The BP Deepwater Horizon spill continues to have ramifications for pipeline safety even though pipelines — neither gas nor oil — had nothing to do with that Gulf of Mexico disaster. Nonetheless, “BP” is an entry point for Congress and others to show renewed concern about potential environmental accidents from all sorts of energy activities.
Onshore natural gas pipelines aren’t escaping scrutiny. In this hyper-sensitive safety environment, a number of new concerns seem to be coming to the fore, making it increasingly unlikely the transmission industry will get an integrity management reform it has been ardently seeking for two years. That reform would allow pipelines to re-inspect segments in high consequence areas based on a risk assessment rather than the current IM program requirement of every seven years. INGAA and its member companies have been hoping that a congressional reauthorization of the pipeline safety law, which has been the subject of recent hearings, would include a “risk based” re-inspection standard. That now seems like a remote possibility.
Instead, pressure is mounting to tighten the PHMSA’s transmission IM program, not loosen it. At a June 24 hearing held by the Senate Commerce, Science and Transportation Committee, Deborah A.P. Hersman, chairman, National Transportation Safety Board, reeled off a string of gas pipeline accidents including one on May 4, 2009, when an 18-inch diameter gas transmission pipeline with an operating pressure of 850 psi ruptured near Palm City, FL. There were no fatalities. Hersman made the point that the operator of the pipeline had not inspected the segment per the PHMSA IM program because the company didn’t believe it was located in a high consequence area. PHMSA determined otherwise after the fact.
As a result of this, Hersman said, “The NTSB is concerned that the level of self-evaluation and oversight currently being exercised is not uniformly applied by some pipeline operators and PHMSA to ensure that the risk-based safety programs are effective. PHMSA must establish an aggressive oversight program that thoroughly examines each operator’s decision-making process for each element of its integrity management program.”
Carl Weimer, executive director of the Pipeline Safety Trust, went further at the Senate hearings. Weimer is clearly in the environmentalist camp, but he is no gadfly. He has credibility as a member of the Pipeline and Hazardous Materials Safety Administration’s (PHMSA) Technical Hazardous Liquid Pipeline Safety Standard Committee and as a member of the steering committee for PHMSA’s Pipelines and Informed Planning Alliance. He argued that only 7 percent of natural gas transmission pipelines and 44 percent of hazardous liquid pipelines are located in high consequence areas. He mentioned that the New Mexico pipeline leak which caused an explosion in 2000 killing 12 people is not in a high consequence area. He acknowledged that progressive pipeline operators already apply integrity management rules to significantly more miles of their pipelines than required by federal regulations.
“Unfortunately, not all companies voluntarily provide these needed safety precautions, and even those that do are not required to respond to the problems found as they would be if these areas were covered by the integrity management rules,” Weimer explained.
Pipeline Accidents Raise Questions About Damage Prevention
Two Texas intrastate pipeline accidents in June have turned up the heat on both Congress and PHMSA to address inadequacies in state “one call” laws and programs. The two accidents came up at the June 24 Senate Commerce Committee hearings where senators and industry officials, including Gary Sypolt, CEO of Dominion Energy, who were testifying on behalf of INGAA, called for Congress to strengthen PHMSA’s hand on excavation damage.
On June 7, 2010, a 36-inch natural gas transmission pipeline in Cleburne, TX, was struck and ruptured by a contractor for an electrical cooperative that was installing a pole for a power line. An ignition and explosion of the escaping gas resulted, and the operator of the auger was killed. Six other crewmen were hospitalized. On June 8, a natural gas non-regulated, 14-inch gathering line was struck by a bulldozer near Darrouzett, TX. Two persons were killed, one critically injured and three others escaped injury.
Currently, PHMSA has no regulatory authority over state one-call programs, which often revolve around “811” telephone numbers. PHMSA has some slight influence, however, since the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (PIPES Act) authorized PHMSA to award State Damage Prevention (SDP) grants to fund improvements in damage prevention programs. Since 2008, PHMSA provided over $4 million dollars in SDP grants to 30 distinct state organizations. To be eligible for a grant, a state program has to meet nine criteria laid out in the PIPES Act. One of those criteria is not inclusion of all excavators in the program. Many states have exemptions to their damage prevention one call rules for a variety of stakeholders including municipalities, state transportation departments, railroads, farmers and property owners.
“In order to provide the public with maximum protection, exemptions from state one-call programs should be strongly discouraged,” Sypolt said. “We recommend that such one-call exemptions be a factor that PHMSA must consider when deciding whether to make annual state pipeline safety grants and one-call grants.”
At the Senate hearings, Cynthia Quarterman, the PHMSA administrator, said she has been saying in her speeches that exemptions from one-call laws “are not something we believe are appropriate.”
In addition to potentially using exemptions as a SDP grant eligibility criterion, PHMSA has the authority — again, from the PIPES Act — to enforce state one-call laws if the state itself isn’t doing so. PHMSA finally got around to starting to flesh out regulations on enforcement of state laws last October when the agency issued what is called an advanced notice of proposed rulemaking (ANPR) asking for input on the criteria it should use to determine whether states are enforcing their one-call programs. One of the things PHMSA will almost assuredly consider in its analysis of state programs is whether they have exemptions for some excavators who are not required to call before they dig.
EPA Improves GHG Reporting For Pipelines, But Not Enough
Natural gas transmission companies say the EPA’s revised mandatory greenhouse gas (GHG) reporting rule is better than an earlier version, but far from perfect. In the argot of the agency, its “Subpart W” proposed rule, issued in April, is an offshoot of the final GHG reporting rule the agency published last October. That final rule applied to most manufacturers and industrials. Subpart W pertains to Petroleum and Natural Gas Systems only, and is suppose to take their operational idiosyncrasies into account.
Both INGAA and companies such as Kinder Morgan have said the April 2010 proposed rule is a significant improvement over one issued a year ago because, among other things, it makes greater use of emissions estimation and emission factors compared to the original proposal. But Lisa S. Beal, director, environment and construction policy, INGAA, says the Subpart W proposal would impose significant new cost and logistical issues for the natural gas transmission and storage segments. “Issues clearly remain that necessitate the commitment of additional time and resources to finalize the Proposed Rule,” she adds.
Again, the new proposal includes some welcome modifications. It focuses on key source types and eliminates some of the direct measurement requirements proposed in 2009. But Kim Dang, chief financial officer, Kinder Morgan Energy Partners, L.P., says the EPA has not taken into account, for example, the danger to employees posed by measurement requirements for units and components that are either unsafe or physically inaccessible.