Devon Canada Corp. has high hopes for shale gas in northeastern British Columbia
Gas megaproject methods are migrating into B.C. shale, setting the stage for the next big boom
British Columbia’s mother lode eclipses even the renowned Barnett Shale in central Texas. “This gas is just trying to blow the rock apart,” says geologist Brent Snyder, leader of Devon Canada Corp.’s foray into northern B.C.’s Horn River Basin.
In area and depth, the top shale natural gas formations of Canada and the United States look similar. Each one spans about 13,000 square kilometers (5,000 square miles). Their tops lie 2,000 to 2,500 meters (6,540 to 8,175 feet) beneath the land surface.
But the Horn River layer averages 200 meters (654 feet) from top to bottom, or about twice the Barnett’s thickness of 100 to 120 meters (327 to 392 feet). And the B.C. deposit is “severely over-pressured,” Snyder reports. “There is more gas packed into the column.” In B.C., the emerging new supply pushes against the rock walls of its geological prison with about 40 per cent more force than the Barnett deposit.
To visualize the drilling targets that have transformed the North American supply outlook, imagine vast black crystals or deeply tinted safety glass windshields. They have microscopic pores stuffed full of dispersed natural gas that combines into currents if the material is cracked in just the right way to open channels. Powerful initial flows, driven by freshly released pressure, drop by 60 per cent over the first year, then continue to taper off at a more gradual rate. But the structure is so full that proper control and additions of new channels can keep the gas coming out potentially for decades.
Devon Canada’s Oklahoma-based parent company became the top Barnett gas producer in 2001 with a US$3.5-billion takeover of Mitchell Energy, a private Texas firm that spent 20 years inventing technology to crack shale deposits. The trial-and-error work, done with an array of drilling and oilfield service contractors, developed a gas-manufacturing system of horizontal wells and “fraccing,” or fracturing the geology by injecting dense fluid blends of water and sand.
In transplanting the technology to B.C., where Devon has 153,000 acres (620 square kilometers) of Horn River mineral rights, Snyder foresees building a gas factory. An efficient production line will have up to 32 long horizontal wells reaching out at varying depths from compact drilling “pads” or sites. Each one would only occupy 2.5 times the land surface space used by typical single wells in conventional Alberta production. “We would like to make this as friendly to the environment as possible,” the Devon geologist says.
The rate of shale gas development in B.C. will depend on energy prices and construction of roads, bridges and pipelines into the remote, rugged Horn River Basin.
The deposit is a three-and-a-half-hour drive northeast into the woods and muskeg marshes beyond Fort Nelson, on an industrial trail of gravel and one-lane bridges that reaches towards the provincial boundary with the Yukon and Northwest Territories.
“Even if the gas price goes up, it’s not all going to happen tomorrow,” Snyder says. “It’ll be a five- to 10-year period before it really comes on.”
With its lavish use of expensive technology to develop big reserves with long productive lives, shale gas follows a pattern set in Alberta’s oil sands that the industry calls “resource plays.” Big spreads of mineral rights are acquired. Then development goes in stages. Operations start small and slow, with pilot projects that assess variable conditions in the deposits and work out technology adaptations which can be scaled up into efficient mass production lines.
Resource plays are dominated by big companies looking far beyond current energy markets, prices and stock exchange moods. The approach generates counter-cyclical surprises. In Alberta’s bitumen belt, the Athabasca consortium led by Shell Canada startled conventional producers and investors by launching construction of its mega-mine, pipeline and upgrader when oil stagnated at lows as sorry as US$11 a barrel in the mid-1990s. Imperial started its Cold Lake megaproject at a low point in 1980s slumps and is repeating the pattern now with its Kearl development.
On the natural gas horizon, the view is bright for B.C. Old conventional supplies are dwindling. Demand is bound to rise for the cleanest fossil fuel.
Environmental policies are expected to discourage building new coal-fired power plants, and possibly encourage old ones to switch fuels. Alberta, meanwhile, is past its best-by date as Canada’s gas supply mainstay unless it too can lure industry into shale deposits. Conventional production peaked seven years ago. Output will drop by six per cent this year then keep on shrinking by an annual average of four per cent even if drilling stages a comeback, says the latest Alberta reserves review by the Energy Resources Conservation Board.
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