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Using CIM to Comply with the Gas Mega Rule Part 2

Although there was considerable anticipation surrounding Gas Mega Rule Part 1, significant and wide-ranging rulemakings were introduced in Part 2 of the three-part Gas Mega Rule, which went into effect last year. Part 2 was the last of the three Rules to be published, as seen below.  

  • Part 1: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments 
    • Final Rule: Oct. 1, 2019, effective July 1, 2020. 
  • Part 2: Safety of Gas Transmission Pipelines Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments
    • Final Rule: August 24, 2022, effective May 24, 2023. Some enforcement extended to February 2024.  
  • Part 3: Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments.
    • Final Rule: Nov 15, 2021, effective May 16, 2022. 

The Part 2 final rule covers a multitude of changes to pipeline integrity management regulations, including data integration and risk, corrosion control, managing the threat of weather events, and adjusted repair criteria for pipelines in high consequence areas (HCAs) and non-HCAs. We’ll discuss these specific changes and their impact as well as how to use Cognitive Integrity Management (CIM) to comply. 

Data Integration and Risk Assessment: §192.917 (Liquid: §195.452(g)) 

When a new Rule is published, the Pipeline and Hazardous Materials Safety Administration (PHMSA) writes a Section-by-Section analysis that describes each change and the impetus behind said change. In discussing §192.917, PHSMA states the following (on RIN 2137-AF39, page 37): 

“Even though the IM regulations have been in effect since 2004, PHMSA still finds certain operators have poorly developed IM programs. The clarifications and additional specificity adopted in this final rule, with respect to the processes an operator must use in implementing the threat identification, risk assessment, and preventive and mitigative measure program elements, reflect PHMSA’s expectation regarding the degree of progress operators should be making, or should have made, during the first 10 years of the implementation of the IM regulations.” 

PHMSA has therefore determined that operators need a more robust program for gathering and integrating data as well as analyzing “spatial relationships among data elements” i.e. understanding interacting threats. Per §192.917(b), 47 data elements concerning pipeline information shall be gathered by February 24, 2024 - everything from integrity assessment data to aerial photograph and geology information.

This requirement is very similar to the updates to §195.452(g) published in the "Liquid Mega Rule" on October 1, 2019, in which 21 data elements were delineated as required. In discussing these data gathering and integration requirements, it’s stated in §195.452: “Storing the information in a geographic information system (GIS), alone, is not sufficient. An operator must analyze for interrelationships among the data.”  

As described in 192.917(c) regarding Risk Assessment, it’s now required that the risk assessment: 

  • Be validated and include sensitivity analysis. 
  • Be used to identify additional P&M measures. 
  • Able to quantify the probability of a failure at discrete locations on the pipeline due to individual AND interacting threats  
  • Correctly account for uncertainties. 
  • Quantify the risk reduction taken from P&M measures. 

Using CIM to Comply
: Currently data from in-line inspections (ILI) and GIS are already ingested and integrated with our Core CIM module, however work is underway to integrate data from our external and internal corrosion modules (discussed below) as well as our geohazards module which will be integrating and aligning publicly available information e.g. soil data, seismic activity, etc. with pipeline data. Additionally, OneBridge is currently incorporating C-FER’s probabilistic risk model into CIM to help operators meet these new regulatory requirements.  

Risk Management is also offered as a OneBridge Solutions professional service. 

External Corrosion Control §§§192.465, 192.473, 192.478 

Updates were made to tighten regulations concerning the control of both external and internal corrosion as summarized below. 

External Corrosion Control: Monitoring and Remediation, §192.465:  

Operators must now:  

  • Determine the extent and cause of inadequate cathodic protection (CP) where annual CP readings are below the required level.  
  • If low CP is found to have a systemic cause, Close Interval Survey (CIS), shall be conducted in both directions of the test station. 
  • Create a remediation plan to promptly correct any deficiencies per prescribed timelines in the rule.  

External Corrosion Control: Interference Currents,

Operators must now: 

  • Conduct interference surveys if stray current is indicated on a monitoring survey or if stray current sources are introduced. 
  • Analyze the cause and potential effect of the stray current. 
  • Develop a remedial action plan and execute plan within a certain timeframe. 


Using CIM to Comply: You might have guessed it – we’re working on an external corrosion control module that will gather, integrate and analyze the relevant data sets e.g. CIS, CP annual surveys, DCVG etc. and align it with pipe information like coating type (for example) and ILI data. What started as a solution to digitize atmospheric inspection reports for an operator is morphing into its own comprehensive corrosion control module.  Need interference surveys done? Check out our professional services team! 

Internal Corrosion Control, §192.478 

Operators must now: 

  • Have an internal corrosion control program (unless the gas contains no corrosive constituents) which includes:  
    • Monitoring: Evaluating the partial pressure of each corrosive constituent and analyzing the gas quality data to determine if or where corrosive constituents enter the gas stream. 
    • Mitigating: using technology to mitigate internal corrosion 
  • At least once every calendar year, not to exceed 15 months:  
    • Evaluate the collected data to ensure gas constituents are effectively monitored and mitigated. 
    • Review program to ensure its effectiveness. 


Using CIM to Comply: A new internal corrosion control module is available NOW that helps you monitor and mitigate internal corrosion by allowing you to gather and analyze the appropriate data in one location i.e. coupon data, maintenance pigging, sample analysis results, chemical program information (if applicable) and ILI data. Enterprise-wide reports are available for displaying the state of your internal corrosion program to determine effectiveness, create appropriate mitigation actions and conduct reviews.  

Managing the Threat of Weather Events §192.613 (Liquid §195.414) 

Another gas pipeline regulation that is mirrored in the "Liquid Mega Rule" is the requirement to respond to weather events and “inspect all potentially affected onshore transmission pipeline facilities to detect conditions that could adversely affect the safe operation of that pipeline” within 72 hours. This requires that operators know the pipeline locations that could be potentially affected by each type of weather or trigger event.  

Using CIM to Comply: As described in a recent blog, managing the threat of weather events becomes a problem of identifying where your pipeline or the surrounding environment is most likely to move. And the best way to solve this problem is obtaining environmental information and aerial photography through publicly available sources and aligning that with your pipeline . . . which is also currently in the works!  Stay tuned for a new geohazard module that will be available soon.

New Repair Conditions, §§192.933, 192.714 

The Gas Mega Rule Part 2 increased the number of repair conditions for pipelines in HCAs, specifically adding more conditions to the "Immediate" category as well as the "One-year," noting that “some injurious anomalies and defects were not listed as requiring remediation in a timely manner commensurate with their seriousness.” Repair conditions for pipelines not in HCAs were also added which include "Immediate," "Two-year" and "Monitored."  

Using CIM to Comply: All new repair conditions have been added to Integrity Compliance (Assessment Analysis) process within CIM for use when operators analyze their integrity assessment data 

Other Notable Mega Rule Part 2 Updates 

  • Management of Change (MOC), §§192.13(d), 192.911(k)): An MOC process per ASME B31.8S shall be developed and implemented for all pipelines covered under Part 192. Previously this was only required for IMP pipelines. 
  • Coating assessment, §192.319(d): a coating assessment is required for projects that involve1,000+ ft of continuous backfill.  
  • General repair requirements, §192.711: prescribes when a permanent and temporary repair should be made.  
  • ICDA and SCCDA, §§§192.923, 192.927, 192.929: are now allowable integrity assessment methods.  


Gas Mega Rule Part 2 Compliance  

As you can see - Part 2 of the Mega Rule is a significant update for operators of gas pipelines, specifically regarding pipeline integrity requirements. Most of these regulations require more efficient data and workflow management and center around repeated tasks i.e. monitoring, mitigation, follow-ups, reviews, etc. versus discrete one-time actions. How are YOU complying with these new enhanced requirements?  

Learn more about CIM. Comments or questions? We’d love to hear from you!