By William M. Glenn
By William M. Glenn
Health & Safety
On the evening of July 20, operators in the Husky Energy control room detected certain “pressure anomalies” in sections of one of its oil pipelines spanning the North Saskatchewan River. Although such monitoring “blips” are common during start-up operations, inspection crews were dispatched to the site as a precaution, but found no evidence of a breach, according to the July 26 incident-response report posted on the company’s website.
After further analysis, Husky initiated its “safe shutdown” procedures at about 6:00 a.m. the following morning. The valves on both sides of the river closed automatically as part of the operation, but the company was too late. Between 200 and 250 cubic metres of heavy oil and diluent had already spilled into the river.
That has not been the only bad news on the pipeline front in recent months. In July, 380,000 litres of light petroleum condensate leaked from a pipeline operated by ConocoPhillips Canada near its Resthaven gas plant in northwestern Alberta. In March 2015, an estimated 17,000 barrels of the condensate used to dilute heavy oil escaped into the muskeg south of Peace River, Alberta, from a three-inch pipeline operated by the Murphy Oil Corporation. And in July 2015, five million litres of a bitumen-water-sand mixture oozed across the tundra from a Nexen Energy pipeline south of Fort McMurray.
These incidents might convey the impression that Canadian pipelines have been failing at epidemic rates. But recent statistics compiled by the Alberta Energy Regulator (AER) indicate that the total number of pipeline incidents — ranging from pinhole-sized leaks to major ruptures and spills — decreased by approximately 37 per cent from 2006 to 2015. Over the same time, the total length of operational pipeline in the province increased by 20 per cent. According to the AER’s Report 2013B: Pipeline Performance in Alberta 1990-2013, “very large pipeline releases are relatively few.”
The improvement is largely due “to more stringent [regulatory] requirements, an increased focus on integrity issues, industry education, improvements in inspection programs and a greater focus on pipeline safety within the energy industry,” says Monica Hermary, public-affairs advisor for the AER in Calgary. Amendments to the province’s Pipeline Regulation, passed in 2005, require operators to undertake greater pipeline surveillance and leak-detection action.
But that does not mean everything is under control. “Detecting leaks is an ongoing challenge for pipeline operators, and the industry needs to do more,” Hermary says. In an operational advisory bulletin released in July, the AER said operators must increase their focus on systems monitoring and operator training.
Since its inception in June 2013, the AER has investigated 23 pipeline releases. According to those investigations, “improper leak detection” was cited as a significant contributing factor in eight of them. Most of the lines that failed were upstream lines transporting effluents and salty process water produced by oil wells.
The investigators also found that the company personnel responsible for leak detection either were not sufficiently trained or simply failed to recognize that a leak was occurring. On average, it took 48 days to respond to and isolate the pipelines for these eight releases, the AER bulletin notes.
The AER requires an integrated approach to leak detection that includes direct visual assessments — patrolling pipeline right-of-ways for evidence of leakage or other issues that could affect the integrity of the pipeline — as well as in-service pressure testing, mass-balance monitoring and instrument-based data collection. In addition, all personnel must be properly trained in leak detection and their competency evaluated and retested on a regular, ongoing basis.
For its part, the AER conducts inspections to ensure that operators are in compliance and have proper leak-detection strategies and preventive pipeline-maintenance programs in place. “Our inspections also focus on identifying high-risk activities, such as water crossings and inactive pipelines, to prevent pipeline incidents from occurring,” Hermary adds.
Dollars and sense
“While it is hard to put an exact number on it, perhaps five per cent of pipelines could be considered ‘high-risk’ and prone to failure,” says corrosion and materials specialist Daryl Foley, president of Group 10 Engineering in Calgary. Another 20 to 25 per cent are considered lower-risk, but a leak, spill or rupture could cause significant environmental repercussions. His firm helps oil and gas companies assess the hazards posed by their pipelines, tanks, pressurized equipment and other physical assets.
Not all pipelines present the same risks. “First of all, you need to understand the difference between the big pipelines operated by the oil and gas transmission companies and the thousands of smaller-diameter lines that the upstream producers use to transport their products, process materials and wastes back and forth from wells to field-processing facilities,” Foley explains. Those upstream companies are focused on exploration and production; their pipelines are just one of the many assets they manage. And that upstream infrastructure is aging.
“Some of it was built back in the 1950s,” he says, “while much is equipped with less than state-of-the-art protection systems. We know there are going to be leaks and there are going to be failures somewhere.”
In a tight economy, upstream operators have to prioritize high-risk situations — the pipeline leak and rupture scenarios that pose the greatest environmental and health threats — to ensure that they are getting the biggest impact for every dollar in their integrity-management budgets.
“It can cost between $60,000 and $100,000 to inspect and assess each small, upstream pipeline on a well-by-well basis,” Foley says. On the other hand, it costs about $150,000 to find and repair the average small leak and clean up any spilled product. “It is not surprising, then, that many operators gamble,” he suggests.
One of his clients manages some 27,000 lines, many of which are just two or three inches in diameter and each averaging just a kilometre to a kilometre-and-a-half in length. “They can only afford, economically, to inspect a fraction of their pipelines and would quickly go out of business if they tried to do it all,” Foley adds.
Bull’s eye on high risks
Risk assessment is a multi-step process that can show companies where to allocate their resources to prevent leaks most effectively. First, the inherent risks posed by the equipment, as well as the volumes and commodities that a particular pipeline carries, need to be identified. Sour gas, crude oil, salty or fresh water, multi-phase oilfield wastes and refined products each pose their own risks.
That is followed by mapping the location of the pipeline, local topography, water crossings, various land uses and population centres along the route, followed by an assessment of existing safeguards, the effectiveness of the operator’s integrity-management program and any upgrades that can be made. Finally, consider the full range of environmental and health consequences that may arise if something goes wrong.
To date, one of the “biggest voids” has been identifying which of the thousands of pipeline water crossings are the most vulnerable, Foley says. “We needed a leveraged system to do a ‘first pass’ and identify significant sites for a deep assessment.”
To fill the gap, Group 10 has developed a pipeline water-crossing classification tool to help operators “laser-focus” their resources on high-impact areas through ranking various risk factors, including the width and flow of the watercourse, sensitive fish and wildlife habitats, recreational or commercial water use and withdrawals for drinking water and human consumption.
When it comes to preventing leaks at significant water crossings or in densely populated areas, “there should be zero tolerance for high-impact failures,” Foley stresses. “Whether you are operating a big transmission pipeline or one of thousands of smaller upstream lines, you must know the condition of the pipes running through those areas with 100 per cent certainty.”
Despite some recent high-profile incidents, Foley has confidence in the ability of big transmission companies to prevent leaks, detect problems and respond quickly to serious releases. “Their pipelines are their primary asset. They have the staff, the experience and the focus needed to monitor, inspect and maintain them. If a pipeline was going through my backyard, I would pick a transmission pipeline company hands down over an upstream operator.”
The numbers seem to back him up. “For more than a decade, our industry has seen a steady decline in the number of natural gas and liquids pipeline incidents per 1,000 kilometres,” says Patrick Smyth, vice president of safety and engineering for the Calgary-based Canadian Energy Pipeline Association (CEPA), which represents all the major gas and oil transmission-line companies in Canada.
“Maintenance and monitoring throughout the entire life cycle of a pipeline is a top priority for our industry,” Smyth says, noting that companies have automatic leak-detection alarm systems, automatic shut-off devices and devices that continuously monitor the internal condition of the pipe. The association and its members are continually seeking out opportunities to improve the sensitivity of leak-detection technology, he adds.
In 2015, CEPA members posted a 99.999 per cent safety record. “This record can be attributed to the fact that CEPA member companies are collaborating on a national strategy to develop best-in-class pipeline leak detection technologies,” Smyth says. Integrity First® is an industry-led program established by CEPA to improve safety and environmental performance and to strengthen the pipeline industry’s engagement and communications.
Not if, but when
But not everyone agrees that big transmission pipeline companies are doing enough.
“The question is not if a pipeline will spill, but when,” says Patrick DeRochie, the climate and energy program manager for Environmental Defence in Toronto. The non-governmental organization is particularly concerned about the risks of long-term contamination that the transportation of oil and gas by pipeline poses to drinking-water systems and terrestrial and aquatic ecosystems. “When a pipeline spills, only a portion of the oil is ever actually recovered,” DeRochie says.
Environmental Defence opposes TransCanada’s construction of the Energy East Pipeline, which will transport about 1.1 million barrels of oil a day from Alberta and Saskatchewan to refineries in Eastern Canada and a marine terminal in New Brunswick. While the industry spends millions every year trying to improve pipeline integrity and leak detection, “there are limits to what can be done,” DeRochie says. “Even the most rigorous combination of remote leak detection, ground and aerial patrols and external sensors is not foolproof.”
The environmental risks are compounded by the potential threats to human health following a major spill. “Bitumen must be diluted with highly toxic condensate chemicals to create dilbit,” DeRochie notes. If spilled, this diluent separates from the bitumen and evaporates to form a toxic cloud of benzene, toluene and other carcinogenic compounds that can create an acute health risk for communities and first responders in the area. The remaining bitumen, unlike conventional crude oil, will sink and coat river and lake bottoms, complicating cleanup efforts.
The group also disagrees with much of the reassuring safety data that the industry has compiled. “Oil and gas companies continue to tell us that pipelines are safe and oil spills are rare, but the evidence suggests otherwise,” DeRochie argues. “There were 69 pipeline spills in Canada in 2015 — that is more than one per week,” he adds, citing numbers from the statistical summary of pipeline occurrences in 2015 by the Transportation Safety Board of Canada. “These are alarming numbers coming from an industry trying to reassure the public about pipeline safety.”
Environment Defence claims that the leak-detection systems are inadequate. According to statistics compiled by the Pipeline and Hazardous Materials Safety Administration in the United States, remote sensors detected only five per cent of pipeline spills.
“In last June’s heavy oil spill in the North Saskatchewan River, Husky Energy took a staggering 14 hours after discovering the leak to even notify the provincial government,” DeRochie says. “This is unacceptable, especially to the 70,000 residents whose drinking water was disrupted.”
From inside out
Preventing incidents before they occur is a critical component of Enbridge’s ongoing commitment to safety, says Len LeBlanc, director of integrity systems for Enbridge Inc. in Edmonton. The company operates the world’s longest crude oil and liquids transportation network, as well as Canada’s largest natural-gas distribution system. “As part of our multi-layered prevention strategy, we regularly use in-line inspection tools that allow us to monitor the health of our pipeline systems from the inside out,” he explains.
Prevention activities include anti-corrosion coatings, cathodic protection (the application of a low-level electrical current to stop external corrosion), the interior cleaning of pipes, aerial and ground patrols and preventive-maintenance inspections. The potential threats that, over time, can deteriorate a pipe fall into one or more of the following categories:
— metal loss or corrosion;
— pipe deformation, such as denting caused by a third-party digging near a pipeline;
— cracking stemming from steel manufacturing or forming processes;
— cracking related to exposure to natural environments; and/or
— incorrect operations.
According to the AER, the majority of pipeline incidents are integrity-related, with internal corrosion ranked as the leading cause of some 36 per cent of incidents in 2015, followed by external corrosion at 13 per cent. This is not surprising, as the vast majority of pipelines — 90 per cent — are made of steel. Other causes of pipeline incidents include pipeline valve or fitting failures (13 per cent) and external damage (ten per cent).
In the field of spill prevention and detection, TransCanada is developing and testing a number of new technologies, including “smart pigs” to inspect for anomalies, corrosion-resistant coatings, automated ultrasonic testing and electromagnetic acoustic transduction to detect hairline cracks in natural-gas pipelines.
According to Mark Cooper, senior lead of media relations with TransCanada, the company has also pioneered the use of high-strength steel, such as the X-100 grade, for large-diameter steel pipelines, which can transport greater volumes of natural gas or liquids at increased pressures, while reducing transportation costs.
“We are pushing the envelope on automated welding systems,” which can produce more consistent, high-quality welds, particularly in harsh conditions and short construction seasons, he adds.
TransCanada and Enbridge have also teamed up to evaluate some “cutting-edge technologies” for external leak detection at the C-FER research facility in Edmonton. These include vapour-sensing tubes, fibre-optic distributed temperature-sensing systems, hydrocarbon sensing-cables and fibre-optic distributed acoustic sensing systems.
Technology aside, protecting people in the event of a spill is a top priority at Enbridge, according to Len LeBlanc, director of integrity systems for Enbridge Inc. in Edmonton. The company provides free training to first responders along its pipelines as part of the Emergency Responder Education program and corresponds regularly with local communities as part of the Public Awareness Program.
“Our goal is to prevent spills from occurring in the first place,” says LeBlanc, but if a concern is identified, the pipeline is shut down, local valves are closed and trained responders equipped with the appropriate personal protective equipment will respond to assess the specific situation. The company also undertakes air monitoring at the spill site and surrounding areas and works with local emergency services if public evacuations are recommended.
On the regulatory front, the National Energy Board and the Canadian Energy Pipeline Association established a Joint Committee on Issues of Mutual Interest for Federally Regulated Pipelines in April to advance the “safety culture across the industry,” according to Darin Barter, communications officer with the National Energy Board in Calgary.
According to the Committee’s terms of reference, members will identify regulatory process efficiency and optimization opportunities that span service standards, improvements in regulatory burden and clarity, pipeline performance measures and targets and application processes.
“The main cause of external or contact damage is a lack of due diligence carried out to identify buried pipelines in an area before digging or other ground disturbance occurs,” Hermary says.
The AER is currently working with the industry on a “more robust” data-collection system for pipeline incidents to facilitate better identification of trends and areas of higher susceptibility. “Operators must understand the risks inherent to their pipeline system and factor in the monitoring and integrity management needed to control the risks,” Hermary adds.
Factors behind failures
With more than 40 years’ experience in troubleshooting problems and investigating mishaps in the pipeline business, Richard Kuprewicz, president of Accufacts Inc. in Redmond, Washington, knows that a dedicated safety-culture approach can work. “Integrity management is not all that complicated. So why have we seen many failures over the last decade?” he asks.
The short answer is that too many organizations look for the loopholes in a safety-management system in a misguided attempt to cut costs. “I have seen good times when the sector was flush with money, and I have seen bad times when people start to cut corners,” Kuprewicz says. “That is when you get into trouble.”
And sometimes, a leak-detection system may not be as effective as one thinks it is. “Everybody is looking for the ‘magic bullet’ that will solve all your pipeline-release problems, but nobody has come up with it yet,” Kuprewicz says. “There is no easy answer because it is not a one-size-fits-all kind of problem.”
A line carrying oilfield wastes or salty water presents very different challenges than one carrying crude oil or sour gas. And lines designed for transporting refined products, like gas or oil, each come with their own sets of risks. But AER data on pipeline performance in Alberta from 1990 to 2013 show that approximately 30 per cent of the lines in that province are more than 25 years old. Does the age of Canada’s pipelines raise additional concerns?
The National Energy Board, the federal agency that oversees pipelines crossing international or provincial borders, has compiled a database on the root causes and circumstances surrounding the 39 major pipeline ruptures that have taken place in Canada since 1992. Of these, only two occurred in lines or facilities built in the last 30 years. Eight occurred in lines constructed in the 1950s, 15 in lines built in the 1960s, 10 in lines from the early 1970s and four incidents in undated lines or structures.
While the statistics may indicate systemic problems, experts say they can be overcome. “Generally speaking, pipeline steel doesn’t wear out,” Kuprewicz says.
Quality-control problems dating back to the year of manufacture can introduce some vintage threats, but one can stay ahead of them with a proactive inspection and maintenance program before they fail. Unless there is a manufacturing imperfection or construction anomaly, damage or failure to protect it against corrosion, “most pipelines should last forever,” he adds.
The leak-detection provisions promulgated in Canada are based, in large part, on the premise that one can spot and prevent leaks through a mass-balancing process. On the macro scale, discrepancies between the amount of product flowing into and out of sections of a pipeline could indicate losses along the route. Mass-balancing techniques can theoretically be used to pinpoint those leaks.
Both federal and provincial regulators — in legislation promulgated by the NEB federally and by British Columbia, Alberta, Saskatchewan, Manitoba, Ontario, Quebec, New Brunswick and Nova Scotia provincially — have adopted CSA Z662, the Safety Standards for Oil & Gas Pipeline Systems, which gives it the force of law.
The standard covers the design, construction, operation and maintenance of pipeline systems that convey liquid hydrocarbons, natural gas, oilfield water and steam and the carbon dioxide used in enhanced recovery schemes. That includes not only the pipelines, but all pumping stations, compressors, pressure-regulating stations, tank and storage vessels, monitoring stations and terminals spread along the route. As a result, each of those regulatory regimes makes mass balancing a mandatory component of a release-prevention program.
Sensors located at regular intervals along the line monitor changes in temperature, pressure, density, flow rates and other parameters. All that data is fed back, in real time, into a sophisticated computer program that isolates aberrant computational signatures that could indicate a loss — anything from a slow leak to a major rupture — at a specific location in the pipeline. If such a release is detected, the operator can shut down the system.
“Good luck with that,” says Kuprewicz, who suggests that a regulation that relies on mass balancing to spot pipeline releases is “the most dangerous of all regulations because it confers the mere illusion of safety.”
As a large transmission pipeline can carry millions of tonnes of hydrocarbons, it does not really mass-balance. “When you are dealing with a compressible liquid, relatively small changes in inventory can mask significant pressure changes, making it hard to detect even a big hole. Relying on mass balancing can increase errors by whole additional orders of magnitude,” Kuprewicz says.
He also stresses that many in the sector misunderstand the technical limitations of mass-balancing technology. “Again and again, we see ruptures continuing undetected even under low pressures, nowhere near the maximum operating pressure allowed pipelines.”
Ahead of the curve
“The industry is under severe scrutiny at the moment,” says Paul van Eeden, executive chairman of Edmonton-based Synodon Inc., a remote sensing company that helps energy firms improve their operational safety and reduce their environmental footprint. The company’s remote alkane-sensing technology, realSens™, measures ethane emissions to locate hydrocarbon leaks along pipelines and around other oil and gas infrastructure.
“In Canada, the oil and gas sector is undergoing some intensive self-evaluation to determine the appropriate level of leak detection,” van Eeden says. “There are two kinds of companies: there are those that say aerial-based remote sensing is not required by the regulators, so I am not doing it, and there are those who recognize that this is a good technology that goes beyond the minimum requirements and allows us to be proactive.”
In addition to continuously monitoring pipeline conditions, companies must also conduct regular visual inspections as part of their integrated management systems. Small planes may overfly routes or crews tramp alongside pipelines, typically looking for pools of leaking product or patches of dead and dying vegetation. Right-of-way crews may also be equipped with handheld monitors. This is an expensive, time-consuming process.
“How many field crews will you need to inspect 1,000 kilometres of pipeline, and how long to cover the entire distance?” van Eeden asks. The logistics for mobilizing such an operation are staggering, and they can detect only a leak that has already existed long enough to cause damage. “We can do it faster, cheaper and more efficiently,” he claims.
“By monitoring ethane plumes along a 200-hundred-foot-wide corridor, we can detect very small leaks, as small as ten barrels a day, and track them back to within two metres of their point of origin,” he says. “And because we can find leaks early, the operator can send out a repair crew to stop the release and mitigate the environmental damage.”
Good people, bad decisions
Despite the limitations of the current spill-detection technology, most pipeline ruptures remain a people problem. “Whenever there is a serious accident, almost invariably, you will find one group of experts in an organization hasn’t been talking to another group of experts,” Kuprewicz says. A lack of coordination can negate all the checks and balances built into the system, and an operator can quickly lose control of a pipeline.
He also cites trimming back integrity management and spill-detection budgets as probably the worst decision that a pipeline operator can make.
“Technology can be a wonderful thing,” Kuprewicz says, “but never underestimate the odds that a group of very smart people will make a stupid decision, especially if given the incentive to not do the right thing.”
William M. Glenn is a writer in Toronto.