Diluted bitumen, heavy crudes are similar, NAS panel told
Diluted bitumen (dilbit) from Alberta’s oil sands is so similar to heavy crude oils, which US pipelines have handled for years, that it is unlikely to pose corrosion problems, experts told a National Academies of Science panel on July 23.
Diluted bitumen (dilbit) from Alberta’s oil sands is so similar to heavy crude oils, which US pipelines have handled for years, that it is unlikely to pose corrosion problems, experts told a National Academies of Science panel on July 23. “Once processed, dilbit is simply oil,” said Peter T. Lidiak, pipelines director at the American Petroleum Institute. “It’s made of the same components in any mixture of crudes.”
Crude from Canada’s oil sands has been delivered to US refiners by pipeline since 1968, he told the committee studying pipeline transportation of dilbit at the request of the US Pipeline and Hazardous Materials Safety Administration. Tariff specifications from the US Federal Energy Regulatory Commission limit impurities in pipeline crude, including total water and solids, which must be less than 0.5%, Lidiak said.
“Pipelines are high-value assets intended for operation over many years,” he added. “Operators have no incentive to accept shipments which could damage their systems.”
John Zhou, of Alberta Innovates Energy and Environment Solutions, part of the provincial government’s technology arm, said the group’s comparison of sour crudes and dilbits found no significant differences, although solids in both instances need to be better characterized.
“For me, dilbit is just another crude,” said Oliver Moghissi, president of NACE International in Houston and director of the materials and corrosion technology center at DNV Columbus (Ohio) Inc. “We just put back into it some of what comes from other crudes.”
Sources of problems
Problems mainly arise when water that has not been removed from a crude before it goes into a pipeline begins to separate and collects at points along the bottom of the pipe’s interior, he explained. Dissolved gases—primarily carbon dioxide—and oil extracts such as organic acids also can influence corrosion rates, Moghissi said. Running a pig through the pipeline probably is the most effective corrosion inhibiter, although chemicals also can help, he told the panel.
“For new pipelines, design, manufacturing, and construction will be more important than preventing internal corrosion in preventing releases,” Moghissi said. “It’s also important to sample under live conditions. You can’t do it in a tea cup or mayonnaise jar because the atmosphere will have changed.”
But Jeffery Gilliam, PHMSA’s engineering and research director, said the US Department of Transportation agency concentrated on internal corrosion because it’s the single most likely risk factor since it involves the interaction of a transmitted product on the pipeline’s interior.
Although concern has been expressed about possible problems from pipelines shipping crudes that may be more corrosive because they contain abrasives, lines transmitting dilbits have had only nine corrosion incidents in the last 10 years, he told the NAS committee. Naphtha normally is used as a diluting agent, although gas condensates and similar light products also work, Gilliam said.
“As a starting point, the committee might want to reference similar types of crudes,” suggested Linda Daugherty, PHMSA’s deputy associate administrator for policy and programs. “Age also is a definite factor. Many pipelines were installed 40 years ago and have sharp turns where water which has separated from dilbit would tend to collect and start corrosion.”
Officials from two pipeline companies that ship Canadian crude to US refineries also said preventing water accumulation is the major weapon against interior corrosion. Both Canada’s National Energy and FERC in the US limit allowable sediment and water to 0.5%, according to Scott Ironside, Enbridge Inc.’s integrity programs director. The pipeline firm regularly runs pigs where its lines are susceptible to water or solids accumulation, he said. “Enbridge has never had a release caused by internal corrosion on its piggable pipelines,” he reported.
“US refineries can handle heavy, sour crude we’re shipping from Canada because they’ve been handling it from Venezuela and California for years,” maintained Jenny Breen, who helped Alberta Innovates conduct its study before joining TransCanada Corp. as a pipe integrity corrosion specialist 6 weeks ago. Fully turbulent dilbit flow will prevent suspension of sediment and water, she said.
Bruce Dupuis, TransCanada’s liquid pipeline integrity manager, said the carrier ships multiple crude grades in 100,000 bbl minimum batches on its existing Keystone pipeline from Hardesty, Alta., to US refineries. “We sample every batch that comes into our system, and begin prerequisite testing when one doesn’t meet our specifications,” he said. “We’re also seeing the velocity products travel basically clean the line.”
But Anthony Swift, an attorney in the Natural Resources Defense Council’s international program, urged the committee to question assurances that dilbit is so similar to sour crudes that it won’t cause additional problems for pipelines. He also criticized PHMSA’s decision to emphasize corrosion, noting that poor planning and response were bigger culprits when crude oil leaked from a rupture in an Enbridge crude pipeline near Kalamazoo, Mich., in 2010.
Swift also questioned comparisons of dilbit to imported sour crudes that are partially refined at their ports of entry before entering pipelines; to California heavy crude because it travels a much shorter distance to specially configured refineries than dilbit moving through TransCanada’s proposed Keystone XL pipeline would; and to Canadian synthetic crudes produced since the 1960s that were upgraded near mine mouths.
“It would be better to compare dilbit to lighter crudes which historically have been shipped on US pipelines,” he said. “The argument that this is similar to conventional crudes doesn’t bear out. There are major hydrocarbon differences.”
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