INGAA Locks Horns with PHMSA

The Interstate Natural Gas Association of America (INGAA) has locked horns with the Pipeline and Hazardous Materials Safety Administration (PHMSA) over the agency’s advisory bulletin on pipeline safety.

PHMSA sent out that bulletin as the result of a recommendation from the National Transportation Safety Board (NTSB), following preliminary findings from an investigation of the explosion of a Pacific Gas and Electric Company (PG&E) gas pipeline last year. Seven people died in the explosion near San Bruno, CA.

In a Jan. 31, 2011, letter to top PHMSA safety official Jeff Wiese, INGAA President Don Santa, wrote, “We are concerned, however, that the advisory bulletin could be read to countermand longstanding regulations and disturb what we understood to be mutual expectations concerning the implementation of integrity management programs on natural gas transmission pipelines.”

Santa argued, “The advisory bulletin is overly broad and could be read to require operators to review vast amounts of data unrelated to cases where records were used to determine a segment’s MAOP.”

The PHMSA advisory bulletin issued in early January urged pipelines to be absolutely sure that the data they used to calculate Maximum Allowable Operating Pressure (MAOP) was accurate. In the PG&E case, the NTSB found that although the company’s records indicated that the pipeline in the area of the rupture was constructed of seamless pipe, it was instead, at least in part, constructed of longitudinal seam-welded pipe. In addition, some of the seams of this section of pipeline were welded from both the inside and the outside of the pipe, while others were welded only from the outside.

Santa also took issue with the advisory bulletin’s reference to taking “defects” into account when establishing MAOP. Santa argued that “stable” defects can be disregarded under the gas transmission integrity management program. “INGAA assumes PHMSA did not intend the advisory bulletin to countermand existing regulations or to impose additional regulatory requirements,” Santa wrote. “Yet several passages in the advisory bulletin, particularly those referring to activities operators ‘must’ undertake, lend themselves to troublesome interpretations.”

Proposed changes for Hazardous Liquids IM Program
While gas transmission pipelines are worried about advisory bulletins, hazardous liquid pipelines are fretting about new PHMSA regulations that are in the offing. The PHMSA had already indicated last October that it planned to tighten provisions of the hazardous liquid integrity management program. The advanced notice of proposed rulemaking (ANPR) issued on Oct. 18, 2010, suggested a number of significant changes, so much so that industry players asked PHMSA to extend the comment deadline, which was slated to end on Jan. 18, for 60 days. On the same day the PHMSA released its “San Bruno” advisory bulletin, it also announced that it would extend the comment period for the liquid line ANPR, but only for one month, to Feb. 18.

That ANPR contained a laundry list of hazardous liquid IM program upgrades PHMSA was considering such as: steps extending regulation to certain pipelines currently exempt from regulation; whether other areas along a pipeline should either be identified for extra protection or be included as additional high consequence areas (HCAs) for Integrity Management (IM) protection; whether to establish and/or adopt standards and procedures for minimum leak detection requirements for all pipelines; and whether to establish and/or adopt standards and procedures for improving the methods of preventing, detecting, assessing and remediating stress corrosion cracking (SCC) in hazardous liquid pipeline systems.

Leak detection measures could be at the top of PHMSA’s list of things to address given the leak that occurred in the Trans-Alaska Pipeline in January. That leak shut down the pipeline for a number of days, which was unusual. Fortunately, the leak was, in terms of the environment and public safety, relatively minor, though the shutdown cost the five companies who own the oil that runs through the pipeline considerable money, as it did the state of Alaska. The Alyeska Pipeline Service Co. said the leak was hard to get at because the leaking pipeline was underground and encased in cement. Also raising the profile of oil pipeline leak detection was the $435,000 fine for Chevron Pipe Line PHMSA proposed on Nov. 1, 2010. There, Chevron had identified leak detection inadequacies in a line in 2007 but failed to take remedial action.

Groups such as the American Petroleum Institute and Association of Oil Pipelines had asked for the 60-day comment period extension, citing the complexity and impact of the potential changes on their companies. Peter T. Lidiak, director, pipeline, API, says, “We are looking at all the questions posed by PHMSA and planning to respond to each one in some detail. We will urge PHMSA to continue to allow risk ranking of what is regulated so that resources can be appropriately prioritized for and focused on where the greatest risks are. Also, there is potential for regulatory duplication and overlap and PHMSA should be careful to consider oversight of pipelines by state and other federal agencies before they extend their own regulations to additional classes of pipelines. Potentially duplicative or conflicting requirements would not serve greater pipeline safety.”

INGAA wants flexibility on greenhouse gas monitoring
INGAA is pressing the Environmental Protection Agency (EPA) to clarify greenhouse gas (GHG) reporting rules for 2011. Companies had to monitor greenhouse gas emissions from compressor combustion in 2010, and report emissions over 25,000 tons as of March 31, 2011. For year 2011, pipelines will have to monitor fugitive and vented emissions as well from centrifugal compressor venting, reciprocating compressor rod packing venting and a few other less significant sources. Combustion measurements were fairly easy; monitoring fugitive and vented emissions, mostly of methane, will be much more difficult because measurement has to be done directly, by a worker, which in many cases, particularly with regard to blow down vents, can pose serious safety threats because of the difficulty of getting to those vents.

That explains the petitions the INGAA filed in late January, one to the EPA and the other to the U.S. Circuit Court of Appeals in Washington, DC. The very similar petitions request that the EPA allow transmission pipelines to use best alternative monitoring methods (BAMM) to compute GHG emissions. BAMM allows pipelines to measure fugitive and vented emissions without a company having to re-engineer a compressor station to make access to a blow down vent, for example, safe for a worker. BAMM are based on supplier data, engineering calculations or other owner or operator records.

The oil and gas industry GHG reporting rule the EPA issued last year basically allows use of BAMM up until June 30, 2011. After that date, companies have to use very specific monitoring technologies dictated by the EPA. Companies could use BAMM after June 30 until the end of 2011, but only if the EPA approves an application in which the company proves extreme circumstances, which includes safety concerns. If companies want to use BAMM in 2012 and beyond, they would have to prove extreme and unique circumstances.

Lisa Beal, vice president, environment and construction policy at INGAA, emphasizes that her members have every intention of reporting GHG emissions. But the cost of re-engineering compressor stations, and the time that will take so that direct measurement of vents can be made, will be substantial. Hence the need for some EPA flexibility on deadlines after which BAMM cannot be used.

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