PHMSA Plans to Modernize U.S. Gas Pipeline Safety Rules

With the proposed amendments, PHMSA hopes to ease regulatory burdens on the construction, maintenance, and operation of gas transmission, distribution, and gathering pipeline systems.

The U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) (Washington, DC, USA) recently issued proposed amendments to federal pipeline safety regulations. According to PHMSA, these regulations are intended to ease regulatory burdens on the construction, maintenance, and operation of gas transmission, distribution, and gathering pipeline systems.

“The amendments in this proposal are based on PHMSA's considered review of public comments, petitions for rulemaking, and an agency initiative to identify appropriate areas where regulations might be repealed, replaced, or modified,” the agency writes in a proposed rule published in the U.S. Federal Register on June 9, 2020.1

Remote Monitoring

As it pertains to the corrosion industry, PHMSA is proposing to clarify that cathodic protection (CP) rectifiers can be monitored remotely. The agency is also seeking to revise the requirements for assessing atmospheric corrosion on distribution service pipelines.

“Virtually all hazardous liquid and most natural gas transmission pipe in service today is made of steel,” PHMSA writes. “This steel, when not otherwise protected, reacts with its environment and can deteriorate over time. Under certain conditions, unprotected metal can corrode, causing gas leaks that can threaten public safety.”

To guard against this, PHMSA says its proposed rule requires, with some exceptions, CP and protective coatings to mitigate corrosion risks on pipelines. CP works like a battery, the agency explains, running an electrical current across the buried pipeline using devices called rectifiers. The electrical current prevents the metal surface of the pipe from reacting with its environment. If the current is sufficient, CP can control the threat of corrosion.

With regards to rectifiers, PHMSA believes that advances in technology have made it possible to remotely monitor the proper operation of these systems. However, they say it is not clear in the current regulations if this is permissible. As such, PHMSA wants to revise the rule to clarify that operators may inspect rectifier stations directly at the site or by way of remote monitoring technologies. This proposed rule also specifies that, at a minimum, such an inspection consists of recording amperage and voltage measurements. In a separate rulemaking, PHMSA says it is considering a similar revision for monitoring rectifier stations on hazardous liquid pipelines.

PHMSA notes that its experience has shown that rectifiers, often located in remote areas, can be subject to damage from a variety of sources, including natural forces and vandalism. If an operator chooses to monitor a rectifier remotely, PHMSA is proposing to require operators to physically inspect that station whenever they conduct a CP test. For transmission pipelines and distribution mains, this will occur once each calendar year, concurrent with required inspection activities.

Reassessment Intervals

Separately, PHMSA is also working to establish an atmospheric corrosion reassessment interval for gas distribution pipelines. Currently, according to the agency, all onshore gas pipelines that are exposed to the atmosphere must be inspected once every three years, and not to exceed 39 months.

In that segment of the rule, PHMSA is proposing a maximum inspection interval for service lines of once every five years and not to exceed 63 months, unless atmospheric corrosion was identified on the last inspection. PHMSA also proposes to keep the current inspection interval on service lines with observed corrosion. If an operator identifies atmospheric corrosion on a service line during an inspection, then the interval for the subsequent inspection would be once every three years. If no atmospheric corrosion is identified on a subsequent inspection, then operators would be permitted to revert to the five-year interval.

Atmospheric Corrosion Risks

PHMSA is also clarifying that existing requirements for corrosion monitoring include the consideration of atmospheric corrosion risks. In its rule, PHMSA says it would expect operators of service lines in high-corrosion environments to consider atmospheric corrosion in their evaluation and conduct those inspections on a more frequent basis. As such, the rule establishes a maximum inspection interval of five years for distribution service lines without observed corrosion.

PHMSA says it recognizes that not all environments face the same atmospheric corrosion risks. However, based on inspection results and field experience, the agency determined that establishing a maximum inspection interval, rather than an open-ended reference, could ensure that atmospheric corrosion on distribution facilities is adequately monitored and remediated before it leads to a failure.

The proposed maximum interval of five years was supported in public comments, according to PHMSA, which says it will allow operators of gas distribution pipelines with low atmospheric corrosion risks to realize cost savings from less-frequent inspections and the ability to schedule corrosion inspections and leakage surveys concurrently. The agency says it considered input from several industry associations in coming to these conclusions.

“The proposed requirement to evaluate atmospheric corrosion risks and the shorter inspection interval for pipelines with observed corrosion will ensure that operators of service pipelines with atmospheric corrosion threats take appropriate action to maintain the integrity of those pipelines,” PHMSA writes.

Risk Factors

When evaluating atmospheric corrosion risks, PHMSA says it expects operators to evaluate environmental risk factors and the operating history of the service lines. Environmental risk factors for atmospheric corrosion include proximity to coasts, atmospheric moisture, salinity, and corrosive pollution. Meanwhile, relevant operational risks include a history of leaks, incidents, and evidence of atmospheric corrosion on previous inspections.

PHMSA expects operators of distribution lines with higher risks due to atmospheric corrosion to take mitigative action, such as more frequent inspection or maintenance activities, as part of their plans. Those operators will also be called on to accurately and completely document such actions.

Other aspects of the proposed U.S. gas pipeline regulatory reform include updating the design standard for polyethylene pipe and raising the maximum diameter limit; revising test requirements for pressure vessels consistent with codes from The American Society of Mechanical Engineers; and revising welder requalification requirements to provide scheduling flexibility. In total, PHMSA says it has quantified annualized cost savings of $129.4 million per year, or a 7% discount rate, from the proposed rules.

The agency says it looks forward to reviewing comments on the proposal “and will closely keep them in mind while determining the final rule.”

Sources: PHMSA,; Federal Register,


1 “PHMSA Announces Gas Pipeline Regulatory Reform Notice of Proposed Rulemaking,” PHMSA Newsroom, May 28, 2020, (July 7, 2020).

Related Articles