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Vol. 11, No. 4 Week of January 22, 2006
Providing coverage of Alaska and northern Canada's oil and gas industry

Technology key to Canadian tight gas

Tight gas in place estimated at 575 tcf, with 10-15 tcf economically recoverable; common definition of tight gas lacking

Gary Park

For Petroleum News

Tight gas is the next in line to keep Western Canada in the North American big leagues, says an executive report by Ziff Energy Group.

Currently the resource accounts for 8 percent of the region’s recoverable gas potential and 7 percent of its current production, but it is destined to match coalbed methane as the sector’s major supply source, the Calgary-based consulting firm forecasts.

Currently tight gas in place in Western Canada could be 575 trillion cubic feet, with 10 tcf to 15 tcf deemed economically recoverable.

Ziff said tight gas is currently yielding about 1.2 billion cubic feet per day from the Deep Basin region that stretches along the eastern foothills of the Canadian Rockies in Alberta and British Columbia.

The producers range from mid-size companies such as Duvernay Oil, Daylight Energy Trust, PrimeWest Energy Trust and Compton Petroleum, to several majors, including BP Canada Energy, Burlington Resources Canada, Anadarko Canada and Devon Canada.

The northern end of Deep Basin connects with the Jeanne-Marie formation and Greater Sierra region of northeastern British Columbia, where EnCana and Talisman Energy are the power players.

Uniform definition lacking

What’s lacking in Canada is a uniform definition of what constitutes tight gas, which Ziff defines as gas existing in sand, conglomerate and carbonate formations that are laterally continuous, gas-saturated, generally thick and have low matrix permeability.

Ziff analyst Dana Bozbiciu expects tight gas development will be more the result of technical advances, notably in artificial fracturing of formations, than strictly by price.

Meanwhile, the industry is currently developing guidelines for evaluating unconventional gas reserves, although that task is confined to volunteer workers.

The Alberta Securities Commission is not prepared to say when those guidelines will be completed, although special committees are limiting their work to in situ bitumen, mined bitumen and coalbed methane — the three leading sources of unconventional production.

There is no idea when other forms of unconventional oil and gas will appear on the horizon, although Alberta, British Columbia and Saskatchewan are all awakening to their unconventional gas potential.

B.C. working on royalty scheme

David Molinski, a deputy minister in British Columbia’s oil and gas division, said the province is working on a royalty scheme for shale gas as industry interest builds in the northeastern prospects.

Shale, tight gas and coalbed methane will “play a very significant role in B.C. oil and gas development into the future,” he told a Calgary conference, but will depend heavily on industry investment, including technology.

A 2005 study by the British Columbia energy ministry that concentrated on Devonian shale potential estimated an in-place capacity of more than 500 tcf.

However, it’s not clear how much will be recoverable, Molinski said.

The province estimated that northeastern shale accounts for 5 tcf or 12 percent of estimated remaining marketable gas resources.

A follow-up study on the potential of Triassic shale gas, which Molinski said could be “enormous,” will be released this year.

British Columbia’s strong interest in unconventional resources is easily understood, given that up to 30 percent of its current production stems from tight gas, while a surge of exploration, including 70 wells and test holes, is underway to exploit 84 tcf of potential coalbed methane resources.

To further spur investment, the province is offering a break on royalties for smaller, shallower pools that are less productive, covering two thresholds — wells under 80,000 cubic feet per day and production of less than 880,000 cubic feet per day.

The qualifying period expires June 30, 2008, although there is hope it will be extended.

Alberta looking at changes

Alberta Energy Minister Greg Melchin has promised regulatory, taxation and legislative changes in 2006 to stimulate the development of unconventional gas, which he says has the potential to become the dominant source of supply in the province.

Even now, 50 percent of oil patch capital spending is devoted to unconventional plays, according to Tristone Capital analyst Chris Theal, while drilling was predicted to exceed 3,000 wells in 2005.

Melchin is a strong backer of the coalbed methane, tight gas and shale gas prospects of southern Alberta, which offer much easier access to Canadian and U.S. markets than Arctic gas.

“We might be overlooking the best and easiest prize right here, closer to customers,” he said.

Saskatchewan has established a working group to explore potential issues relating to coalbed methane.

It does not expect to operate on the same level as British Columbia or Alberta, but offers a royalty level on wells of less than 125,000 cubic feet per day that is lower than Alberta’s.

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