The Pipeline and Hazardous Materials Safety Administration (PHMSA) has published Part 2 of the Gas Mega Rule on August 24, 2022; it will be live on May 24, 2023. Part 2 will include components specific to external and internal 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.
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. Any installation, repair, or replacement of natural gas main greater than 1,000 feet in length will need a coating survey to be performed within six months after putting the pipeline into service. These surveys include both ACVG and DCVG, and any indications that are classified as 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.
Another critical element in Part 2 addresses annual voltage surveys. Any “down” reads (i.e., those below NACE protection criteria) will require a follow-up CIS at five-foot intervals upstream and downstream of the deficiency to determine the maximum extent of impact. This activity will need to be planned within six months of identifying the issue and executed within 12 months following plan development and permit acceptance. A follow-up CIS will then need to be performed to confirm resolution. Non-systemic causes are exempt from this testing (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.
A program must be developed to perform three tasks: identify pipeline segments subject to AC & DC interference, analyze the results to determine whether it presents a corrosion and/or safety risk, and implement remedial actions.
Identifying pipeline segments subject to interference may require AC & DC threat analyses throughout the system based on proximity of overhead powerlines, underground electrical transmission, substation proximity, foreign pipelines and CP facilities, and other potential interference sources.
Modeling or field work may be required to be performed to assess the safety and corrosion risk on those segments. The wording states the analysis results should determine the cause of the AC & DC interference, whether the levels could cause significant corrosion (>100 A/m2AC), or if it impedes the safe operation of a pipeline, or that may cause a condition that would adversely impact the environment and public.
Once identified, a remedial action plan is required to reduce the interference risks within six months after completion of the survey. All remediation installation must then be completed within 12 months following plan development and permit acceptance.
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. AC and DC current densities and voltages may need to ensure adverse impacts to the environment or public are not met.
For onshore gas transmission pipeline that transport corrosive gas, each operator must develop and implement a monitoring and mitigation program to identify potentially corrosive constituents in the gas being transported and mitigate the corrosive effects. This includes monitoring by coupons or other measures checked twice per calendar year not to exceed 7½ months.
For segments where potential corrosion contaminants are identified, technology to mitigate the effects such as product sampling, inhibitor injections, in-line cleaning pigging, separators, or other means will need to be installed or able to be installed to address. An evaluation will need to be made once per calendar year not to exceed 15 months to ensure remediation of the corrosion risk. An IMP will be required to be reviewed annually not to exceed 15 months based on the results of the monitoring and sampling programs.
This wording may have significant impact on operators. The wording requires operators to prove they have non-corrosive gas or constituents and monitor those levels during operation. This may require installation of new sampling and monitoring facilities, as well as have the ability for pig launcher/receivers, inhibitor injection and removal or other technologies. Actual values and partial pressures of corrosive gas constituents and water will need to be monitored, and their corrosive effects need to be considered individually and in combination of each other.
EN Consulting 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 jcreaney@enengineering.com.
Sign Up to get Latest Updates
myENTRUST