Deteriorating production, cold snaps, a switch in drilling targets to oil and strong Alberta industrial demand are cutting down the Canadian natural gas surplus overhanging the North American market.
As a supply barometer, the inventory in Canadian gas storage facilities is dropping fast. When heating season tapered off and injections began in early April, the stockpile was 273 Bcf — 83 Bcf (44%) larger than at the same time in 2009. As of early June gas in Canadian storage was 375 Bcf, which meant that the surplus dropped to only 13 Bcf (4%) more inventory on hand than at the comparable date last year.
During April through early June of 2010, volumes injected into Canadian storage facilities fell by 41% to 102 Bcf from 172 Bcf during the same period of 2009.
Startlingly miserable weather, especially in Alberta, has helped to burn off the surplus. Furnaces and big gas burners such as livestock fodder drying operations have run frequently this spring. As late as the first week of June, repeated blasts of cold covered the hills ringing Calgary with snow. Southern Alberta ranches at the feet of the Rocky Mountains were hit hard, with some cattle and spring calves dying in the storms, then the surviving herds running short of food because the grasslands were covered by melting snow.
But the gas surplus reduction is mainly a symptom of a longer-range decline in Western Canadian production capacity that has been widely described from various angles by analysts ranging from the Calgary oil and gas investment boutiques of FirstEnergy Capital Corp. and Peters & Co. to Alberta’s Energy Resources Conservation Board and the National Energy Board.
Gas receipts by pipelines collecting supplies from the Western Canada Sedimentary Basin (WCSB) of British Columbia, Alberta, Saskatchewan and Manitoba have fallen by 15% since prices and drilling peaked in the region four years ago.
During the 2006-07 heating season, when prices still held up strongly in the US$10/MMBtu area and annual Canadian drilling topped 22,000 wells per year, WCSB production was 16.5 Bcf/d. In the 2009-10 heating season, after prices and drilling fell by more than 50%, the total shrank to 14 Bcf/d.
Canadian industry, financial and government forecasters alike predict that the supply trend will continue for at least the next two or three years.
Drilling is recovering this year from the hard-times level of about 8,000 WCSB well completions last year, say the principal field operations trade groups, the Canadian Association of Oilwell Drilling Contractors and the Petroleum Services Association of Canada. But oil has replaced gas in the activity driver’s seat. From 70% or more of WCSB drilling, gas has dropped to the target for less than half of Canadian industry activity. Oil is the objective for up to 90% of 2010 drilling budgets disclosed by senior producers that formerly focused on gas such as Penn West Energy.
Unconventional “tight” and shale supply development, while accelerating, is still only in its infancy in Canada compared to the U.S. The new sources, led by early production in northern BC and starting to spread into Alberta, are expected initially to be too gradual in developing to make up for deterioration of aging conventional wells.
Peters & Co. analysts, who make a specialty of covering field contractors in detail, are tracking gradual evolution in Canada of the new high-productivity technologies: horizontal gas drilling and geological formation “fracing” or fracturing flow channels into rock formations with high-pressure fluid injections. The Peters count of the jumbo high-tech operations has gradually climbed from 3.5% of Canadian gas wells in 2007 to 5.3% in 2008 and 7.7% in 2009. This year, then again in 2011, the investment house predicts that high-tech wells will account for 16% of WCSB gas drilling.
But some of the new unconventional supplies are liable to be siphoned out of the international gas trade between the United States and Canada by steady increases in demand from thermal oil sands projects in northern Alberta. Bitumen extraction with processes employing hot water and steam uses on average about 1 MMBtu of gas per barrel of production. The fuel consumption is often higher by growing operations that use underground separation of oil and sand with parallel horizontal steam injection and production wells, a system known as SAGD or steam-assisted gravity drainage.
The Alberta industry is in position to increase gas use steadily as a result of an addition by TransCanada Corp. to its NOVA grid spanning the province. Construction has been completed early and gas is flowing as of this spring on a new route called North Central Crossing. The line runs from a point near the BC boundary to the heart of the most active oil sands districts in northeastern Alberta.
High oil prices, announcements that projects deferred since the 2008 financial collapse are back on track again, and fresh infusions of foreign investment including a recent spate of joint-venture deals with Chinese conglomerates have prompted the Canadian Association of Petroleum Producers (CAPP) to raise its oil sands development forecast.
Counting only plants now operating or under construction, CAPP projects that oil sands production will rise from 1.5 million barrels daily this year to 2 million in 2015 and remain there with modest increases indefinitely. But the new growth outlook, taking into account the current bitumen belt revival, calls for oil sands production to keep on rising to 3.2 million b/d as of 2020 and 4 million b/d by 2025.
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