Buried about a metre underground and stretching from the Northwest Territories to Quebec, the steel pipes are the arteries of the oil and gas industry – and some say of Canada itself.
Approximately 14.2 billion cubic feet of natural gas and 3.2 million barrels of crude oil already flow through pipelines every day, reaching power plants and refineries in Canada and the United States, as well as businesses and households.
Amid heated public debates, billions of dollars in pipeline projects and expansions hang in the balance, including the controversial Keystone XL oil line to the U.S. Midwest.
Many of the discussions pivot on the risks inherent in transporting natural gas and oil. The safety concerns are bolstered by groups hoping to delay oil sands development by reducing access to markets.
What exactly is being done to ensure pipelines don’t crack under all that pressure? An ever-evolving mix of technological improvements, maintenance techniques and human training, say experts.
While there have been recent high-profile incidents of pipeline spills, such as Alberta’s Red Deer River spill last June and the Kalamazoo River in Michigan disaster in 2010, overall frequency of breaks has been decreasing since the 1950s, says Ziad Saad, vice president of safety and sustainability with the Canadian Energy Pipeline Association.
“The reasoning is that diagnostic and maintenance techniques have been constantly improving and the overall level of monitoring, such as electronic remote monitoring, has been advancing,” Saad says. “And the body of knowledge in general in engineering and such with respect to where the risks associated with pipelines are have been improving.”
Members of CEPA operate about 72,000 kilometres of oil and 38,000 kilometres of natural gas pipelines in Canada. Improvements to safety operations have been incremental over the past 30 years, from how steel is manufactured to in-line inspection tools affectionately called smart pigs (pipeline inspection gauges).
Shaped somewhat like metal bottle cleaner or a millipede, smart pigs are pushed through a pipeline by whatever product is being transported in it. During the journey, the device collects information about the inside of the pipe, such as dents or thickness of a wall, through ultrasound technology and in-line GPS chips which pinpoint where the pipe might be compromised.
The data is then analysed by engineers and technicians to determine the condition of the pipe and respond accordingly. A thinner wall might indicate corrosion, a major threat – after third-party damage – to pipeline integrity.
Corrosion is managed in large part by coating the pipe, most commonly with fusion bonded epoxy that seals the steel surface. The steel itself has undergone several incarnations as manufacturing processes increased the strength of the metal allowing for higher pressure with thinner walls.
The coating is applied to the pipe under high temperatures, bonding with the steel to “cure” it. Coatings are also tailored to the product which will flow through it, from solvent-free epoxy for water transportation to chemical-resistant coatings used in pipes moving aviation fuel.
External corrosion of a pipe occurs as the metal reacts to soil or water in its environment, like iron collecting rust. Cathodic protection is one method of controlling external corrosion through the use of electric currents which draw corrosion to another piece of metal placed away from the pipeline. Coatings specific to the region often are applied externally in the field.
In addition to pipeline integrity, inspections and corrosion prevention, pipeline systems incorporate layers of monitoring devices which detect rate of flow and pressure to ensure operations are running smoothly, and to detect leaks.
The information is commonly collected by supervisory control and data acquisition (SCADA) systems and transmitted to control centers for evaluation by technicians. The SCADA system allows operators to remote control flows and pressure by starting and stopping pumps and compressors, and by opening and closing valves.
If a leak happens and pressure drops in the pipe, technicians can shut down the section of pipe with automated or manual block valves placed along the pipeline after sending out a team to inspect the site.
At least, that is what is supposed to happen.
In both the recent Plains Midstream spill into the Red Deer River last spring and the Enbridge disaster in Michigan, human error at the control centres was tagged as increasing the severity of the event. Technicians disregarded alarms of lower pressure for a variety of reasons, leading to delays shutting key valves and reducing the amount of oil released.
“You cannot divorce performance from human fallibility, that’s for sure,” Iaian Colquhoun, chief engineer at the National Energy Board said. “All you can do is make sure that the management system in place has the correct elements, that it is communicated to the human operators and that a management review is taking place of the performance, and the regulator is looking at the performance to minimize any accident on behalf of people’s actions.”
Canada’s pipeline watchdog recently was mandated by Parliament to increase inspections to 150 a year from 100, receiving $13.8-million to boost comprehensive audits of pipeline companies’ – each element, to ensure they are in place, communicated effectively and implemented.
“We have to find out for each of these incidents why it happened, when it happened, and probably more importantly if it is a symptom of a systemic deficiency,” noted Colquhoun.
In Alberta a review of the provincial safety regulations will be made public this summer as a result of the 2012 spill. The oil could have threatened drinking water for the province’s third largest city, Red Deer, if not contained in time.
Investigations of the break continue but initial observations suggest a section of pipe collapsed due to soil erosion and the force of a river swollen with spring rains. It was the third oil spill in Alberta in six weeks. One year earlier, the province suffered the largest oil spill since 1975 after 28,000 barrels of sour crude leaked out onto northern muskeg near Peace River.
In July 2012 the provincial government announced it would launch a technical safety review in the aftermath of the spill. The best safety feature is prevention through well-defined and followed integrity and maintenance programs, as well as well-trained and alert staff, say experts.
“There is no silver bullet that will, all of the sudden, make everything go away,” Saad said.
The number pipeline incidents in Alberta fell to 717 in 2011 from 974 in 2007, according to the latest data from the Energy Resources Conservation Board. The board recorded 523 leaks and 16 ruptures in 2011, “mainly caused by equipment failure, third-party damage, operator error and procedural or design.
Alberta has the highest concentration of pipeline in the country, some 400,000 kilometres of oil and gas pipelines, many built in the 1950s. Like an older car, older pipelines need more maintenance and are kept running through the use of up-dated diagnostics which can pinpoint areas at risk, recoating or replacing segments or simply lowering the pressure of the product flowing through it.
A report commissioned last year by the U.S. Pipeline and Hazardous Materials Safety Administration on leak detection found many internal monitoring systems did not detect smaller leaks, while external systems generated too many false alarms triggered by variants such as changes in temperature.
Small leaks pose a different risk because most devices aren’t sensitive enough to pick up the changes in pressure. Most are detected by people seeing pooled oil, such as the 1,500 barrel Norman Wells leak uncovered last winter which had been accumulating crude on the frozen tundra for an undetermined length of time.
Companies need to take into account risk assessments of older pipes, including the era it was built in, and demonstrate how they are managing it in their approach, Colquhoun said.
“A pipeline that is properly maintained, the possibility of failure is remote,” he said. “However, no matter how remote, we also require companies to have in place emergency responses in order to mitigate any damage that takes place, and to remediate any damage that takes place.”
Just one incident can have a lasting negative effect on the environment. Colquhoun noted. “And a lasting effect in the consciousness of people, too.”