NTSB blames Enbridge for failures to comply with federal law; but IM rule often "unclear".
The NTSB report, which will be issued in final form publicly sometime in the future with additions and deletions from the preliminary report, came about one week after the DOT's PHMSA issued a Notice of Probable Violation with the largest proposed civil penalty in its history--$3.7 million--as a result of a spill of more than 840,000 gallons of crude oil into hundreds of acres of Michigan wetlands, fouling a creek and a river.
"This investigation identified a complete breakdown of safety at Enbridge. Their employees performed like Keystone Kops and failed to recognize their pipeline had ruptured and continued to pump crude into the environment," said NTSB Chairman Deborah A.P. Hersman. "Despite multiple alarms and a loss of pressure in the pipeline, for more than 17 hours and through three shills they failed to follow their own shutdown procedures."
The NTSB preliminary report appears to be a bit hazy on one issue: whether Enbridge violated federal hazardous liquid integrity management rules with regard to fixing pipeline defects and doing risk assessments with regard to what is called Line 6B. But the company clearly seems to have fallen short of compliance with regard to federal rules in the areas of operation and management procedures, reporting and operator qualification requirements. Perhaps the biggest problem was the Enbridge control room was asleep at the wheel. The rupture occurred during the last stages of a planned shutdown and was not discovered or addressed for more than 17 hours. During the time lapse, Enbridge twice pumped additional oil (81% of the total release) into Line 6B during two startups.
The NTSB's key finding was that the Line 6B segment ruptured under normal operating pressure due to corrosion fatigue. But the report goes on to say that federal law "does not provide clear requirements regarding when to repair and when to remediate pipeline defects and inadequately defines the requirements for assessing the effect on pipeline integrity when either crack defects or cracks and corrosion are simultaneously present in the pipeline."
The report then clearly faults PHMSA for failing "to pursue findings from previous inspections and did not require Enbridge Incorporated (Enbridge) to excavate pipe segments with injurious crack defects."
Asked whether PHMSA bore some responsibility for Enbridge's failures, Jeannie Layson, PHMSA's director for Governmental, International, and Public Affairs, says, "PHMSA will continue to take a hard look at internal operations, make improvements, and hold operators accountable when they violate our regulations and put our communities and the environment at risk."
In fact, the NTSB appears to exonerate Enbridge to some extent for not finding the cracks sooner and evaluating them properly by saying "PII Pipeline Solutions' analysis of the 2005 inline inspection data for the Line 6B segment that ruptured mischaracterized crack defects, which resulted in Enbridge not evaluating them as crack-field defects." PII Pipeline Solutions is one of the industry leaders in inspection and integrity services for gas and liquid pipelines.
But Enbridge clearly made numerous mistakes before and after the accident. The NTSB said Enbridge's integrity management program was inadequate because it did not consider the following: a sufficient margin of safety, appropriate wall thickness, tool tolerances, use of a continuous reassessment approach to incorporate lessons learned, the effects of corrosion on crack depth sizing, and accelerated crack growth rates due to corrosion fatigue on corroded pipe with a failed coating.
But again, underlining the inadequacy of federal law, as it does in a number of instances, the NTSB cites the absence of a "uniform and systematic approach in evaluating data for various types of in-line inspection tools" which is "necessary to determine the effect of the interaction of various threats to a pipeline." So, one wonders whether the PHMSA rules on risk assessment within IM programs are adequate to prevent the kinds of accidents that happened in Michigan.
The NTSB also cited a list of control room inadequacies, including a lack of training of personnel leaving them unable to correctly identify the cause of the Material Balance System (MBS) alarms. "Enbridge's control center staff placed a greater emphasis on the MBS analyst's flawed interpretation of the leak detection system's alarms than it did on reliable indications of a leak, such as zero pressure, despite known limitations of the leak detection system. Enbridge control center staff misinterpreted the absence of external notifications as evidence that Line 6B had not ruptured."
After the NTSB preliminary report was issued, Patrick D. Daniel, Chief Executive Officer, Enbridge Inc., said, "We believe that the experienced personnel involved in the decisions made at the time of the release were trying to do the right thing. As with most such incidents, a series of unfortunate events and circumstances resulted in an outcome no one wanted."
Enbridge will have an opportunity to present its case to the PHMSA, and ask, if it wishes, for a reduction in the civil penalty. The PHMSA fined Enbridge $2.4 million in October 2008 which the company ultimately paid. There an explosion and fire when a heater ignited an escaped flammable cloud of oil from a Clearbrook, MN pipeline that killed two Enbridge employees.
The NTSB preliminary report recommendations to PHMSA would seem to give Enbridge some leverage for arguing that some of its missteps, particularly related to addressing the crack which led to the leak, were understandable given the lack of clarity in federal law.
The recommendations include urging the PHMSA to revise current law "to clearly state:" (1) when an engineering assessment of crack defects, including environmentally assisted cracks, must be performed; (2) the acceptable methods for performing these engineering assessments, including the assessment of cracks coinciding with corrosion with a safety factor that considers the uncertainties associated with sizing of crack defects; (3) criteria for determining when a probable crack defect in a pipeline segment must be excavated and time limits for completing those excavations; (4) pressure restriction limits for crack defects that are not excavated by the required date; and (5) acceptable methods for determining crack growth for any cracks allowed to remain in the pipe, including growth caused by fatigue, corrosion fatigue, or stress corrosion cracking as applicable.
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|Publication:||Pipeline & Gas Journal|
|Date:||Aug 1, 2012|
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