1. CIBC’s Andrew Potter estimates that Canada’s oil sands production will jump from 1.5 million barrels a day in 2010 to five million barrels by 2020. This is being caused by high oil prices in combination with low natural gas prices.
“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.
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).
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
2. Before the water-flooding, Crescent Point believed it could extract 19 per cent of the oil in place in the Bakken, a major new play that contains an estimated 4.6 billion barrels. With water, it expects to boost that to 31 per cent. That’s a potential gain of roughly 500 million barrels in the Bakken alone – and water-flooding also has the advantage of bringing oil to surface much faster.
“In six years, we’re getting out the oil that we would have got out in 50 years,” Mr. Smith said. Crescent Point ended 2010 with 11 water injection wells. It plans to increase that number to 36 in 2011, although that remains far from the 700 it has drilled in the Bakken.
But the true impact of the technology lies in its reach. The Bakken is only one of a series of prolific tight oil plays where it could work, including the Lower Shaunovan, which contains 4.3 billion barrels; the Viking, which holds six billion; the Swan Hills trend, which has roughly seven billion; and the Cardium, which contains 10 billion barrels.
Others are testing the technology, too, including Legacy Oil + Gas Inc., which has one pilot under way and another coming this year. Privately held Manitoba company Tundra Oil & Gas Ltd. has also piloted water-floods in a Bakken-like play in 2007; it has seen recovery factors leap forward much like Crescent Point.