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Agency Cites Coating Failure in 2015 Leak

Monday, September 26, 2016

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A federal pipeline safety agency has identified external corrosion as the cause of a June 2015 gas line rupture in rural eastern Pennsylvania.

Contributing factors included localized coating failure and pressure variations, a Central Pennsylvania news source reported Thursday (Sept. 22), citing an investigation report dated earlier this year.

34-Foot Fracture
Photos: PHMSA

The rupture of a 24-inch natural gas pipeline in Williams’ Transcontinental Gas line resulted in a 34-foot longitudinal fracture originating at the one-o'clock position on the pipeline, according to PHMSA’s investigation report.

The findings of the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) confirmed conclusions reached by the pipeline owner, Tulsa-based Williams Partners, that the failure was caused by a form of corrosion, PennLive noted.

34-Foot Fracture

The gas line rupture and leak occurred at about 9:30 p.m. on June 9, 2015, in a section of pipeline near the town of Unityville in Lycoming County. Local media reported an initial fire associated with the explosion was put out; PHMSA noted, however, that there were no fires.

Nearly 150 people were evacuated as a safety precaution, but there were no injuries, minimal environmental damage, and no impact to local waterways, the agency said.

The rupture occurred on a 24-inch natural gas pipeline as part of Williams’ Transcontinental Gas Leidy Line B. The Transcontinental Gas Pipe Line is a 10,500-mile interstate system extending from the Gulf and Southeast states through the Atlantic Coast states to the New York City metropolitan area.

The break consisted of a 34-foot longitudinal fracture originating at the one-o'clock position on the pipeline, the report noted. Visual and laboratory examination of the pipe showed the failure was not near or associated with the longitudinal weld seam on the pipe, it explained.

PHMSA’s Office of Pipeline Safety initiated its investigation the following day, and issued a Corrective Action Order June 12.

In addition to ordering a pressure reduction and operating restriction, the CAO called for submission of a restart plan, an instrumented leakage survey, review of prior inline inspections, mechanical and metallurgical testing, failure analysis of the failed pipe, and root cause failure analysis.

Ruptured pipe

Investigators reportedly observed corrosion and rust staining in the area surrounding the cracks, which indicated coating failure. “The coating failure could be due to inadequate surface preparation prior to applying the coating or soil stresses on the coating,” the report noted.

A third-party review of prior assessments of the failed pipeline showed no metal loss, cracking, or denting that would have contributed to the failure. Moreover, no anomalies associated with seams, wrinkles, buckles or strain in the area of the failure were identified.

Coating Failure, Corrosion

According to the agency’s report, PHMSA identified the cause of the break as near-neutral stress corrosion cracking (SCC) of the pipe.

“Localized shielding and coating failure, in addition to cyclic pressures during bidirectional flow, were identified as possible contributing factors to the incident,” the document stated.

Investigators reportedly observed corrosion and rust staining in the area surrounding the cracks, which indicated coating failure.

“The coating failure could be due to inadequate surface preparation prior to applying the coating or soil stresses on the coating,” according to the report.

The section of Line B that failed was constructed in 1963, and consisted of 24-inch diameter, 0.344-inch wall thickness, Grade X60, electric flash welded (EFW) seam pipe. It had an external coal tar coating, and no history of internal corrosion was recorded.

Line A, installed in the 1950s, also has an external coal tar coating. Line C, installed in 1987, sports a three-layer external phenolic epoxy coating.

Integrity assessments of Lines A and C showed no damage.

Close-up

The section of Line B that failed was constructed in 1963, and consisted of 24-inch diameter, 0.344-inch wall thickness, Grade X60, electric flash welded (EFW) seam pipe. It had an external coal tar coating, and no history of internal corrosion was recorded.

An August 2015 SES metallurgical analysis report determined that near-neutral pH SCC had begun on the external surface of the pipe and that groups of SCC colonies were found next to the rupture area, in addition to several areas nearby.

Corrosion pits of depths less than 10 percent of the pipe’s wall thickness were present on the outside surface in the vicinity of the SCC colonies, the report indicated, and were evident in areas where the exterior coating had locally disbonded from the pipe.

“The combination of transgranular cracking, corrosion of the crack sides, external corrosion pitting, and corrosion deposits containing iron carbonate (siderite) indicates that the cracking was the result of near-neutral pH SCC,” the analysis explained.

No evidence of mechanical or third-party damage contributing to the failure was identified, and pipe material properties met the requirements of API 5LX, Grade X60, confirming that the pipe properties did not contribute to the rupture, the report added.

The day of the break, operators had reportedly repositioned valves to change the flow of gas to a western storage area from an eastern station; the east-moving gas had flowed at a lower pressure. Records indicated that pressure slowly built in Line B throughout the day.

The report suggested that the bidirectional flow and pressure variations helped to cause the formation of the near-neutral pH SCC on the pipeline.

   

Tagged categories: Asia Pacific; Coating failure; Coating Materials; Corrosion; Cracking; Disbondment; DOT; EMEA (Europe, Middle East and Africa); Explosions; Latin America; North America; Oil and Gas; PHMSA; Pipelines

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