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Alberta Fracking New Life Into Oil Production
Horizontal drilling and hydraulic fracturing has powered the biggest increase since the 1970s in Alberta oil production from flowing wells outside the northern bitumen sands belt, says the provincial Energy Resources Conservation Board (ERCB).
Output from flowing Alberta oil wells jumped by 14% in 2012 to 559,000 b/d, says the scorecard in an annual ERCB reserves and state of the industry report released Wednesday. The total is expected to climb again to a 2013 average of 593,000 b/d.
The number of new Alberta wells that tapped oil targets with horizontal drilling and multiple-stage fracturing methods climbed by nearly one-third last year to 2,379.
The ERCB predicts that the count of new generation hydraulic fracturing wells will stay above 2,300 this year and again in 2014. The total is currently forecast to recede to 2,080 by 2022, but the board acknowledges use of the technology has grown and spread far faster than its conservative former expectations.
The new Alberta volume of oil from flowing wells remains far below the peak of 1.4 million b/d hit in 1973. But counting growing oilsands bitumen output that averaged 1.9 million b/d last year, the province is a bigger producer than ever, pumping out 2.5 million b/d and exporting the majority of the total to the United States as the largest supplier of U.S. imports.
By 2022, the ERCB expects Alberta’s total output of all oil varieties to hit 4.2 million b/d, led by a doubling of bitumen to 3.8 million b/d.
Where all the production will go is not forecast because a variety of delivery projects are jostling for industry support and regulatory approval. The schemes have potential to expand the province’s markets overseas through proposed Pacific Coast tanker terminals, to the Atlantic seaboard with proposed eastbound pipeline service, and via railway routes across North America.
Alberta natural gas production continues to head in the opposite direction, lowering the province’s profile as an exporter due to gradual depletion of aging wells and rapid growth of domestic industrial consumption by thermal oilsands projects.
The province’s daily average gas output declined by 5.6% last year to 10.2 Bcf/d and is expected to slip again in 2013 to 9.6 Bcf/d.
The National Energy Board of Canada tallies marginally different totals than ERCB but reports the same production trends for the province, with crude oil production expected to increase 13.3% this year and natural gas output forecast to decline 10.1%.
The gas production decline is expected to remain gradual. As of 2022, the ERCB forecasts that Alberta will still produce 7.8 Bcf/d. The province’s withdrawal from export markets is forecast to be faster because domestic industrial consumption is forecast to jump to 78% over the next 10 years, or nearly double the 44% of Alberta output currently used on markets inside the province.
The price gap between oil and natural gas is also expected to remain a wide gulf. Oil is forecast to stay in a range of C$90-100 per barrel (US$ at par), while the Alberta gas price hovers at an annual average of C$3.26 per gigajoule (US$3.42/MMBtu) this year and takes until 2022 to recover to C$4.88/gigajoule (GJ) (US$5.12/MMBtu). The new pricing outlook brightens the gloom that prevailed last year, when Alberta gas averaged C$2.14/GJ (US$2.25/MMBtu), but remains a far cry from the commodity’s C$8-10 range before the onset of economic recession and surplus supplies four years ago.
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