The Pipeline and Hazardous Materials Safety Administration (PHMSA) announced in January a number of changes in the pipeline safety laws in a final rule covering some of the provisions in the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The key provisions dealt with the timeframe for notification of accidents or incidents and new fees companies will have to pay PHMSA for its design review work on projects totaling more than $2.5 billion or which use new or novel technologies. PHMSA made some changes in the final rule in response to industry concerns. But in some cases, the agency ignored industry entreaties. All of the new requirements become effective March 24, 2017.
The Interstate Natural Gas Association of America (INGAA) is supportive of this rulemaking. “There may be small things that we wished were different, but we believe it’s a good rule that incorporates a lot of important safety improvements,” said a spokeswoman for the group.
PHMSA delayed finalizing a controversial expansion of the Operator Qualification (OQ) requirements authorized by Congress in the 2011 law. The agency says it will publish a broader final rule including construction and emergency response tasks in the OQ requirements “in the near future.” INGAA supported the expansion in theory but balked at the costs, arguing they needed to be commensurate with the anticipated benefits. C.J. Osman, INGAA’s pipeline safety director, said, “We appreciate that PHMSA is taking additional time to consider feedback on its proposed changes to Subpart N – Qualification of Pipeline Personnel, which has the potential to significantly impact pipeline operations and construction.”
On notification, PHMSA essentially followed the language of the 2011 act, which limits the timeframe within which the operator must electronically or telephonically report notice of an accident or incident to within one hour of confirmed discovery of the event. The pushback concerned the PHMSA’s use of the words “confirmed discovery” and INGAA’s argument that only significant events be reported within one hour. The agency defined “confirmed discovery” as there being “sufficient information to determine that a reportable event may have occurred even if an evaluation has not been completed.” The use of the modifier “may have” was criticized because it could be viewed as casting doubt on whether a “confirmed discovery” had been made. PHMSA did revise the definition of confirmed discovery to mean “when it can be reasonably determined, based on information available to the operator at the time, a reportable event has occurred, even if only based on a preliminary evaluation.” But there was no allusion to significant events.
A second element in the notification requirement is that within 48 hours after the confirmed discovery of an incident, an operator must revise or confirm its initial telephonic notice with additional information. INGAA unsuccessfully pressed PHMSA to eliminate the 48-hour notification saying the National Response Center (NRC), to whom both the one-hour and 48-hour reports are to be made, does not have the means to accept supplemental reports. That request also fell on deaf ears.
However, in sticking with the 48-hour notification requirement, PHMSA also rebuffed the National Transportation Safety Board which complained that the two-day respite for a follow-up report allowed pipelines to “provide incomplete information initially” in the one-hour report knowing they could be more accurate in the 48-hour report. This would delay receipt of information by the NTSB or other responding agencies that is needed to decide whether to mobilize a response. The NTSB suggested that the second notification requirement would be significantly improved if PHMSA established a follow-up reporting requirement that would be triggered only “when the pipeline operator has confirmed that previously reported information has significantly changed.” PHMSA declined to follow the NTSB’s advice.
There was industry concern regarding PHMSA’s proposed structure for design review fees. One of the hot spots was the 2011 law’s application of these new design review fees when “new and novel technologies” were being deployed. INGAA objected to the definition, saying it was “overbroad and far exceeds the intent of Congress’s authorization.” The American Gas Association (AGA) also criticized the language in the proposed rule. In response, PHMSA tacked “new construction” on to the end of the definition.
Christina Sames, vice president, operations and engineering, AGA, pointed out that the final definition tracks with the recommendation of a PHMSA advisory committee, and pretty much parallels the AGA’s suggested definition.
In fact, Sames explained that the AGA is generally happy with the entire final rule, although it is disappointed with one provision – farm taps. PHMSA revised the regulations to exclude farm taps from Distribution Integrity Management Programs and moved them to simple prescriptive inspection. “We believe that including farm taps under DIMP is a more holistic risk based approach but we understood that transmission operators of farm taps might not want to create a DIMP program simply for farm taps, so we were not opposed to PHMSA allowing operators to choose between including them in DIMP or simply inspecting periodically,” she stated.
API unhappy with liquid pipelines safety rule (subhed)
In its mad dash to complete rules prior to the Trump Administration taking office, PHMSA also finalized a new safety rule which affects onshore hazardous liquid pipelines. The rule strengthens the standards that determine how operators repair aging and high-risk infrastructure, increases the quality and frequency of tests that assess the condition of pipelines, and extends leak detection requirements to onshore, non-HCA transmission hazardous liquid pipelines.
Robin Rorick, director of the American Petroleum Institute’s Midstream Group, said, “We are concerned that this rule has the potential to decrease pipeline safety rather than improve it. We appreciate PHMSA taking into account our comments during the rulemaking process, and while this rule is an improvement over previous versions, the agency’s ‘one-size-fits-all’ approach in portions of the final pipeline rule creates situations where industry will be forced to redirect its attention away from areas that present higher risks to those that are lower in risk.”
Michael Tadeo, an API spokesman, declined to specify exactly which parts of the final rule the API finds most objectionable.
The rule includes an increased focus on a data-and-risk-informed approach to pipeline safety by requiring operators to integrate available data, including data on the operating environment, pipeline condition, and known manufacturing and construction defects. The rule requires pipeline operators to have a system for detecting leaks and to establish a timeline for inspecting affected pipelines following an extreme weather event or natural disaster. The inspections will allow operators to quickly identify damage to pipelines and make appropriate fixes.
The rule also requires operators to annually evaluate the protective measures they are already required to implement on pipeline segments that operate in high consequence areas (HCA) and implement additional measures as necessary. In addition, the rule sets a deadline for operators to use internal inspection tools where possible for any new and replaced pipeline that could affect an HCA. The rule also improves the quality and frequency of tests used to assess threats and the condition of pipelines.
Furthermore, the rule updates repair criteria under PHMSA’s risk-based management framework by expanding the list of conditions that require immediate repair.