PHMSA Final Rule: Safety of Gas Transmission Pipelines Published
The Federal Register published PHMSA’s Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments rule (a.k.a. Mega Rule RIN 2) today and can be located here. Its effective date is shorter than most PHMSA rulemakings, at nine months away on May 24, 2023. Some key topics and points covered in this rulemaking include:
Definitions
New definition of Distribution Center
Updated definition of a Transmission Line
Additional definitions for technology used in the rule such as Close Interval Survey and In-Line Inspection
Management of Change
Based on AMSE B31.8S Section 11, making it the same as the Integrity Management requirement
Implementation deadline of February 26, 2024
Does not apply to gas gathering lines
Corrosion
DCVG/ACVG Assessments of Newly Installed Pipe
For projects with 1,000 feet or more of contiguous backfill, a DCVG or ACVG must be performed, and any severe coating damage repaired as soon as possible, but within 6 months of placing line into service
Permits must be applied for within the first 6 months. If permits are required for repairs the above deadline may be extended by up to an additional 6 months
Records of assessment findings and remedial actions must be maintained for the life of the asset
External Corrosion Monitoring and Remediation
Defines specific timeframes for remediation of cathodic protection deficiencies for gas transmission lines
Must determine area of inadequate protection where any test station readings are below required levels
Investigate and remediate non-systemic issues
Perform CIS in both directions to identify systemic issues and remediate according to specified timeframes
Confirm restoration of adequate cathodic protection
Interference Currents
Where minimization of interference currents is required, the program must include:
Interference surveys
Survey results analysis to determine cause and severity (potential impacts)
Remedial action plan
Remediation timeframes
Internal Corrosion Monitoring and Mitigation
Transmission lines with corrosive constituents (CO2, hydrogen sulfide, sulfur, microbes, liquid water, etc.) must evaluate those constituents for their effect on the pipeline and develop/implement an internal corrosion monitoring and mitigation plan.
The plan must include:
Gas quality monitoring where corrosive contaminants enter the line
Mitigating technology for those contaminants
Annual evaluation of constituents and mitigation
Annual review/updates of internal corrosion program
Continuing Surveillance
Extreme weather event or natural disaster
Assess nature of event and inspect pipeline for potential impacts within 72 hours of safe access
Determine inspection method
Take prompt and appropriate remedial action
Analysis of Predicted Failure and Critical Strain Level
Provides details for PHMSA submittal request of other methods to determine remaining strength
Provides procedure and/or ECA details for evaluating dents and other mechanical damage
Provides details for submitting the ECA process for PHMSA approval
Details assessment interval requirements for pipe segments with anomalies that an ECA has been performed on to determine assessment intervals
Repair Criteria for Transmission Pipelines Outside of HCAs
Details repair timeframes for different types of anomalies
Repairs must be documented in accordance with Traceable, Verifiable, and Complete (TVC) requirements
If data required for analysis is not available (including MAOP determination), the data must be obtained through 192.607, Verification of Pipeline Material Properties and Attributes: Onshore steel transmission pipelines
Temporary pressure reduction requirements
PHMSA notification is required if remediation schedule cannot be met
Pressure reduction records (calculations, decisions, and actual pressures) must be kept for 5 years
On any repair location, in situ direct examination of crack defects is required in known locations of cracks or crack-like defects
Failure pressure is to be calculated in accordance with 192.712, Analysis of predicted failure pressure and critical strain level
Integrity Management
Risk Assessment
Integrate thirty-five (35) listed data elements starting May 24, 2023, and to be fully completed by February 26, 2024
Use validated data as much as possible
If using SME input, need consistency control measures, documentation of SMEs and qualifications of personnel approving SME inputs
Include a spatial relationship analysis of data
Include a threat interrelationship analysis
Must include potential consequences of an incident for each covered segment
Ensure method validity for incident, leak, and failure history analysis, which must align with industry benchmarks including root cause analysis or equivalent and the pipeline integrity sensitivity
Beginning February 26, 2024, risk assessments must evaluate:
How a potential failure would impact HCAs
Likelihood of failure form each threat and combination of threats
Account and compensate for data uncertainty
Impacts of preventive and mitigative measures on risk reduction, reduced anomaly remediation and assessment intervals
Includes additional threat language for plastic transmission pipelines
Direct Assessment
Included NACE SP0206 and enhanced language for Internal Corrosion Direct Assessment (ICDA)
Included NACE SP0204 and enhanced language for Stress Corrosion Cracking Direct Assessment (SCCDA)
Remediation
Repairs must be made and documented in accordance with TVC requirements
If data is not available for analysis, it must be obtained through material testing
Enhanced pressure reduction language and included reference to 192.712, Analysis of predicted failure pressure and critical strain level
Added documentation requirements to substantiate pressure reduction decisions
Added PHMSA notification requirements if Discovery cannot be made within 180 days
Updated most of the scheduled remediation criteria
Added requirement for in situ direct examination of crack defects using inverse wave field extrapolation (IWEX), phased array ultrasonic testing (PAUT), ultrasonic testing (UT), or equivalent technology
Preventive and Mitigative Measures (P&MMs)
Added a list of 15 items to include during evaluation
Included documentation requirement for risk analysis and preventive and mitigative measure implementation decisions
Enhanced language regarding leak surveys for low stress pipelines
Low Stress Reassessment
Enhanced indirect assessment specifics for low stress pipelines
Operators may request a one-year extension of some of these deadlines if the request is submitted to PHMSA at least ninety (90) days before the compliance deadline, the operator can provide a reasonable and justified basis, a plan for completing the requirements is provided, and a summary is included of safety status and mitigating measures to temporarily ensure safety.
If you have questions or would like to discuss a path forward on this or any other pipeline safety rulemakings, please contact Elemental Compliance for Nicole Tebow at Nicole.Tebow@ElementalCompliance.com or Lauren Tipton at Lauren.Tipton@ElementalCompliance.com.