A National Transportation Safety Board (NTSB) hearing March 1-2 in Washington may push Congress to renew failed efforts from last fall to upgrade pipeline safety laws. The hearings will air the NTSB’s preliminary findings from the Pacific Gas & Electric Co. (PG&E) pipeline explosion in California in September where seven people were killed.
Recommendations from the NTSB in January to PG&E, the state of California and the Pipeline and Hazardous Materials Safety Administration (PHMSA) grew out of the NTSB’s belief that PG&E conducted a faulty risk analysis on the pipeline segment at issue leading to a miscalculation of Maximum Allowable Operating Pressure (MAOP). But the NTSB did not conclude that the error led to the explosion. The exact cause has not been determined.
When the NTSB announced its recommendations in early January, it said its examination of the ruptured pipe segment and review of PG&E records revealed that although the as-built drawings and alignment sheets mark the pipe as seamless API 5L Grade X42 pipe, the pipeline in the area of the rupture was constructed with longitudinal seam-welded pipe. The NTSB suggested the seam-welded sections may not be as strong as the seamless pipe that was indicated in PG&E’s records.
In response, Kirk Johnson, PG&E vice president, Gas Engineering and Operations, answers, “The NTSB noted that it does not know at this time whether record discrepancies played any part in the San Bruno accident.” He adds, “PG&E is giving these recommendations close and immediate attention. We have been undertaking an intensive review of our pipeline records, scrutinizing and verifying thousands of documents to confirm the quality of our data.”
Terry Boss, senior vice president at INGAA, seconds Johnson’s point that the NTSB has not found the cause of the accident. He doubts that incorrect data on pipe strength used in MAOP calculations led to the accident and, moreover, describes that kind of recordkeeping error as “not compelling.”
One of the NTSB recommendations was that the PHMSA issue an advisory bulletin to all gas and hazardous liquid pipelines warning them about the importance of assessing risks and threats as part of an integrity management program. The PHMSA did that on Jan. 4. However, the language in that bulletin was critical of the industry, going way beyond what may or may not have happened in San Bruno, ticking off numerous insufficiencies the PHMSA feels is bedeviling integrity management programs.
The bulletin warned: “However, some operators are not sufficiently aware of their pipeline attributes nor are they adequately or consistently assessing threats and risks as a part of their IM programs.” Operator oversight of IM programs was deemed “lacking.” The bulletin went on to list “deficiencies” PHMSA has found in its inspections and investigations. “Inspections and investigations have revealed examples where assessment methods, specific tools, and schedules were not based on a rigorous assessment of the type of threats posed by the pipeline segment, including consideration of the age, design, pipe material including seam type, coating, welding technique, cathodic protection, soil type, surrounding environment, operational history, or other relevant factors. “
Richard B. Kuprewicz, president, Accufacts Inc., who is a member of the PHMSA technical advisory committee for liquid pipelines, and had a hand in fashioning the gas transmission IM program, says the advisory bulletin is “carefully and clearly worded in a matter that could be read as ‘terse.'”
He adds, the bulletin “makes very clear, given recent events and observations, that more than one pipeline has apparently not done their important homework.”
Boss takes issue with the implication in the advisory bulletin that there are systemic shortcomings in gas transmission compliance with aspects of the IM program. “If they are alluding to systemic problems with integrity management programs, those problems should be documented on their website,” he responds.
In fact, the PHMSA website says nothing particular about integrity management violations. It does list civil penalties proposed in 2010, of which there were 34. Only three of those cases have been closed, with penalties paid amounting to less than $80,000 per case. Those cases had nothing to do with IM program violations, much less faulty risk assessments. Dixie Pipelines paid the biggest fine, $78,000, because it had not sent public awareness program brochures to homeowners whose properties were damaged in a previous accident. The biggest proposed fine was on Chevron Pipe Line Co. That case is still open. PHMSA did site one integrity management violation, inadequate leak protection, among a number of other non-integrity problems in assessing a fine of $435,000. Moreover, across gas transmission, liquid, gas gathering and gas distribution lines in 2010, penalties proposed totaled $4.5 million. That is substantially less than the totals in 2008, the last year of the Bush administration, and 2009: $8.7 million and $6.4 million respectively.
A PHMSA official who did not want to be identified responds that the agency has identified 228 probable violations of integrity management regulations, resulting in approximately $1.4 million in proposed civil penalties. In addition, PHMSA has identified another 752 instances of inadequate integrity management plans or procedures since these requirements became effective in 2003. “PHMSA posts its enforcement cases on its Stakeholders Communications website, with the exception of cases that may not yet be finalized,” he adds.
Martin Edwards, vice president of Legislative affairs at INGAA, says, “We can pretty safely say all operators are taking integrity management extremely seriously. But there is a lot of give and take between the regulated community and the regulator. In addition, PHMSA is pushing to expand the envelope as reflected in its legislative proposal to Congress last year to expand the amount of pipe segments covered under the IM program.”
Kuprewicz believes Congress will address the shortcomings referenced in the advisory bulletin as “more comes to light about investigations uncovering major weakness in gas transmission approaches to IM rules.” Additional information could come to light in the NTSB hearings on March 1-2 which will probably explore how pipelines determine MAOP, and the adequacy of current practices in that regard.
The NTSB recommendations and the PHMSA advisory bulletin have been picked up by congressional radar. “The Committee is aware of them both,” says Justin Harclerode, spokesman for Rep. John Mica (R-Fl), chairman of the House Transportation and Infrastructure Committee. “As we prepare a pipeline safety reauthorization bill, we will take a hard look at the high profile pipeline accidents that have occurred over the past year and determine what changes need to be made to federal pipeline safety law in order to prevent these types of accidents from occurring in the future.”
PHMSA’s preferred means for establishing MAOP is via hydrostatic testing. But that means shutting down pipelines and temporarily stopping gas deliveries to customers. Consequently, operators prefer to use available design, construction, inspection, testing, and other related records to calculate the valid MAOP. While this method is permissible under the IM program, it is susceptible to error if pipeline records are inaccurate. In the case of the PG&E accident, the NTSB says its “preliminary findings indicate that the pipeline operator did not have an accurate basis for the MAOP calculation.”
Kuprewicz adds, “It is becoming very clear that a portion of gas transmission companies have not embraced the IM process defined in regulation and have twisted the intent. These companies clearly need to change their course. It is also becoming quite clear, given the lower number of miles inspected under IM, as well as the much lower number of repairs in HCAs, and the exclusion to avoid reporting repairs in non HCAs for gas transmission pipelines, that the IM regulatory process appears to have been subverted by some. For example, direct assessment (DA) was never intended to be the major inspection effort as the federal IM regulations are very clear on its limited technical applicability, and only a very few pipeline segments in HCAs have only the three risks that DA can reasonably address.”
INGAA’s Edwards responds that the 2002 congressional law which authorized the gas transmission IM program is very clear that companies can use any of three assessment tools: 1) smart PIG, 2) hydrostatic test, 3) direct assessment. “The law doesn’t distinguish between those three,” he adds.