Tuesday, August 21 , 2018, 9:21 pm | Fair 69º


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Industry, Lawmakers At Odds Over Need for Automatic Shut-Off Valves on Oil Pipelines

The Plains All American pipeline that ruptured May 19 off Refugio State Beach was not equipped with the devices

A portion of the ruptured pipeline owned by Plains All American Pipeline was excavated and replaced at the site of the May 19 oil spill off Refugio State Beach. At the work site, shown here June 1, the company is working with federal regulators to review past maintenance records before operations start again.
A portion of the ruptured pipeline owned by Plains All American Pipeline was excavated and replaced at the site of the May 19 oil spill off Refugio State Beach. At the work site, shown here June 1, the company is working with federal regulators to review past maintenance records before operations start again. (Giana Magnoli / Noozhawk photo)

The lack of automatic shut-off valves on pipelines has been a major point of debate in the wake of the Refugio State Beach oil spill, since these devices can be programmed to close as soon as a computer system detects a problem.

Plains All American Pipeline, which owns the crude oil pipeline that ruptured May 19, sending thousands of gallons of oil onto the shoreline, has aggressively defended its lack of automatic shut-off valves locally, saying they are not common and could actually increase the risk and magnitude of pipeline failures.

While some industry experts echo that view, regulators and others are equally adamant that the valves can minimize the environmental damage in the event of a pipeline failure.

“Most of our other big lines have that system on it, an automatic shutdown system on it,” said Kevin Drude, director of Santa Barbara County's Energy Division. “It’s really risk-based and environmental-concern-based in the county, and that’s what it’s always been.

"We look at it through the environmental review process.”

The pipeline that ruptured, Line 901, carries processed crude oil from the ExxonMobil and Venoco Inc. offshore oil production platforms to a Gaviota pump station.

Since the oil already has been processed, at ExxonMobil’s Las Flores Canyon and Venoco’s Ellwood Onshore Facility, it means all but 3 percent of the water has been taken out, along with dirt, rocks and sand and most natural gas liquids, Drude said.

It can take hundreds of pounds-per-square-inch of pressure to move this product, and it typically moves through pipelines at about 3 mph, said John Stoody, vice president of governmental and public relations for the Association of Oil Pipelines, of which Plains is a member.

Line 901 has the capacity to carry 150,000 barrels a day, but had been averaging 34,000 barrels per day recently, according to the county. Pipelines are designed to accommodate potential future growth, so this line has never delivered its full capacity. 

“This pipeline was critical in assuring residents of the county that tankering wouldn’t occur,” Drude noted. “Still, even with the upset, pipelines are the safest way to transport.”

Plains says it has automated shut-off procedures for its pump stations, but doesn’t have automatic shut-off valves on its pipelines in Santa Barbara County.

It has valves that are remotely controlled by operators in a Midland, Texas, control center using the Supervisory Control and Data Acquisition (SCADA) system, according to a company statement. These systems give operators real-time information such as pressure and flow rate. 

Santa Barbara County doesn’t have regulatory jurisdiction over Line 901’s operations or safety, since the company won a legal victory decades ago to keep federal oversight of its interstate carrier pipeline.

The Department of Transportation’s Pipeline and Hazardous Materials Safety Administration, PHMSA, is the federal regulatory agency for this pipeline and conducts investigations, inspections and enforcement actions.

County planning and development staff in the Energy Division manage the company’s local emergency response plan and oil spill plan (as does PHMSA), and environmental mitigation plans, which is “everything except that particular part where we manage the operations and safety of the pipeline,” Drude said.

County energy staff don’t regulate the pipeline operations so they don’t even know what specific safety system is used by Plains — they have to wait like everyone else for the PHMSA-ordered report with details about the system and how the spill occurred, Drude said.

Plains repeatedly has asserted that it’s uncommon to use an automatic shut-off valve system for crude oil because of the potential pressure build-up from the incompressible liquids.

“It is much safer for controllers who understand the hydraulics of a crude oil pipeline to shut it down using a planned sequence of steps than for a computer to automatically close a valve on oil that is traveling in a confined space under high pressure,” Plains communications analyst Karen Rugaard said in a statement.

The lack of shut-off valves has been questioned by legislators, including a letter to PHMSA from California Sens. Barbara Boxer and Dianne Feinstein, and Massachusetts Sen. Edward Markey.

The letter questions Plains’ response time to the spill and the lack of local responding agencies used in the cleanup effort, and asked for a report by June 11.

“We are also concerned that the ruptured pipeline reportedly did not have an automatic shut-off valve, which can swiftly react to a loss in pressure, and significantly decrease the volume of oil or gas released in a pipeline failure,” the senators wrote. “This technology has long been recommended by the National Transportation Safety Board, and we would like to ensure that it is fully deployed to mitigate disasters like this one.”

The use of automatic shut-off valves for crude oil lines, as opposed to manual or remote-controlled valves, is a point of debate in the industry because of the potential pressure buildup, according to Stoody. They’re “fairly rare” for interstate liquid pipelines, he said. “Operators think it’s a lower risk to, when they see a problem, remotely be able to control valves depending on the pressure.”

Tom Meisner of Pipeline Knowledge Development, a pipeline consultant and author of Oil and Gas Pipelines in Nontechnical Language, had a similar answer.

"They're not used very widely. The reason they're not used very widely is that one of the worst things that can happen on a liquid pipeline is a valve going closed when it shouldn't go closed,” he said. "How fast a valve closes is a bit of a function of how big around it is — closing them too fast can cause pressure waves in the pipeline, just like closing faucets in a house can cause water hammer." 

A general rule of thumb for valves closing is one inch per minute, he said.

The controversial Keystone XL Pipeline project, proposed to be a 36-inch pipeline transporting crude oil the 1,179 miles from Alaska to Nebraska, includes automatic shut-off valves in its design.

“Automated shut-off valves can be closed remotely on either side of a pipeline, isolating a damaged area within minutes,” project information states. “Keystone XL will be equipped with more automated shut-off valves placed at shorter intervals than any other oil pipeline in the U.S. They will be placed every 20 miles with extra valves where required, to protect water crossings and other areas of higher consequence.”

Several pipelines in Santa Barbara County have these valves installed and two recent crude oil pipeline projects added automatic shut-off systems voluntarily.

The Venoco Line 96 project, which connected its facilities to the Plains-owned Line 901 in 2012, and the recently approved ERG Operating Co. project on Foxen Canyon Road both proposed automatic shut-off systems as part of their project descriptions, Drude said.

The ERG project is a 2.9-mile crude oil pipeline to connect the Cantin Tank Battery on Foxen Canyon Road, near Sisquoc, to the Phillips 66 Line 300 Sisquoc Pipeline with two eight-inch pipes to replace daily trucking operations.

Operators purchase the SCADA systems and customize them for each pipeline, working with the manufacturers and engineers, Drude said.

“It’s not to say these systems are foolproof or would eliminate environmental impacts, because if there is a huge breach and there’s a valve here and upstream, anything within that piece of pipeline is going to drain out — but it prevents anything north or south from entering the line,” Drude said.

Investigators now know there was extensive corrosion on the outside of the crude oil pipeline that ruptured and caused spill. PHMSA released a report that detailed the findings, including a six-inch hole near the bottom of the pipe section and the surrounding area had corroded to a mere 1/16 of an inch.

The spilled oil has been estimated anywhere between 21,000 and 101,000 gallons. 

There are extra safety regulations for pipelines considered in “high consequence areas,” such as urban populated areas, river crossings or other areas of high environmental sensitivity, Stoody said. Those areas have higher inspection requirements and more rigorous maintenance schedules, he said.

The location of the spill out of Line 901 — a quarter-mile from the Pacific Ocean — has been designated as an area that could affect a high consequence area, according to PHMSA.

“PHMSA integrity management regulations require pipeline operators to conduct an assessment of their pipeline systems to determine which portions operate within high consequence areas,” spokesman Damon Hill said in an email. “These locations consists of areas of high or moderately populated areas, commercially navigable waterways, and unusually sensitive areas (containing drinking water, endangered species, etc.).”

For these areas, pipeline operators have to be proactive and focus on prevention and safety efforts to reduce risk to public safety and the environment, he said.

Plains conducts in-line inspections every three years, according to company officials, and these tests use “smart pigs,” cylindrical diagnostic tools that travel through the lines and can sense potential cracks or metal loss in the steel pipeline.

PHMSA's latest update on the investigation indicated that the May 5 in-line inspection test did show metal loss in several places, but not as badly as the 1/16-inch-thick pipe wall observed by investigators in the area of the rupture. 

Noozhawk news editor Giana Magnoli can be reached at .(JavaScript must be enabled to view this email address). Follow Noozhawk on Twitter: @noozhawk, @NoozhawkNews and @NoozhawkBiz. Connect with Noozhawk on Facebook.

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