While raising a possibility that the dormant Deep Panuke project will be revived offshore of Nova Scotia, Canada’s top natural gas producer has made it plain its priorities are out West and on safer bets.
EnCana Corp. declared itself encouraged by recent drilling results at the Deep Panuke site near the Sable Offshore Energy Project, but only set a target of Dec. 10 for explaining its intentions there. At the same time, the 3 Bcf/d producer launched work on a development described as a model of the tamer type that it prefers, announcing the largest coalbed methane extraction program yet in Canada.
President Gwyn Morgan called it a classic case of “resource plays” that Canadian suppliers need to concentrate on under a “new paradigm” set by the peaking and downward turn of their conventional reserves, productive capacity and drilling targets since 2001.
Also known as technology plays or the gas-factory approach, the strategy centres on applying advanced methods such as horizontal and controlled-pressure drilling in assembly-line fashion to well-known deposits previously rated as unconventional or too difficult. Another example, now getting under way, is an EnCana development called Cutbank Ridge in northeastern British Columbia, where the industry knew about the gas deposits for decades, but passed them up as beyond reach of previous technology.
“Resource plays are not sexy,” COO Randy Eresman told investors last week. “They don’t appeal to explorationists. It’s an engineers’ approach.” In western Canada — and in a company determined to make its own luck and strictly control its costs — the new focus will also increasingly become the only practical approach, Morgan suggested.
He pointed out that conventional gas fields have been depleted and picked over to the point where “even a frenzied effort to drill wells after the 2000-01 brush with shortage didn’t do a whole lot.” EnCana set a target producing 200 MMcf/d in five years on 700,000 acres of coal properties, in a district that thrived on mining until the 1950s a short distance northeast of the Canadian gas capital of Calgary.
EnCana added it will not have to pay royalties because it owns all the mineral rights – a rarity in Canada owed to the company’s descent from PanCanadian Energy, a former affiliate of the Canadian Pacific Railway and heir to 19th-Century federal land grants. Gas reserves in EnCana’s Alberta plains coal fields are forecast to exceed 2 Tcf.
The company expects to drill 4,000 wells to reach its production target. Each can be drilled and completed and tied-in to production facilities for about C$250,000 (US$190,000). The program will use an established grid of shallow gas production systems. Costs of developing the coal-seam gas production are forecast to average C$1.50 (US$1.15) /Mcf. A 200-well program is getting under way.
An additional 300 wells are planned for 2004 and the program is expected to accelerate as the company’s engineers become familiar with the operation to the point where it becomes a harvesting routine. It helps that there is little water in the coal seams to interfere with production or duplicate environmental headaches encountered in some parts of the United States.
At Cutbank Ridge, a similar pattern will be followed to extract a forecast 2.5 Tcf of gas. The deposit is the type known as “stratigraphic” or spread over a wide area instead of concentrated in balloon- or tank-like formations. The project requires mastery of techniques described as akin to drilling through glass, with the engineers using a light touch to penetrate brittle rock formations that older, cruder methods can break and seal up.
On about 800 square miles of resource leases acquired from the B.C. government and less technically-minded producers for C$369 million (US$280 million), EnCana intends to drill up about 375 horizontal wells over a five-year period. Cutbank Ridge production is expected to build up to more than 300 MMcf/d. Although the B.C. program is expensive compared to the Alberta coalbed methane, with Cutbank Ridge wells each costing about C$4 million (US$3 million), it is still seen as a bargain compared to offshore projects.
EnCana suspended work on Deep Panuke last February, saying its reserves in the range of 900 Bcf at the time did not justify the projected C$1.1 billion (US$840 million) cost of a production platform. Although the drilling results have yet to be disclosed, EnCana said the outlook has improved offshore of Nova Scotia as a result of two wells called Margaree (100% EnCana) and MarCoh (split by EnCana, ExxonMobil and Shell Canada).
Canadian regulatory authorities were promised a progress report before the end of the year when they agreed to grant EnCana a “time-out” on Deep Panuke applications last winter. The company indicated the drilling results are not the only factor weighing on the decision whether to proceed. Also under review are options for lowering costs of the development, such as connecting to the SOEP production system or a site on shore.
While Canada’s top producer presented its version of the nation’s future as a gas supplier, its peers confirmed that sustaining productive capacity is becoming harder. In a review of 2002 overall performance, the Canadian Association of Petroleum Producers reported only 86% of production was replaced by additions to reserves. As of year-end 2002, the total Canadian gas inventory slipped by 1 Tcf or 1.7% to 59 Tcf. B.C., sometimes nicknamed “the near frontier,” stood out as the lone Canadian gas-producing jurisdiction where reserves additions exceeded production in 2002. Accelerating drilling into sparsely explored northern targets added a net 114 Bcf to the B.C. inventory.
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