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Alberta crude up, gas bleak Alberta Energy Resources Conservation Board report for 2011 projects less natural gas will be available for export as needs grow Gary Park For Petroleum News
Alberta’s hydrocarbon future is being pulled in opposite directions, with horizontal drilling credited for a 6.7 percent increase last year in the province’s crude oil production, while evidence continued to point to a bleak future for natural gas.
Those conflicting highlights were contained in the Alberta Energy Resources Conservation Board’s report on 2011 reserves and supply/demand outlook for the next decade.
The regulator said the increase in conventional crude volumes to 490,000 barrels per day was largely due to the use of horizontal wells, many of them employing multi-stage fracturing, with remaining established reserves up 3.8 percent from 2010 to 1.5 billion barrels.
The ERCB reported that 3,170 successful conventional wells were drilled, up 37 percent from 2010.
It said the Athabasca Upper, Middle and Lower Grand Rapids deposits and the Athabasca Nisku deposit were reassessed for year-end 2011 and resulted in a 7 percent hike in the total in-place crude bitumen resource to 58.4 billion barrels, while the Nisku deposit was increased by 57 percent to 102 billion barrels.
The ERCB reported that Alberta produced 1.7 million bpd of raw crude bitumen from the oil sands for an annual total of 637 million barrels, up 8 percent from 2010.
It listed remaining established crude bitumen and crude oil reserves at 170.2 billion barrels.
No new conventional gas On the downside, remaining established reserves of conventional gas were unchanged at 34 trillion cubic feet, while production for the year of 3.6 tcf was 4.6 percent lower than 2010.
But the failure to build on reserves has the ERCB projecting that less than 20 percent of Alberta’s production will be available to out-of-province buyers by 2021, continuing a trend that emerged five years ago as commodity prices started their long slide and output locked in at 12.5 billion cubic feet per day.
“As Alberta’s requirements continue to increase and production declines, less gas is forecast to be available for removal from the province. Last year, nearly 42 percent of the province’s production was used domestically and this will increase to 81 percent by 2021,” the report said.
The ERCB forecast gas prices at the Alberta wellhead will range between C$1.50 and $2.50 per gigajoule in 2012, with a base price of C$2, and expects continued weakness due to surplus supplies in North America, although a slow recovery should raise prices to C$6 by 2021.
“Longer term, a combination of LNG exports and increased domestic demand is projected to contribute to a slow strengthening of natural gas prices,” the ERCB said.
Potential renaissance from LNG Speaking at a Calgary conference on the development of unconventional gas, Nexen’s Senior Vice President for Gas Ron Bailey said LNG could “potentially bring about a renaissance in Alberta’s natural gas sector and spur several more drilling activities.”
He said Nexen is conducting an extensive technical and commercial analysis of its assets in the Horn River, Cordova Embayment and Liard plays of northern British Columbia and is completing an 18-well pad aimed at raising gross production volumes to peak rates of about 155 million cubic feet per day by late 2012 or early 2013.
Bailey said his company is currently projecting reserves of about 388 billion cubic feet per well, which could increase to 565 bcf with reservoir modeling.
He said Nexen is working on plans with Inpex and Japan Gas to develop the 9 tcf of resources it holds in Western Canada.
Ed Kallio, director of gas consulting with Ziff Energy Group, estimated gas demand will increase by 1 to 3 bcf per day by 2021 for new thermal recovery oil sands projects, but he warned that unless existing shale gas reserves in Western Canada are monetized soon they risk becoming stranded.
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