A full Senate vote is the next step for a pipeline safety bill which cleared a Senate committee in December. The Senate Commerce, Science and Transportation Committee approved the Securing America’s Future Energy: Protecting Infrastructure of Pipelines and Enhancing Safety (SAFE PIPES) Act (S. 2276) by a bipartisan vote.
The bill contains very few new safety mandates, especially compared to the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has been very slow to implement the 2011 bill, to the chagrin of many inside and outside Congress.
Some pipeline industry partisans are very supportive of the Senate bill. “This is a great first step,” said Dave McCurdy, American Gas Association president and CEO. “We applaud this bipartisan action and look forward to working with this committee as well as members of the House to get a final bill passed and on the president’s desk as soon as possible.”
The 2011 law required PHMSA to address 42 mandates, some requiring final rules. Others required reports and recommendations. An important provision for the interstate pipeline sector was Section 5 which required PHMSA to evaluate and issue a report on whether gas transmission integrity management program (IMP) requirements should be expanded beyond high-consequence areas (HCAs) and whether such expansion would mitigate the need for class location requirements.
PHMSA issued a request for comments in 2013 but has not proceeded beyond that. The gas pipeline community has waited impatiently for the next step. Even Don Santa, INGAA president and CEO, expressed exasperation at hearings last year about how long it is taking for PHMSA to publish a proposed rule. A final rule will not appear for at least a year after the proposed rule was published.
The new Senate bill again addresses the IMP/class location issue. It brings the Government Accountability Office (GAO) into the reporting writing queue and has it determining whether IMP/class location provisions in the final rule mentioned above, whenever that is finally published, “would prevent inadvertent releases from pipelines and mitigate any adverse consequences” from those releases. Those recommendations could include changes to the current definition of HCAs, or expand IM beyond HCAs, or review the cost-effectiveness of legacy class location regulations and a description of any challenges affecting the natural gas industry in complying with the program, and how the challenges are being addressed.
The Senate bill requires the GAO to do the same study of the IM program for liquid pipelines. There, however, PHMSA published a proposed rule in October suggesting some major changes.
The Senate bill also creates a new safety program for underground natural gas storage facilities. The major leak from a Southern California Gas Co. underground facility near Los Angeles late last year probably gives momentum to this provision. It requires PHMSA to issue minimum uniform safety standards, ‘incorporating, to the extent practicable, consensus standards for the operation, environmental protection, and integrity management of underground natural gas storage facilities.” Those must be published within two years of passage of the bill. The bill does add a caveat here: to ensure that the regulations do not have a significant economic impact on end users to the extent practicable.
EPA Proposal to Reduce Methane Leaks from Pipeline Equipment Stirs Controversy
Besides lending credence to the provision in the new Senate pipeline safety bill, the Southern California Gas Co. underground gas leak – given its large methane release – may also give some new legitimacy to the Environmental Protection Agency’s (EPA) proposed restrictions on methane emissions from the natural gas industry. The proposal would require controls on emissions of methane from centrifugal compressors, reciprocating compressors, and pneumatic controllers.
The requirements are very technical in each case, with opposition from pipeline companies based on such things as the agency mandating: Optical Gas Imaging (OGI) for leak detection and blowdowns conducted to enable leak repairs. The leak detection and repair (LDAR) program the agency wants to implement would, in the minds of many industry executives, divert attention from INGAA’s Directed Inspection and Maintenance Program (DI&M), which is viewed as more reasonable than LDAR.
The LDAR regime involves an initial survey of “fugitive emissions components,” which is an expansively defined category of equipment. After the initial survey, an operator must survey semi-annually. The LDAR regime also has a self-ratcheting dynamic. If a survey detects fugitive emissions from just 3% or more of the fugitive emission components during two consecutive semi-annual surveys, the survey frequency increases to quarterly.
“The INGAA DI&M facilitated through the Methane Challenge Program has the ability to achieve methane reductions more quickly from existing facilities than the proposed NSPS
OOOOa Rule which only affects new or modified facilities,” stated Gary Buchler, chief operating officer, Natural Gas Pipelines, Kinder Morgan. “The logistics of conducting both a voluntary DI&M program at existing sources and an NSPS OOOOa fugitive emissions monitoring program at new and modified sources, or both at the same source if that source is modified, is daunting and logistically difficult.”
NSPS stands for New Source Performance Standards and is one of EPA’s high profile air emission regulatory programs. Methane leaks from pipeline equipment have not been covered but would under this proposal, labeled “OOOOa.”
With regard to unnecessary blowdowns, INGAA’s Theresa Pugh, vice president of environment and construction policy, said, “The proposed rule requires an operator of a compressor station that identifies a leak through such a monitoring survey to repair the leak in 15 days, with the possibility for an extension only under limited circumstances. The failure in the proposed rule to provide a reasonable delay of the repair provision will lead to adverse consequences, including the possible impairment of transportation service to pipeline customers during high-demand periods and increased methane emissions due to otherwise unnecessary blowdowns conducted to enable leak repairs.”
There are a variety of industry complaints about elements of the provision’s requirements in each of the three equipment categories. For example, EPA proposes rod packing for reciprocating compressors be changed every 26,000 hours, no later than every 36 months.
Greg Ammon, director of Environmental, Northern Natural Gas, said Berkshire Hathaway Energy (BHE) Pipeline Group (which includes Northern Natural) recommends EPA consider the option to monitor rod packings after 26,000 hours and replace only when the condition of the packing merits replacement as per manufacturer recommendations. Once the packing merits replacement, Ammon suggested the rod packing would be required to be placed on a delay of repair list to be changed at the next shutdown. “This method is cost-effective and reduces waste generation, instead of changing the packing while it still has useful life,” Ammon said.