The new technologies and drilling methods behind the current U.S. shale gas boom may mean cheap natural gas for the foreseeable future. But they are also driving higher profits and expanded development in Canada’s controversial oil sands, often labeled “dirty oil” because of the huge volumes of natural gas required to extract and refine the fossil fuel.
There is no question oil sands activity is picking up again, says Andrew Potter, a petroleum analyst at CIBC World Markets. “Whereas 12 to 24 months ago, oil sands would have been showing rates of return in the 10 to 15 percent range with $85 a barrel (oil), we now see rates of return in the 15 to 25 percent range.”
Shale gas is a big part of that story, given the role that natural gas plays in oil sands production. Canada has the world’s largest proven reserves of bitumen—the tar-like form of petroleum found in oil sands—but turning it into light crude doesn’t come easy. Some form of heating is typically required to separate the bitumen from the sands.
With surface mining, which accounts for rough half of all current projects, bitumen is removed from the sand by washing the mixture with hot water heated with natural gas. Another approach that’s growing in popularity is in situ extraction. This involves a method such as steam-assisted gravity drainage, whereby a horizontal well is drilled into the ground and steam is injected inside, reducing the viscosity of the bitumen and causing it to flow upward through a separate vertical well. Steam-assisted gravity drainage has a much lower visual impact on the surrounding environment.
Natural gas is the largest single input cost for in situ projects. When natural gas prices are high, it can represent more than half of an oil sand project’s operating costs. About 1,000 cubic feet of natural gas is burned for every barrel of bitumen produced from an in situ project. After that, another 400 cubic feet is put through a steam methane reforming process to produce hydrogen, which is required to upgrade the bitumen into a kind of synthetic crude that shares the same characteristics of conventional light oil.
“In situ projects are highly dependent on the price of natural gas,” says Marc Huot, a technical analyst at the Pembina Institute, an energy think tank in Alberta, Canada. “For every single unit of energy that goes in, most of it in the form of natural gas, you get only five units of energy out.” Conventional oil, by comparison, gives an energy return of more than 10 to 1, according to the U.S. Department of Energy. For this reason, the carbon footprint of oil sand-based petroleum products is much larger compared to conventional oil.
But in the absence of a meaningful price on carbon, a slowdown of development is unlikely under current economic conditions. Three years ago, at the height of the last oil sands boom, when the price of oil momentarily peaked at $147 per barrel, natural gas prices on the spot market were higher than $11 per million British thermal units. Today, oil is at about $108 per barrel and holding, and the flood of shale gas in the market is keeping natural gas spot prices below $4.50 per million BTU. “That’s become a big driver of development,” says Greg Stringham, vice president of oil sands and markets at the Canadian Association of Petroleum Producers (CIBC).
It also comes at a time when U.S. demand for Canadian oil (already 23 percent of imports) is growing. President Obama’s speech on energy policy last week emphasized the importance of imports from Canada and other stable neighbors as the U.S. tries to wean itself from Middle East oil and imports from other volatile jurisdictions. The Keystone XL project, a proposed $7 billion pipeline that would deliver diluted bitumen from Alberta to an upgrader facility in Texas, is waiting for State Department approval, although it has faced stiff pushback from environmental and community groups.
CIBC’s Andrew Potter estimates that oil sands production will jump from 1.5 million barrels a day in 2010 to five million barrels by 2020. That represents about 37 megatons of greenhouse gases, according to the Pembina Institute. “By 2020, that means a near tripling of emissions,” says Potter.
The fact that the shale gas boom is feeding an oil-sands boom worsens the environmental picture. New techniques for the hydraulic fracturing of shale formations may unlock new sources of natural gas, but it also involves injecting a toxic cocktail of chemicals that can contaminate groundwater. Also, new research from the U.S. Environmental Protection Agency has found that the amount of methane (a potent greenhouse gas) from shale projects that can escape into the atmosphere is 9,000 times higher than previously thought.
Stringham says the oil sands industry knows it must do more to reduce emissions, and that means coming up with methods of bitumen extraction that use less natural gas. Many developers are experimenting with using solvents to separate the bitumen and sand, an approach that reduces the amount of natural gas used to produce steam.
Another method is called in situ combustion, which involves setting fire to some of the bitumen underground to warm up the bitumen surrounding it. Some developers are also heating the bitumen by running electricity through electrodes that are inserted through shallow reservoirs. The industry has even begun investigating the use of small modular nuclear reactors to provide electricity, steam, and hydrogen, but the business case is weak while natural gas prices are so low. “The big driver is not there anymore because of the surplus across North America of shale gas,” adds Stringham.