New Rulemaking and Corrosion: How Mega Rule Part 2 Could Impact You

The Pipeline and Hazardous Materials Safety Administration (PHMSA) is preparing to publish Part 2 of the Gas Mega Rule. The Gas Mega Rule Part 1, published Oct. 1, 2019, focused on pipeline integrity. Part 2 will include components specific to external corrosion prevention for gas transmission lines. Here’s a quick look at the external corrosion aspects of the proposed rulemaking and how it could impact you.

Coating Assessments

Historically, most efforts in the pipeline corrosion industry have been about Cathodic Protection (CP). While CP systems are a critical component of the operation and maintenance of pipelines, they are not the primary source of corrosion protection for pipelines. The first line of defense is coatings. Part 2 focuses on coatings by ensuring their proper application and integrity ­— especially following construction activities.

This will be achieved primarily through post-construction coating assessments. As it is currently proposed, any installation, repair, or replacement of natural gas main greater than 1,000 feet in length will need a coating survey to be performed after backfilling. These surveys include both ACVG and DCVG, and any indications that are classified as moderate or severe according to NACE SP0502 will need to be addressed.

These surveys could have a major impact on the work scope of post-construction activities. Operators may need to develop contract language to include these surveys, and additional language regarding the remediation efforts (if any actionable indications are found). It may be prudent to consider performing the coating surveys as soon as possible after backfill to ensure a contractor is on site to address any necessary remediation efforts.

Annual Voltage Surveys

Another critical element proposed in Part 2 addresses annual voltage surveys. Any “down” reads (i.e., those below NACE protection criteria) will require follow-up surveys to determine the extent of the issue. The proposed wording describes performing a CIS at five-foot intervals upstream and downstream of the deficiency. Any issues will then need to have a remediation plan developed. Non-systemic causes are exempt (i.e., electrical shorts, rectifier malfunctions, power source interruption, or CP current interruption).

The biggest impact on operators will be on their maintenance activities. After reviewing the annual reads, the operator will need to understand the cause of the low voltage potential. If it was determined to be non-systemic, then a re-read after addressing the issue should be performed. If it is systemic, then a new work order or activity will need to be scheduled to perform a field assessment to determine the issue’s extent. Following that, a remediation and action plan will need to be implemented and the situation addressed within the mandated timeframe.

AC and DC Interference

Under this section of Part 2, a program must be developed to perform three tasks: identify the presence of interference, analyze the results to determine whether it impacts the cathodic protection system, and implement remedial actions.

Interference sources can be static and dynamic and involve AC and DC currents. For AC sources, the criteria would be anything that increases the risk of safety hazards or AC corrosion. Some operators consider that any predicted or measured AC current densities greater than 100 A/m2 will need to be addressed. Some use more restrictive criteria. Evaluations should be performed for steady state and fault interference scenarios. For DC sources, interference is defined as anything that impacts the polarized potential of the structure resulting in readings not meeting protection criteria. Interference sources could be foreign pipeline operators, third party CP infrastructure, or even DC transit systems.

To prepare, operators should review their existing corrosion or integrity standards. A section should be dedicated to addressing AC and DC interference scenarios and how to remediate the situation. Operators may also need to review their existing operating procedures and ensure their field personnel are not only trained in determining interference situations, but are also collecting the correct data to support such a finding. Existing GIS-based systems may be able to develop interference threat assessments from nearby infrastructure.

EN Engineering has experience performing all of these services and can develop programs to address these anticipated changes. For more information on how we can help, call or email Jeff Creaney at 346-888-4988 or

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