British Columbia (BC) will grow to match Alberta -- and possibly surpass it -- as Canada's prime supply source as development of shale deposits accelerates, the nation's biggest natural gas producer predicts.
The industry is embarking on nothing short of a "gas renaissance" and in Canada, BC is at the forefront, EnCana Corp. Vice President Richard Dunn told an industry conference held Thursday in Calgary by the Canadian Institute. "I've been working on gas for 30 years. We've never seen such a change," Dunn said.
He recited a new consensus forecast that by 2020, shale development will double or triple BC production into a range of 6-9 Bcf/d. The growth in a region known as the Canadian industry's "near frontier" is projected to happen at the same time as natural depletion shrinks Alberta output from conventional fields dating back to the 1940s and 1950s.
The switch is expected to propel BC into prominence as potentially the top source of Canadian exports to the United States. Alberta supplies are forecast to stay increasingly within the province for use as industrial fuel by thermal oilsands extraction and synthetic crude upgrader plants.
The Canadian share in the coming gas renaissance is owed to a combination of shale technology transplanted from Texas, rich deposits discovered in BC, favorable provincial royalties, and a resource play method of organizing development into manufacturing gas, Dunn said.
Up to 10 hydraulic fractures, or high-pressure fluid injections, are opening shale deposits to make the gas flow in a process akin to shattering safety glass, he reported. In Canada, the technique developed in the Barnett Shale deposit of North Texas is being employed in networks of wells with horizontal legs approaching two miles long.
While the pace of growth will vary over time as economic conditions fluctuate, shale development will not require market spikes, Dunn predicted. "Commodity prices are going to be modest at best for the foreseeable future." But the technology will improve and in Canada the resource play method of organizing drilling into networks of repetitive wells on large, continuous mineral rights holdings generates reductions in costs at the same time as they are spread over rising production, he said.
The BC government is providing a key ingredient of the forthcoming growth with a net profit royalty regime that is being implemented this year, the EnCana executive added. The system is a gas counterpart to the light royalties regime used by Alberta to encourage oilsands projects.
The new regime does away with the Canadian provinces' tradition of taking royalties off the top as large shares of gross revenue from the day production starts. Instead, rates are held down to a nominal level of 5% or less until capital costs are recovered. Then royalties are collected only off projects' net revenues after deductions of production costs. Rates gradually rise over time, but are not expected ever to reach the traditional system's government take of up to 30% during periods of high prices.
BC project negotiations, currently under way, are expected to take into account the remote location of shale development targets by including new roads and pipelines in the costs allowed to hold royalties down.
The prime BC target -- the Horn River Basin -- is in all but uninhabited, trackless woods east of the Alaska Highway near the province's boundary with the Yukon and Northwest Territories. But the immense size of the resource justifies taking on high up-front costs of opening the region.
"It's extensive. It's thick. It's got a lot of gas," said Apache Canada's Rob Spitzer, the company's exploration vice president and chairman of the Horn River Producers Group. The alliance coordinates development planning and government and community relations for 11 producers in the area including Apache, EnCana, Devon, ExxonMobil, Nexen, EOG Resources, Quicksilver Resources, Stone Mountain, ConocoPhillips Canada, PenGrowth Energy and Petro-Canada (soon to merge with Suncor) (see Daily GPI, June 5).
The Horn River deposit is a 500-feet-thick layer of shale saturated with gas at depths of 8,000 to 10,000 feet that spreads over about 3,000 square miles. The formation is estimated to contain 400 to 500 Tcf as an in-place resource endowment. "Even at very modest recovery rates" -- projections range from 10-30% -- "that represents a lot of gas," Spitzer said.
"We're at the start of the development phase," the Apache executive said. Despite the current low on the gas market, the companies in his group are continuing to invest in the area at annual rates of up to C$150 million (US$135 million) apiece.
The BC shale stands out as a world-class development target, Dunn said. "You could fit two to three Barnetts quite comfortably into the Horn," he pointed out. EnCana is in a position to make comparisons between the Texas and BC deposits as a top participant in both areas.
The Horn River Basin is not the only shale deposit expected to propel growth in BC production for decades to come. Development is also accelerating in a less spectacular but more accessible, mixed tight rock and shale formation known as the Montney, in the Dawson Creek region where the Alaska Highway begins.
The area has lured BP Energy Canada back into supply development as big enough to interest a subsidiary of the British global gas empire. The company is embarking on a C$1.4 billion (US$1.3 billion) drilling program called Noel just south of Dawson Creek, BP Canada Vice President Phil Aldis said.
The project will build up 130 MMcf/d of production over the next eight to 10 years with 136 long-leg horizontal wells. Initial production is scheduled by the end of this year. The BP executive indicated that skeptics of shale gas are misunderstanding the nature of the resource by suggesting that current high production levels are temporary initial results of wells that will decline rapidly. The chief attractions of the new gas source include long production lives. Shale wells will keep on putting out gas for 30 to 40 years, Aldis said.
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