A Dec. 11, 2012, natural gas pipeline explosion in Sissonville, W.Va., shows that work still needs to be done to inspect older lines, install automatic or remotely operated shutoff valves, and improve control room personnel’s responses, federal regulators told a US Senate Commerce, Science, and Transportation Committee field hearing in Charleston.
No one was killed or injured in the incident, which involved Columbia Gas Transmission Corp.’s Line SM-80, a buried 20-in. gas pipeline, and occurred at 12:41 p.m. EST on Dec. 11. But it took the operator nearly an hour to stop the line’s gas flow by manually closing shutoff valves, National Transportation Safety Board Chairman Deborah Hersman testified.
She said that like its earlier investigations of pipeline failures at Marshall, Mich., and San Bruno, Calif., NTSB has initially concluded that operators at CGT’s nearest pipeline control center at Charleston had trouble recognizing there was a problem at first.
“At Sissonville, pressure was falling on two other lines as well,” Hersman said. “But the control center received its first notification of the problem at 12:53 p.m. from Cabot Oil & Gas Corp., which heard about it from a field technician who was driving by the accident site…. Whether it’s in the control room or with valves, we know it’s taking too long to shut these pipelines down where there’s a problem.”
Although it has not completed its investigation, Hersman said NTSB believes several recurring factors it identified in previous inquiries were involved at Sissonville. Those safety issues include replacing manual shutoff valves with automatic or remote-controlled units, deploying in-line inspection tools, developing strong integrity management programs, and providing better Supervisory Control and Data Acquisition system training, Hersman said.
The valve factor
The kind of valves on a pipeline can affect how quickly it can be shut down during an emergency, according to Susan A. Fleming, physical infrastructure issues director at the US Government Accountability Office. “Valves that can be closed without a person at the valve’s location include remote-control valves, which can be closed via a command from a control room, and automatic-shutoff valves, which can close without human intervention based on sensor readings,” she explained.
The US Pipeline and Hazardous Materials Safety Administration does not mandate installation of automated valves, but requires they be considered in populated or environmentally sensitive areas, Fleming said. Automated valves respond more quickly, but some can close prematurely, she added.
She noted that GAO issued a Jan. 23 report calling for better collection of data to improve pipeline operators’ emergency response requirements. Fleming said this specifically involves the time it takes to identify and confirm an incident, when emergency response teams arrive at the scene, how long it takes to close a valve and isolate a pipeline segment, and the time taken for emergency responders to assess an incident and declare a site safe again.
“We know automated valves absolutely improve safety, but only in conjunction with a coordinated and rapid control room response,” Fleming said. “It’s important for control room personnel to have the training and authority to shut pipelines down in emergencies. We only talked to eight operators, but some of them told us the old way was to keep things running at all costs. They were pleased that the attitude was changing.”
PHMSA Administrator Cynthia Quarterman said the US Department of Transportation agency worked closely with NTSB and West Virginia’s Public Service Commission in investigating the Sissonville pipeline explosion. “We are also taking immediate action to determine what additional steps need to be taken to prevent accidents like this from occurring in the future,” she testified.
Corrective action order
PHMSA issued a corrective action order (CAO) based on its own investigation, and will not let CGT place the line back in service until it submits an acceptable restart plan, Quarterman said.
“When the pipeline is eventually placed back into service, it will operate at a 20% reduction from the maximum allowable pressure while our engineers oversee a series of tests and evaluations and review the results,” she said. “It is only after PHMSA is fully satisfied that the pipeline is safe for full operation that the pipeline can return to regular operating pressure.”
PHMSA also will require CGT to make it technically possible to inspect the pipeline that ruptured before allowing it to be placed back into service, Quarterman continued. “They have to change the valves at the ends of the pipeline so it can accept an in-line inspection tool and run inspections on it,” she said. Then they have to repair the line as if it was in a high-consequence area, even though it isn’t.”
The agency held a workshop on better data acquisition earlier this year, and is working with pipeline operators on improving the situation, Quarterman said. “The operators have been cooperative,” she indicated. “We actually did a pilot program recently to get more geospatial basis, and [CGT’s parent company] NiSource was one of the operators which volunteered.”
Jimmy D. Staton, a NiSource executive vice-president and group chief executive of its gas transmission and storage division, said CGT has been developing an integrity assurance plan in response to PHMSA’s CAO that will satisfy its requirements.
Plan’s specifics
“The work will include replacement of mainline valves along 30 miles of SM-80 from the Lanham compressor station to Columbia’s Broad Run valve setting; installation of launcher and receiver facilities at points along the line to enable passage of in-line inspection tools; verification that the cathodic protection system is operating properly on all three of Columbia’s pipelines in the vicinity of the incident; and installation and adjustment of pressure regulation and over-pressure protection equipment to support operation at a safe temporary maximum allowable pressure,” he said.
CGT also is taking significant steps to modernize its entire pipeline system, Staton added. It will replace 1,000 miles of aging interstate pipelines (primarily 400 miles of bare steel in the first 5 years), expand in-line inspection capabilities so inspections and maintenance can occur without disrupting service, up-rate pressures and looping systems where needed to make delivery more reliable, and replace and modernize more than 50 critical compressor units, he said.
“We anticipate investing more than $2 billion in this program over the next 5 years—dollars that will be directly focused on increasing pipeline safety and service reliability,” Staton said.
Eric Kessler, president of the Pipeline Safety Trust, noted that while pipelines and their regulators recognize the importance of recognizing that a leak has occurred and a line needs to be shut down, a final report that PHMSA provided the Senate Commerce, Science, and Transportation Committee found that less than 16% of gas transmission pipeline leaks are identified by current detection systems.
“This technology is certainly available,” said NTSB’s Hersman. “The problem with systems based on infrastructure 50 years old is like having a paper highway map instead of a global positioning system. That’s where we need to go: to have better technology in the pipelines themselves, and better-trained people in the control rooms.”
Contact Nick Snow at [email protected].
