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Shale emerging from shadows Vast resource joins tight gas, coalbed methane on Canada’s radar screen; viewed as key part of energy future but development lags behind U.S., industry wants U.S. experience used as model Gary Park For Petroleum News
Something is brewing in the Canadian oil patch, but there’s a tight lid on the contents.
It’s viewed as one of the keys to Canada’s ultimate gas future, more important than conventional gas and at least in the same league as its unconventional first cousins, tight gas and coalbed methane.
Shale gas represents the third plank in a platform that could keep the gas sector active and profitable for perhaps enough years until a way is found to tap the seemingly limitless potential of methane hydrates.
But, as with coalbed methane, Canada is lagging far behind the United States in the development of shale gas.
In the United States, nine of the 12 largest gas fields produce from tight sands, shales or coal seams.
Lower 48 production is already well established in the “hot” and extensive Barnett shale play of north Texas and is in the pioneering stages of testing the Woodford shale in the Arkoma Basin of eastern Oklahoma.
The Barnett reserves average in the range of 1.5 billion-3 billion cubic feet equivalent per well and, based on drilling by Newfield Exploration, the Woodford shale are in the range of 1.5 billion to 3.5 billion cubic feet equivalent per well.
Reflecting those results, lands in the Woodford shale are now fetching US$400-$600 per acre, compared with the US$225 paid by Newfield last year.
The growth of shale production, which now accounts for about 2 percent of U.S. gas output, has also seen a reverse trend in costs, which have fallen sharply, while reserves have risen 25 percent with better stimulation techniques.
Although gas-in-place estimates are huge, recovery factors for shales are only about 25 percent, compared with 45-60 percent for coalbed methane, according to Phil Kandel, vice-president of AJM Petroleum Consultants. Canadian shale reserve could be 860 tcf The data bank on Canadian shales is thin, although some estimates have put the reserve potential at 860 trillion cubic feet.
Whatever the numbers, a quiet case is being made that Canada will only embark on commercial production if it copies the U.S. evolution and offers fiscal structures guaranteeing attractive rates of return on capital investment, given the long lead times needed to bring shale into production.
Kirk Osadetz, a research scientist at the Geological Survey of Canada, said all the evidence suggests Canada is “not resource constrained” in gas, such as gas hydrates and shale gas and the vast Arctic potential in Alaska and northern Canada.
“New fiscal structures could significantly increase the gas supply,” he said.
To that end, industry, spurred by the outlook for commodity prices and the need for new sources of supply, has reportedly been trying to get government attention on the shale gas front.
In laying the groundwork to bring shale gas into the equation, the Canadian Society for Unconventional Gas said major E&P companies are moving closer to exploring a variety of locations.
Although shale gas is not officially being produced in the Western Canada Sedimentary Basin, gas from the Milk River formation in southeastern Alberta and the adjoining Shackleton play in southwestern Saskatchewan might eventually be attributed to shales rather than sands, said Kandel. Wells not licensed as shale gas But the Alberta wells haven’t been licensed as shale gas because the hydrocarbon-bearing zone has traditionally been exploited for conventional gas.
How big a component shale gas could become of Canada’s annual 6 tcf of production and how soon it could enter the commercial stream hinges on several factors, according to Canadian Society for Unconventional Gas President Mike Dawson, who lists three primary considerations: Whether the Mackenzie Gas Project is built, the pace of completing large-scale LNG import facilities in North America and the price of gas.
But he has no doubt that steadily declining conventional well productivity in the Western Canada Sedimentary Basin, where existing conventional wells are losing 20 percent of their output annually, and rising commodity prices will soon make shale gas an economic supply source.
The potential has been estimated in a number of studies of the WCSB, which rate shale gas as the largest component at 80 percent of the sedimentary succession. Several horizons are exploration targets A Gas Technology Institute study in 2002 identified several horizons as exploration targets.
What Canadian Society for Unconventional Gas and others hope for is that Canada will adopt the U.S. lead from 20 years ago when a tax credit program helped fuel exploration and production of unconventional gas resources, enabling the United States to kick-start coalbed methane and shale gas production, while Canada lagged far behind in both categories.
George Eynon, vice president of business development for the Canadian Energy Research Institute, said the development of Canada’s shales for oil and gas will benefit from U.S. efforts to advance drilling and completion technology, in the same way that Canada has been able to draw on U.S. understanding of the geology, resource potential and technical challenges of producing coalbed methane.
In these formative stages for shale gas, the British Columbia government is taking the role of trail blazer.
To promote the development of its shale potential, the province has invited current holders of well permits to demonstrate the production of gas from shale using new technology by granting a three-year extension to those permits. B.C. looking at net profit royalty The province is also developing a net profit royalty regime for tight and shale gas, the first incentive in Canada for those resources.
To that end, it has held discussions with the industry on how such a scheme would work by postponing the collection of royalties until front-end costs were paid off.
A spokesman for the government said the royalties would likely “kick in after a specified date, or after a set percentage of a project’s capital budget had been spent.”
A spokesman for the Canadian Association of Petroleum Producers said British Columbia has been “very responsive ... they’re right on track” with the incentives they already offer and what they are exploring for unconventional developments. As a result, oil and gas revenues are now one of the key revenue sources for British Columbia.
However, E&P companies are keeping a low profile in British Columbia and Alberta.
Sources have said a number of major companies are at work accumulating land prospects, but are not ready to go public because of their concern over unresolved issues with environmentalists and ranchers who are already campaigning against the surface-impact and risks to water supplies of low-volume coalbed methane wells.
The Canadian Society for Unconventional Gas has conceded that all of the affected parties must be involved in developing a strategy to allow the resources to be captured in an economic and environmentally responsible manner.
It says advances in directional and horizontal drilling from single well pads have already made headway in easing land-use objections in the WCSB.
For now, one of the few exceptions to the backroom nature of the discussions was a commitment in 2003 by EnCana and Burlington Resources Canada involving a shale gas test of 225,000 acres in northeastern British Columbia.
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