In natural gas, Texans have no monopoly on thinking big. When prices make a comeback Canadians — including affiliates of international producers with high profiles in the Lone Star State — say they will be ready to launch the next generation of supplies on a scale deserving to rate as large by any standard.
British Columbia’s (BC) mother lode of unconventional gas eclipses even the renowned Barnett Shale in North Texas, says a top participant in both areas. Geologist Brent Snyder, leader of Devon Canada Corp.’s operation in northern BC’s Horn River Basin, does not mince words when he describes the shale deposit. “This gas is just trying to blow the rock apart,” Snyder says.
In area and depth below the ground surface the top shale gas formations of Canada and the United States look similar. Each one covers about 13,000 square kilometers (5,000 square miles). Their tops lie 2,000-2,500 meters (6,540-8,175 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 100-120 meters (327-392 feet). And the BC deposit is “severely over-pressured,” Snyder reports. “There is more gas packed into the column.” In BC the emerging new supply of the cleanest fossil fuel pushes against the rock walls of its geological prison with about 40% more force than the Barnett deposit.
Devon Canada’s Oklahoma City-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 hydraulic fracturing (hydrofracing) the geology by injecting dense fluid blends of water and sand.
In transplanting the technology to BC Devon has 153,000 acres (620 square kilometers, 248 square miles) 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. Each one would only occupy 2.5 times the land surface space used by one typical single well 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 BC 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 toward 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.”
The industry is studded with signs of intentions to make BC shale gas happen big time when the markets burn off current surpluses and prices take a turn for the better. Heavy expenditures of money and planning effort are already in progress. BC sold C$2.66 billion (US$2.47 billion) in provincial drilling rights last year, more than double the old record of C$1 billion (US$930 million) set in 2007 and a six-fold jump from the previous 10-year annual average of C$434 million (US$404 million). Auctions continue at a brisk pace.
Participants in the land rush also launched a Canadian industry first to smooth the development path. Firms that are competing for hot properties, and that are not project ownership partners, formed an alliance for collective work on community relations, aboriginal consultation, regulatory affairs and local training, employment and business development. The 11-company Horn River Producers Group is a gas industry who’s-who studded with Canadian subsidiaries of North American gas leaders: Apache Canada, ConocoPhillips Canada, Devon Canada, EnCana Corp., EOG Resources Inc., a BC partnership of Imperial Oil Ltd. and ExxonMobil Canada, Nexen Inc., Pengrowth, Suncor Energy Inc., Quicksilver Resources Inc. and Stone Mountain Resources (see Daily GPI, Sept. 23).
Preparations for the next generation of Canadian supply development continue to include a lineup of infrastructure projects for putting BC gas on the international supply map, with EnCana predicting production could match or exceed Alberta output in a decade. The major plans are a new processing mega-site north of Fort Nelson called the Cabin Gas Plant and forecast to cost up to C$2.4 billion (US$2.2 billion) (see Daily GPI, April 23; Jan. 12); two extensions of TransCanada Corp.’s Nova pipeline grid into BC for a projected C$580 million (US$540 million) (see Daily GPI, July 7); service additions by the Alliance Pipeline from Fort St. John to Chicago (see Daily GPI, June 15) and by Spectra Energy’s BC gas processing and pipeline network (see Daily GPI, July 29), the new C$1-billion link called Pacific Trail Pipelines to Kitimat on the BC coast (see Daily GPI, April 13); and the C$3-billion (US$2.8-billion) Kitimat LNG proposal for an export terminal that has tentative supply and sales agreements with Apache, EOG, Korea Gas Corp. and Spain’s Gas Natural (see Daily GPI, Aug. 11).
As in Texas, the BC version of shale gas technology is evolving into larger and increasingly economic production systems. Prototype wells drilled by pilot operations began with horizontal legs 750 meters (2,450 feet) long and four formation-fracturing injections. Each of the mini-earthquakes uses 1,500 to 3,000 cubic meters of water and 150 to 250 metric tons of sand driven into the shale by chain gangs of compressors with horsepower measured in tens of thousands. In the latest trials the scale has about doubled. “Everybody’s playing with length. We probably could go a lot farther,” Snyder says.
Estimates of recoverable Horn River reserves run to 60-120 Tcf, a colossal supply at least 50% greater than Alberta’s entire remaining conventional gas inventory.
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