As a budding revival of oilsands development gathers steam, thermal production projects will burn up Alberta’s contribution to North American natural gas gluts, show new projections by the province’s Energy Resources Conservation Board (ERCB).
The 2011 edition of the agency’s annual encyclopedic Alberta Energy Reserves report includes a paint-by-numbers portrait of a decades-old continental supply mainstay subsiding into primarily a producer for its own, growing industrial needs. As of the last complete count, in 2010 the jurisdiction that accounts for about four-fifths of Canadian gas still sold all but 38% of its production beyond its borders, with a majority of the output going to the United States.
As of 2020 Alberta will consume 77% of its own gas production, the ERCB calculates. The board projects that the volumes of Alberta gas sold on markets beyond the province’s borders, in the rest of Canada as well as the United States, will drop by 74% to 1.8 Bcf/d in 2020 from 6.9 Bcf/d in 2010. The trend is well-established. As of last year that 6.9 Bcf/d in out-of-province Alberta gas sales was already down by 38% compared to 11.2 Bcf/d in their peak year of 2001.
Part of the explanation is on the supply side, where decades-old jumbo conventional gas pools that launched the industry are naturally depleting and coalbed methane has turned out to fall far short of a substitute, the ERCB said.
In Alberta shale gas is in an embryonic, exploratory and confidential stage that is too small to make even guessing at future development possible, the board adds. The Canadian industry’s top shale targets are in northern British Columbia where Canadian subsidiaries of Apache Corp., EOG Resources Inc. and Encana Corp. are teamed up on a Pacific coast liquefied natural gas export terminal at Kitimat and a supporting pipeline, while a lineup of producers such as Progress Energy are studying similar projects.
But the demand side of the market plays a starring role in the Alberta gas outlook. The oilsands are a growing factor in lowering the province’s profile on gas markets across Canada and the United States, thanks to surging development in the northern bitumen belt that only paused briefly for the 2008 global economic slump.
The ERCB projections show that gas purchases by oilsands operations will increase by 133% to 2.96 Bcf/d in 2020 from 1.27 Bcf/d in 2010.
Despite trials of alternatives such as solvents, barbecue-like “firefloods” and electrical heaters dating back to the 1970s, steam and hot water made by burning gas remain the only means of separating oil and sand that work on a large scale. And gas use by the heat-and-water bitumen production systems remains stubbornly high after years of engineering work on improving a process invented in the 1920s at the provincial government’s Alberta Research Council.
At the most efficient operations — open-pit bitumen mines and upgrader complexes that make a premium product known as SCO, or synthetic crude oil — every barrel of production burns up an average 0.7 Mcf of natural gas, the ERCB reports. Gas use runs at 1.3-1.4 Mcf per barrel of output at in-situ or underground extraction projects, also known as drilled oilsands because they use heat injection and production wells to separate bitumen from deposits too deep to mine.
The economics of oilsands operations favor the heaviest gas users, the ERCB figures show.
Mines — the original oil sands approach, dating back to the startup of the first plant in 1967 — require production of at least 100,000 b/d, cost C$5-11.5 billion to build and need prices of C$63-102/bbl to be economic, the board estimates. Newer in-situ bitumen extraction operations can be developed in 30,000 b/d stages that cost C$900 million to C$1.35 billion apiece and only need oil prices of C$47-57/bbl, the ERCB calculates.
After canvassing the bitumen belt project lineup and discounting entries to take into account varying levels of preparation, the board projects that production will increase by 120% to 3.5 million b/d as of 2020 from the current 1.6 million. Starting in 2015, in-situ bitumen output is expected to surpass the mines even though they are all working on additions.
Alberta’s shrinkage as a North American natural gas supplier already is effecting the market by causing sharply increased tolls on TransCanada Corp.’s eastbound pipeline to central Canada and the middle-western and northeastern United States. The hikes stem from a national regulatory regime that ensures the delivery system will keep on operating by collecting its revenue requirement when traffic drops.
Apart from shrinking the current glut there is another silver lining to the cloud over Alberta’s role as a North American mainstay supplier, according to industry projections by Ziff Energy Group. Arctic gas from the Mackenzie Delta and Alaska will become more attractive because growing vacant space in TransCanada’s system will cut costs of northern projects by ending any need to build additional capacity beyond its inlets in British Columbia and Alberta, group founder Paul Ziff told an industry conference in Calgary.
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