis Parker, Technical Director
Curtis is a recognized leader in energy asset reliability management with over 25 years of experience in design, construction and operations of natural gas and liquid pipeline systems, natural gas utilities, and power generation plants. His experience includes directing a pipeline integrity organization responsible for over 16,000 miles of pipelines across 30 US states, Canada, and Mexico. He is a registered Professional Engineer with proven hands-on expertise and management of asset integrity and reliability including risk assessment, inspection, repair, and maintenance, with extensive experience with managing field inspection and repair projects. He has led incident investigations for a major North American pipeline company and interfaced directly with pipeline regulator staff. He has an in-depth working knowledge of safety management systems, as well as regulations and industry standards including DOT 49CFR 192 and DOT 49CFR 195, ASME B31.8S, NACE SP0502, and API 1173.
Curtis has a Bachelor of Science in Mechanical Engineering from the University of Saskatchewan, and is a certified AMPP Cathodic Protection Technician (Level CP2).