December 2020 Vol. 75 No. 12
Washington Watch
GAO Report Cites Transmission Pipelines As ‘Generally Reliable’
By Stephen Barlas, Washington Editor
Transmission pipelines received something of an endorsement from the Government Accountability Office (GAO) in a study that found “Reports of serious interruptions of service that interstate transmission pipeline operators submitted to FERC from 2015 to 2019 show that unplanned service interruptions were generally infrequent and limited in scope.”
GAO did the survey after a request from two Rhode Island senators reacting to an outage in their state where about 7,000 homes and businesses went without heat for a week in January 2019. The report published in October looked at service interruptions to the customers of natural gas transmission pipelines between 2015 and 2019, and emerging risks of pipeline service interruptions.
On the first score, pipelines got high grades. After interviewing operators who manage over nearly 94 percent of the total interstate natural gas transmission miles in the United States, GAO concluded the transmission pipelines are “generally reliable.” That was based on reports of “serious interruptions of service” interstate pipelines are required to submit to the Federal Energy Regulatory Commission (FERC). Operators must file a report when the interruption of service to a firm customer is unplanned and lasts three or more hours. That happened 140 times from 2015 to 2019.
The reports don’t tell the whole story, however. Estimates based on these reports do not include interruptions lasting less than three hours or interruptions on pipelines that lie outside of FERC’s jurisdiction, such as intrastate gas transmission pipelines. Moreover, no operator has ever been fined for failing to submit a report, so there really is no incentive to do so.
The takeaway from the report – besides an “attaboy” for the industry – is GAO’s belief that FERC needs to do a better job of identifying and assessing “trends in the frequency or scope of service interruptions on interstate transmission pipelines” because of the growing dependence of electric utilities on natural gas.
“Without this analysis, FERC is not well-positioned to take action, if necessary, to fulfill its mission of working to ensure reliable natural gas transportation,” the GAO concluded. It recommended two specific actions that FERC should take: use available information, such as reports by transmission pipeline operators on service interruptions, to identify and assess risks to the reliability of natural gas transmission service; and develop and document an approach to respond, as appropriate, to risks it identifies to the reliability of natural gas transmission service.
Industry Gets Half a Loaf from PHMSA on Class Location Changes
After nearly 10 years of trying, gas transmission pipelines have finally won a partial victory to convince the Pipeline and Hazardous Materials Safety Administration (PHMSA) to ease the class location system for pipe replacement. But the agency, in its proposed rule published in mid-October, doesn’t go as far as the industry has wanted. This included ditching the class location system entirely for new pipe, which the Interstate Natural Gas Association of America (INGAA) wanted to be subject to an alternative integrity management system based on the potential impact radius of a pipeline segment.
Instead, the PHMSA proposal focuses exclusively on easing the class location system for existing pipe, specifically sections that are reclassified up to class 3 from class 1, as the result of increased residential and/or commercial population and buildings. Where “up-scored” sections qualify – and not all will – their operators can choose an alternative integrity management program instead of having to replace pipe.
The industry has argued the class location system requires too much unnecessary replacement of pipe. Classes are based on population and buildings within an area. PHMSA estimated that based on two different scenarios, over the next 20 years the number of pipeline miles going from class 1 to class 3 would be either 78 miles or 118 miles. Annual cost savings from not having to replace pipe would amount to approximately $55 million for one scenario, and $86 million for the other scenario.
“There are some things we like about the proposal and some things we don’t,” said one industry official in Washington. “We didn’t expect it to come out fully the way the industry wants. But it is largely what we expected.”
Pipelines have pressed for the elimination of the class location system for nearly 10 years. Congress included a provision in the 2011 Pipeline Safety Act that required PHMSA to evaluate whether applying IM principles to areas outside of high consequence areas (HCA) could possibly mitigate or eliminate the need for class location requirements. In a 2016 published report, PHMSA said the application of IM requirements to gas transmission pipelines outside of HCAs would not warrant the total elimination of class locations.
However, PHMSA stated that it intended to consider whether adjustments were needed in the way that operators were required to implement certain requirements when class locations did change. On July 31, 2018, PHMSA published an advance notice of proposed rulemaking (ANPRM) that made good on that promise and asked for suggestions on changes in class location requirements.
This proposed rule is the next step. It addresses the limited situation where an operator is faced with a change from a class 1 location to a class 3 location. In such cases, under the class locations system, the existing options of pressure testing or reducing operating pressure
can be technically or operationally prohibitive for meeting contractual gas flow volume obligations.
If an operator cannot pressure test or reduce operating pressure, the only options remaining per the existing regulations are to replace the pipe with higher-strength pipe by installing pipe with either greater wall thickness or higher steel grade, or apply for a special permit.
Pipelines that choose to take advantage of the new alternative for “allowable segments” would follow IM requirements in subpart O (the 2003 final rule) and additional requirements for applicable segments, which include required in-line inspections (ILI), external pipeline coating, cathodic protection, pipeline repair criteria to maintain MAOP with a Class 1 location 39-percent safety factor; usage of remote-controlled or automatic shutoff valves; and other additional preventive and mitigative (P&M) measures. PHMSA expects these measures to provide for an equivalent level of safety for the life of the pipeline when compared to pipe replacement.
However, a pipeline segment can only be eligible for the IM alternative if it has a documented, successful, eight-hour pressure test to a minimum of 1.25 times MAOP. Even then, segments would not be eligible if they had such things as bare pipe, wrinkle bends, missing material properties records or some other listed shortcomings.
The pipeline industry official said that some of these exclusions would be front and center in the industry’s efforts to modify the proposed rule.
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