New Technology Magazine

Delivering The Goods

For decades the Canadian pipeline industry toiled away in virtual anonymity, with only those involved in oil and gas production aware of the fact that there is no more reliable way to transport oil and gas and other energy to markets.

Then came Enbridge Inc.’s proposed $5.5 billion Northern Gateway pipeline to deliver 525,000 barrels per day to a deepwater port at Kitimat, on British Columbia’s northern coast, and TransCanada Corporation’s $7 billion, 700,000 barrel-per-day Keystone XL project to carry oilsands and other crude to the U.S. Gulf Coast, which became targets for environmentalists and others opposed to the expansion of the Canadian oilsands industry.

Opponents of the Gateway, Keystone and other large pipeline projects—including Kinder Morgan Energy Partners L.P.’s 300,000 barrel-per-day Trans Mountain pipeline to Vancouver, which the company wants to more than double in capacity—raise the spectre of disastrous spills causing serious environmental damage.

However, the facts belie these fears, suggests Ziad Saad, vice-president, safety and sustainability, for the Calgary-based Canadian Energy Pipeline Association (CEPA), which represents Enbridge, TransCanada, Kinder Morgan and most of the firms that operate larger-diameter, high-pressure transmission pipelines that move oil and gas over long distances.

“The curse of our industry is our success,” he says. “It’s an industry that has been taken for granted for many years because it always works.”

The industry, which has aggregate revenues of about $7 billion a year, spends over $1.6 billion a year on operations and maintenance and pays total corporate and property taxes in Canada of over $800 million yearly, has shown a steady record of safety improvement over the last few decades.

Although the industry has a total of more than 100,000 kilometres of pipelines in operation in Canada and the United States, “significant failure incidents” per 1,000 kilometres have been as low as zero in 2004 and 0.05 in 2009 (the last year for which statistics are available). “This safety performance exists while the pipeline sector continues to be, in many ways, the backbone of the Canadian economy,” Saad says.

Not everyone is so convinced. Organizations like the U.S.-based Natural Resources Defense Council (NRDC) suggest bitumen is more corrosive and, in a spill, separates from the lighter diluent added to make it flow, creating new hazards not encountered with conventional crude oil. Such fears prompted the United States in January to order a new study, conducted by the Pipeline and Hazardous Materials Safety Administration and to be completed by July 2013, to examine if pipelines carrying oilsands bitumen are at greater risk for spills and if any changes are needed to its regulations.

CORROSION COMPARISON

A review released last fall by Alberta Innovates – Technology Futures, which acts as an independent research arm of the Alberta government, suggests there is no increased corrosion risk. But it also noted there has been no focused peer reviewed study of the issue.

Entitled Comparison of the Corrosivity of Dilbit and Conventional Crude, the report, led by scientist John Zhou and written by Jenny Been, corrosion engineering, advanced materials, observes: “This review has indicated that the characteristics of dilbit are not unique and are comparable to conventional crude oil.”

The review compared three dilbit crudes (bitumen diluted with diluent, typically composed of about 25 per cent condensate) and one dilsynbit crude against conventional Alberta crudes. Two of the dilbits were obtained from cyclic steam stimulation and one from the steam assisted gravity drainage in situ extraction process, while the dilsynbit was obtained from oilsands mining operations, where it is either upgraded or blended with other crudes.

The report dismissed several of the concerns raised by bitumen pipeline critics. For example, while some of the bitumen had higher concentrations of naphthenic acids, which can be corrosive under refinery conditions and temperatures, “the acids are too stable to be corrosive under transmission pipeline temperatures.” The same goes for sulphur compounds, it states.

And whereas critics claim dilbit could be up to 70 times more viscous than conventional crude, creating higher temperatures due to friction (and therefore higher corrosion risk), Been states all the oilsands products were over 19 degrees API gravity and of “quality and viscosity that are accepted for transportation support operating temperatures within an acceptable range.” While conventional crude pipelines generally run at ambient temperatures, the maximum allowable temperature on the proposed Keystone line has been set at 70 Celsius with a normal operating temperature of 49 Celsius.

Been also found that an apples-to-apples comparison of corrosion leaks between Alberta and U.S. pipelines does not support critics’ claims that Alberta pipelines, which carry more bitumen, are up to 16 times more likely to spill. But she also noted that publicly available data do not separate the statistics for dilbit and conventional crude pipelines or for upstream gathering lines and long distance transmission pipelines. “It is recommended that better statistics be provided as an improved presentation of the integrity of the Alberta pipeline system and to facilitate continuous monitoring of the performance of dilbit pipelines,” the report states.

As for sand and sediment content, bitumen pipeline crudes “were comparable to or lower than the conventional crudes, except for a dilsynbit crude, which showed more than double the quantity of solids than most other crudes, but was still well below the limit set by regulatory agencies and industry. The solids size distribution is unknown as is the role of larger size solids in the formation of pipeline deposits. Erosion corrosion was found to be improbable and erosion, if present, is expected to be gradual and observed by regular mitigation practices,” the review states.

Specifically examining how a corrosive situation can occur, the report notes steel wet by oil does not corrode—for corrosion to occur, separation of a water phase from the oil is required. Transmission pipelines have a limitation on the basic sediment and water content entering the pipe of 0.5 volume per cent, which is too low to be a corrosion concern (generally over 10 per cent is needed), except where the precipitation and accumulation of water on the pipe wall can occur. Sludge deposits—mixtures of hydrocarbons, sand, clays, corrosion byproducts, biomass, salts and water—are one such instance.

“The water will contain chloride salts as well as bacteria, which now form a corrosive mix. The sludge chemistry can vary widely, where some sludges have a large percentage of waxy oil and exhibit low or no corrosion. Other sludges can contain more than 10 per cent water and large bacterial populations, which can contribute to underdeposit pitting corrosion.”

Underdeposit corrosion is not unique to dilbit lines. The report notes sludge deposition and the presence of bacterial populations, resulting in microbiologically influenced corrosion, shut down the Trans-Alaska pipeline last year as well as caused leaks in 2006, resulting in the shutdown of 57 oil wells at Alaska’s Prudhoe field.

“The most likely internal corrosion mechanism in dilbit pipelines consists of underdeposit corrosion as a result of sludge formation…. Microbiologically induced corrosion could play a dominant role in the corrosion process. Complex populations containing multiple types of bacteria are known to be present and support each other’s viability,” including sulfate-reducing bacteria, heterotrophic aerobic bacteria and acid-producing bacteria. But since these bacteria are most active between 10 and 40 Celsius, temperatures up to 70 Celsius in dilbit pipelines may actually reduce the corrosion rate underneath sludge deposits, if the mechanism is controlled by microbial action.

“Little is known about the controlling factors of corrosion underneath sludge deposits and it is recommended that research continue to improve our understanding of sludge formation, the resulting corrosion mechanism, the role of dilbit chemistry and solids, mitigation practices and frequencies, and preventive measures. Enbridge has been quite successful in mitigating underdeposit corrosion through a pigging and inhibition program. However, there are still many uncertainties regarding the effectiveness of each and the required frequency.”

The report recommends expansion of the current crude oil property database to include downstream qualities, for comparison with upstream qualities, as well as to include information on H2S concentration, asphaltene and water content, and viscosity. “The transparency offered by the information of crude oil quality databases on both the shipped and delivered product will be of tremendous assistance in communications between industry and the public. It will also be a valuable resource for the evaluation of sludge deposition and underdeposit corrosion during transportation.”

LESSONS FROM KALAMAZOO

In addition to concerns about possible higher rates of corrosion in dilbit pipelines, Anthony Swift, an energy policy analyst and attorney with NRDC, points to two issues not addressed by the Alberta Innovates review: leak detection and the unique characteristics of a bitumen pipeline spill compared to conventional pipelines.

While the review points to the similar characteristics of dilbit to heavy oil, Swift notes their actual composition is different in that conventional crudes “form a sort of bell curve where the majority of the hydrocarbons are in the 10- 14-carbon range. With diluted bitumen you have bitumen, which is [composed of] hydrocarbons with 30 carbons or more—heavier than water—mixed with natural gas liquid condensate with five-, six- or seven-carbon chains. The combination may make the average density of the mixture approximately what a heavy crude might be, but it’s what you might call a dumbbell crude where you have a very high concentration of very light hydrocarbons and a very high concentration of heavy hydrocarbons, but nothing in the middle. That’s why when the natural gas liquid condensate gasses off [in a spill], there is nothing to keep the diluted bitumen from just sinking into the river column.”

Swift points to the impact of the Enbridge spill in the Kalamazoo River watershed in Michigan in July 2010. Three million litres (19,500 barrels) of dilbit from the Cold Lake oilsands region was released when the 30-inch pipeline ruptured. “We saw with the Kalamazoo spill that the diluted bitumen did behave differently. What occurred was the very light stuff gassed off rapidly and that presented temporary but high level of risk to residents living nearby, and the heavy bitumen sank into the water column, which basically defeated the conventional spill response mechanisms, which rely on containing the crude on the surface and then skimming it off. Once it gets into the river column, it becomes much more difficult to contain and remove.”

The U.S. Environmental Protection Agency (EPA) had originally mandated the full cleanup to be completed within two months, he says. “And here we are about 20 months after the spill and cleanup is continuing, and more importantly, the river is still closed to the public. The EPA has said they are having to write the book on dealing with these sorts of spills as they go, so they haven’t been able to give a firm assessment of when cleanup would end. They’ve said that, in all likelihood, they will be leaving submerged oil in the riverbed and lake bottoms in certain areas because it will be too environmentally damaging to remove it.”

He suggests the cleanup has cost 18 times per barrel that of the average conventional crude oil spill over the last 10 years. “The current cost is estimated at about $725 million, and that amounts to about $36,000 a barrel in cleanup costs, whereas if you average all the other conventional crude oil spills in the U.S., the property damage and spill response costs to clean those up, it comes down to less than $2,000 a barrel.”

Detecting spills is made more difficult on dilbit lines because varying operating conditions generate more “noise,” according to the NRDC. For example, pressure changes in a bitumen pipeline can result in gas bubbles, or column separation, which can send faulty signals to leak detection systems. And because the typical response to column separation is to pump more oil, it can exacerbate a leak. “During the Kalamazoo River spill, the Enbridge pipeline gushed for more than 12 hours before the pipeline was finally shut down, and initial investigation indicates that the pipeline’s monitoring data were interpreted to indicate a column separation rather than a leak,” the NRDC states in a co-authored report, Tar Sands Pipelines Safety Risks.

The report recommends that “until appropriate regulations are in place, oil pipeline companies currently shipping diluted bitumen must use technology that effectively addresses the additional corrosion caused by diluted bitumen to ensure that the smallest leaks can be detected in the shortest time possible and that companies have sufficient spill response assets in place to contain a diluted bitumen spill.”

EVIDENCE LACKING

Pipeline companies, however, maintain there is no evidence to date that piping bitumen is any more likely to lead to spills. Art Meyer, senior vice-president of pipeline integrity for Enbridge, refutes claims by environmental groups that bitumen from the oilsands—the commodity almost totally responsible for the billions of dollars of expansions of the systems of his firm, TransCanada and others in the industry—is inherently more corrosive than conventional sweet crude. “We have seen no evidence that moving bitumen is any more corrosive than moving any other oil,” he says.

Enbridge, which has been transporting crude from oilsands production since 1979, notes a complete metal loss inspection of its 13-year-old Athabasca System linking the Athabasca and the Cold Lake oilsands deposits with the transportation hub at Hardisty, Alta., in 2009 “revealed no increased risk or incidence of internal corrosion.”

Enbridge has 24,613 kilometres of pipelines that carry that diluted bitumen and it operates 150,000 kilometres of pipelines overall. “We operate the longest crude oil pipeline in the world,” Meyer says. He says Enbridge takes management of its network of pipelines very seriously. “We’re probably the largest users of internal inspection tools in North America.”

It conducts ultrasonic sensor-type inspections by pigs (internal inspection tools) about every three to five years, with the emphasis usually on searching for the impacts of corrosion on pipelines, which can include metal loss. “If we find an issue, we dispatch the mainline projects group,” he says. “It may involve recoating or applying a sleeve over the pipe.”

Sometimes whole sections of pipe need to be replaced. For instance, it recently replaced about 100 kilometres of pipe in the U.S. Midwest, at a cost of $300 million.

The sheer volume of liquids it moves through its pipeline system in itself provides a level of protection, Meyer says. “We don’t see a lot of internal corrosion in our system because of the amount of fluids we’re moving.”

It uses corrosion inhibitors such as biocides on slower moving, smaller volume lines, usually applying them about two times a year. “We spend a few hundred million dollars a year on these programs,” he says. “Last year we completed 138 different inspections in Canada and the U.S. and we remediated about 1,800 different sites.”

The company, which employs about 7,000 people overall worldwide, has about 140 crews conducting pipeline remediation work at any given time, with about 1,000 people working in that capacity, many on a contract basis.

The company claims that the vast majority of the spills it experiences are small (less than 10 barrels each), occur at Enbridge facilities such as pump stations and terminals, are completely contained within those facilities and are discovered shortly after they occur.

In 2010, when the company delivered an average of 2.2 million barrels a day along its mainline, there were 80 reportable spills with a total spill volume of 34,122 barrels. It reported that 69 of those spills represented a volume of less than 10 barrels, with 61 of those occurring at Enbridge facilities.

CEPA also notes there is no evidence dilbit pipelines are subject to potentially more corrosion, ruptures or spills than conventional pipelines. Pipeline integrity analysis on its member companies’ bitumen pipelines going back three decades “show no increased risk or incidence of internal corrosion compared to conventional oil pipeline systems,” CEPA states. The association points to Alberta Energy Resources Conservation Board’s assertion, based on comprehensive statistics on pipeline performance since 1975, that: “There is no indication that the types of pipelines transporting blended crude bitumen, crude oil or synthetic crude oil have an increased risk of internal corrosion issues.”

National Call System Stymied

Although the Canadian pipeline industry spends hundreds of millions of dollars a year on sophisticated monitoring technologies that can detect and fight corrosion and cracking (the two biggest causes of leaks and ruptures), much of the damage done to pipelines is caused by landscaping and other firms using equipment that pokes unwanted holes in those lines.

And the Calgary-based Canadian Energy Pipeline Association (CEPA)—which represents companies such as Enbridge Pipelines Inc., TransCanada PipeLines Ltd. and other firms that own larger-diameter, higher-pressure transmission pipelines that move oil and natural gas over larger distances—thought it had the perfect solution to deal with what the industry calls “third-party damage.”

That was until the Canadian Radiotelevision and Telecommunications Commission (CRTC), the country’s telecommunications system regulator, ruled in the week of March 19-23 against a request by CEPA, the Canadian Gas Association and others that would force anyone planning to dig into areas that could be pipeline-prone to use a new regulated, national one-call system before they excavate.

The CRTC ruled against the request even though there are at least 200 incidents a year in which transmission pipelines in Canada are damaged by firms excavating for cable television, telecommunications and sewer and water services, and there are thousands every year involving smaller-diameter natural gasservice pipelines.

“The U.S. has a national 811 number and there is tangible evidence that it has substantially reduced the number of disturbances,” said Ziad Saad, vice-president of safety and sustainability for CEPA.

The U.S. initiative includes a national mandatory system requiring all companies that do excavation to register with government agencies. Finally, some of the states prosecute companies that damage pipelines despite these precautions.

Saad said CEPA wanted a similar system in Canada, starting with the national 811 number. It would have sought provincial government support for a registration system and for legal penalties for firms doing damage to pipelines.

However, it wasn’t able to get beyond first base, since the CRTC rules against the use of an 811 number, saying it wasn’t convinced of the benefits of allowing it. That number is assigned now for non-emergency medical calls in Canada (although it’s only used in British Columbia, Quebec, Nova Scotia and Yukon).

Saad said the CRTC would have supported the use of a 1-800 number, but CEPA and others wanting a three-digit number believe that is the best way to raise the profile of the issue.

He said third-party-caused damage is the second greatest source of pipeline incidents in the United States, while it’s the third biggest cause in Canada, following corrosion and cracking. This likely reflects the more densely populated nature of much of the United States.

In both the United States and Canada there are organizations called the Common Ground Alliance. The U.S. group was able to lobby successfully for the one-call system there, which was put into place in 2005.

CEPA and its allies ran into opposition from British Columbia and some of the other areas in Canada now making regular use of the 811 number, which didn’t help their cause.

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