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Alberta grows reserves, looks for payoff
Gary Park For Petroleum News
Fueled by growth in situ development and production in its oil sands, Alberta posted a 14 percent rise in conventional oil production in 2012, a 10 percent jump in crude bitumen output and a 9.5 percent increase in reserves, intensifying the challenge of how to get those volumes to market.
In its annual numbers update, the province’s Energy Resources Conservation Board, ERCB, said conventional crude output for last year was 204 million barrels, thermal recovery logged 363 million barrels and mining operations yielded 340 million barrels, for a total of 2.48 million barrels per day.
For the first time, in situ volumes exceeded mining and the ERCB expects that gap to continue widening as Alberta’s annual raw crude bitumen production climbs to 3.8 million bpd by 2022.
Remaining crude bitumen reserves were estimated at 168 billion barrels, a drop of 0.7 percent from 2011, while conventional crude is at 1.7 billion barrels.
Conventional lifespan 8-10 years ERCB chief economist Carol Crowfoot said that unless Alberta finds more reserves its conventional holdings have a lifespan of only eight to nine years.
“We’re in a maturing basin and on the conventional side, even though we’re seeing a definite change in trend from declining production, it’s a diminishing pie of remaining reserves,” she said.
Conventional natural gas reserves in Alberta stood at 33 trillion cubic feet entering 2013, a drop of 3 percent during the year, while reserves of natural gas liquids were 1.6 billion barrels, virtually unchanged from the previous year.
The reserves estimates do not include shale oil, shale gas and shale gas liquids, which Crowfoot said represent a “treasure trove of resources” which would be reflected if development started to take place on a major scale.
The application of new technologies demonstrates the industry talent for exploiting conventional fields and the oil sands, adding to the transportation bottlenecks and the drag on prices for heavy oil producers.
‘Massive increase’ in crude Al Monaco, chief executive officer of Enbridge, said the industry is “in the midst of a massive increase in North American crude. That’s generally good news, however the lack of pipeline capacity is causing significant regional price disparities.
“We’re all concerned about the short-term and longer-term effects this could have on energy development,” he said.
The conventional surge is largely the result of horizontal drilling combined with multistage hydraulic fracturing that have unlocked formations long considered uneconomical.
Scott Saxberg, chief executive officer of Crescent Point Energy, has no worries about whether further technological change will enable Alberta to sustain its conventional production.
“We’re at the front end of change,” he said. “In the next five to 10 years we’re going to see even more advances in technology and the knowledge we have around developing these assets using fracking and horizontal drilling.”
Trent Yanko, chief executive officer of Legacy Oil + Gas, said the peak will be short-lived because of the cost of using the new techniques and the sharp per-well decline rates, but Jim Evaskevich, chief executive officer of Yangarra Resources, said his company is finding that as its results improve the costs come down as the fracks become larger and better.
Bitumen production up Of Alberta’s major bitumen producing regions, where the number of producing wells increased to 11,500 in 2012 from 2,300 in 1992, Athabasca last year delivered 547,000 bpd, Cold Lake 394,000 bpd and Peace River 127,000 bpd, with Athabasca benefitting from the evolution of steam-assisted gravity drainage, or SAGD, development.
By 2022, the ERCB expects mined bitumen to reach 1.6 million bpd, decreasing over the decade from 48 percent of total bitumen output to 42 percent, while in-situ bitumen volumes, based on projects that have been approved, are forecast to grow to 2.2 million bpd.
The report estimated that the supply cost for a generic in-situ SAGD project, producing 30,000 bpd with a capital cost range of C$750 million to C$1.5 billion, is equivalent to $50-$80 West Texas Intermediate equivalent per barrel.
For a generic standalone mine producing 100,000 bpd with a capital cost range of C$5.5 billion to C$7.5 billion, supply cost would be $70-$85 WTI per barrel.
The cost calculation changed significantly from previous years, including an increase in natural gas consumption for a SAGD operation.
Upgrading in Alberta of bitumen production edged up to 899,000 bpd from 862,000 bpd in 2011 and accounted for 7 percent of in-situ production, with the ERCB targeting 9 percent in 2022.
Upgrading not keeping pace Over the forecast period, and despite pressure from several quarters to keep more of the value-added end of bitumen production in Alberta, the regulator expects the percentage of bitumen upgraded in the province to decline to 38 percent from 52 percent, as in-situ production growth outpaces the increase in upgrading capacity.
In 2012, the five refineries in Alberta with a combined processing capacity 469,000 bpd, used 292,000 bpd of upgraded bitumen and 18,000 bpd of non-upgraded bitumen.
The ERCB said that with resurgent light oil supplies in Western Canada and the U.S. Midwest and an oversupplied U.S. Midwest market, discounting of upgraded bitumen and Western Canadian light oil will likely continue in the short term.
The largest export markets for Alberta upgraded and non-upgraded bitumen have traditionally been the U.S. Midwest, with a refining capacity of 3.58 million bpd and the U.S. Rocky Mountain region at 616,000 bpd.
But those markets are currently oversupplied because of the surge in light oil output and limited pipeline capacity to other markets, spurring efforts to reach markets such as the U.S. Gulf Coast with refining capacity of 8.8 million bpd.
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