Alberta's role as an international natural gas supply mainstay will shrink as aging wells are depleted and domestic consumption rises, the province's Energy Resources Conservation Board (ERCB) confirms.
In an annual state-of-the-industry report, the ERCB predicts conventional production, currently about 12 Bcf/d, will drop by 6% this year and then by an annual average 4% through 2018. Unconventional output is expected to make up for some of the erosion, but only partially and by an unknown amount because coalbed methane extraction is still in early stages and shale gas development has yet to reach Alberta.
At the same time, the ERCB predicts that domestic demand will jump to 58% of production from the current 33%. The increase will chiefly be due to rising consumption by thermal oilsands extraction operations and associated synthetic crude oil upgraders.
While the new forecast agrees with private projections of a lasting slowdown in the province's Florida-sized northern bitumen belt, the ERCB predicts that development will continue at a measured pace.
By 2018 the board expects gas use in oilsands production will more than double to 2.3 Bcf/d from the current 1 Bcf/d. Counting gas used by power and steam cogeneration units at oilsands plant sites that also produce power for the provincial electricity grid, bitumen belt gas is forecast to rise to 3.5 Bcf/d by 2018 from the current 1.6 Bcf/d.
The bitumen development lineup, stalled since oil prices dropped last fall, has resumed advancing as cost-cutting and engineering reviews select the fittest schemes. Canadian Natural Resources Ltd. (CNRL) declared intentions to go ahead at its Kirby site as the first, 40,000-barrels-daily entry in a string of projects planned to achieve a total of 285,000 b/d from a vast spread of company oilsands leases between Fort McMurray and Cold Lake.
The CNRL plan surfaced at a Calgary investment symposium held by the Canadian Association of Petroleum Producers, soon after Imperial Oil Ltd. restarted bitumen development by launching construction of its Kearl mega-mine north of Fort McMurray for up to C$8 billion (US$7 billion). Production only starts at 100,000 b/d, with additional phases planned to increase output steadily to 345,000 b/d.
Depending on the methods used and the stages of the production systems done by plants, gas use by oilsands operations ranges from about 0.29 Mcf/bbl of output to 1.41 Mcf/bbl, the ERCB reports. The board forecasts that total production will rise to 2.9 million b/d by 2018, or more than double the current 1.3 million b/d. Much of the growth is already launched, with the new forecast relying on plants currently in start-up stages, projects entering construction and development schemes holding regulatory approvals.
On the supply side, Alberta's gas industry is repeating the classic signs of peaking and entering into decline that Texas and Louisiana on-shore conventional production went through in the 1970s.
"The number of producing gas wells has increased significantly year over year, while gas production has decreased since reaching its peak (of about 14.5 Bcf/d) in 2001," the ERCB observes. "By 2008, the total number of producing gas wells (in Alberta) increased to 117,923 from 28,400 wells in 1990. It now takes an increasing number of new gas wells each year to offset production declines in existing wells."
Producers in Western Canada, who were already heavily dependent on natural gas, increased their weighting from oil to gas even more during 1Q2009, according to a survey conducted by Canadian research firm Bryan Mills Iradesso (see related story).
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