The Latin motto on Canada's coat of arms means "from sea to sea," and it aptly describes the development of coalbed-methane gas in the country. From Vancouver Island in the west to Nova Scotia in the east, companies and governments are taking steps to turn a potentially huge source of nonconventional gas into commercial projects. "Really, the question is not the presence of coal. It's how much gas is in the coal, how permeable is the coal and can one produce the gas?" says Kin Chow, manager of new ventures for PanCanadian Energy Corp., Calgary. "It's kind of like oil sands-there is a lot out there, but real technical and cost challenges exist. If you can be successful, the resource is huge." Between C$50- and C$100 million will be spent on coalbed-methane (CBM) pilot projects this year, mostly in British Columbia and Alberta. However, the answers to the critical questions Chow raises will not be known for months or years. This means the commercial viability of the resource, which has been estimated at anywhere from 100- to 2,300 trillion cubic feet, will continue to lag far behind the U.S.-where CBM production has grown in recent years to account for about 7% of daily gas production. The gap in production among the two countries will get smaller this year, however. Drilling dozens of wells to determine which coals, and where, are best suited for CBM production are PanCanadian, Alberta Energy Co. Ltd., Burlington Resources Canada Energy Ltd., Penn West Petroleums Ltd., Quicksilver Resources Inc. and other firms. John Seidle, senior reservoir engineer in the Denver office of consultancy Sproule & Associates, says permeability and fracturing-to ensure the opening of coal's cleated structure-are critical issues to be examined with the pilots. "In my mind, there is gas in almost all the coals in Canada, so the idea is to find the permeability. Once I know the permeability, then it becomes a stimulation-completion kind of a question," he says. "As we learn about the coals of Canada, what fluids to which they are most sensitive and which fracture treatments work best, then we'll see the commercial production begin to grow." CBM experiments in Canada are not new. A review by the Geological Survey of Canada found more than 200 CBM wells have been drilled in the country, many of them about a decade ago, but no commercial fields exists north of the 49th parallel. Executives and analysts attribute the revival of interest to increased maturity of conventional gas plays in western Canada, existing infrastructure, higher gas prices and better technology. "Unlike in the more mature U.S. basins, Canadian producers haven't had to look at unconventional resources," says Mark Ellis, president of Burlington Resources Canada. "With the maturing of the Canadian basins comes a strong effort by all companies to look at unconventional resources as a natural extension of their exploitation of the Western Sedimentary Basin." Mike Gatens, chief executive of MGV Energy Inc., says many of the wells drilled in previous decades went after deeper targets, believed to contain higher gas levels. But permeability was poor and bed deformation complicated completions, contributing to the lack of success. A subsidiary of Fort Worth-based Quicksilver Resources Inc., MGV is participating in CBM projects with both PanCanadian and the Canadian unit of Houston-based Conoco Inc. Gatens believes results will be different this time because of improved technology and greater knowledge. "I also think the Powder River Basin showed the industry that you can produce low-rank, low-gas-content coal commercially if you have the right combination of other things like good permeability and low costs. I think it was a paradigm shift." The shift, if it has occurred, is still young and cloaked in secrecy. Operators are keeping their lips sealed tighter than a locked-down maximum-security prison. Most cite competitive reasons for not releasing data on gas- and water-production rates, completion techniques, permeability factors and possible spacing sizes. The larger players Jeff Wojahn, vice president of Calgary-based Alberta Energy's southwest business unit, says Canadian CBM efforts can generally be divided into two broad strategies. While PanCanadian and Penn West are trying to utilize existing infrastructure to exploit lower-gas-content coals in Alberta, Alberta Energy is going after the deeper, higher-gas-content coals in a region known for its thick beds and metallurgical-quality rock. "British Columbia lacks infrastructure but it has the best coal resources. On the other hand, on the Plains we have coals that are areally extensive and are situated above infrastructure," explains Wojahn, who oversees the company's CBM pilots in British Columbia. "So it's quality-of-resource versus utilizing existing infrastructure. The industry really doesn't know which camp is going to work." Alberta Energy spent approximately C$25 million in the past two years on land, seismic, drilling and testing in Elk Valley, a long-time coal mining area in the province's southeastern corner. Amid rugged terrain near the small town of Sparwood, the company has drilled seven appraisal holes as well as two pilot pads, each containing five wells, with the maximum depths reaching 1,100 meters. AEC has also drilled three wells in the Grizzly Valley near the coal-mining town of Tumbler Ridge in northern British Columbia. The firm has put further drilling on hold as it discusses joint development with other firms that have conducted CBM work in the region. Topography and weather are among the differences between the U.S. and Canada when it comes to CBM, says Wojahn. "In foothills operations, like where we are in Canada, surface access is a major issue. You just don't drive a truck up and start drilling," he says. "It's not the same terrain so cost structures are obviously different." He says his firm is climbing the learning curve in areas such as handling coal fines-tiny particles that plug up fractures and damage pumping equipment. The company is still mulling its budget for this year, with spending on the phased Elk Valley project possibly going as high as C$25 million. The amount will depend on gas prices, success and a new government royalty regime for low-productivity wells. Burlington Resources Canada expects to spend C$12 million this year on unconventional resources, including coalbed-methane and tight gas. The company will test coal in several areas, with much of the focus on deposits in central Alberta. The rights to the gas trapped in coal came with its parent's 1999 acquisition of Poco Petroleums Ltd. for C$2.6 billion. Some properties in the region owned by Canadian Hunter Exploration Ltd.-more recently purchased by Burlington for C$3.3 billion-could also be included in the pilots. But Ellis, who once ran Burlington's San Juan division in Farmington, New Mexico, says Canadian coal is unlikely to replicate the same attractive characteristics as the San Juan's Fruitland deposit, which is the biggest and best coal-gas producer in the world at this time. "My guess is that Canada is going to perform much more like the tighter coals than the Fruitland coal," he says. "But it's a little early for us to say because we're still testing some opportunities." Burlington Resources Canada is tapping the human resources of its parent, which derives 320 million cubic feet per day from the San Juan Basin. It brought a couple of experts from U.S. operations to Calgary to augment the existing pool of technical knowledge. Tax breaks in the U.S., particularly helpful in the early 1990s when gas prices tanked, are a big reason for the U.S. lead in CBM. While firms such as Burlington have operational experience, many observers believe Canadian firms can catch up. "Each coal deposit has to be understood on its own merits," says MGV Energy's Gatens, who has almost two decades of experience in tight sands, CBM and shales, mostly in the U.S. "If you come here and think it's going to be a cookie-cutter imitation of something that you've done somewhere else, then you're going to the back of the class." One company trying for a front-row seat is PanCanadian. It is devoting C$15 million to CBM pilot projects this year after spending C$12 million in 2001. In conjunction with MGV Energy, PanCanadian drilled 82 wells in 2001 and currently expects to drill at least another 35 this year. It is examining seams ranging from the Ardley to the Mannville, buried at depths ranging from about 200 to 1,200 meters. A big chunk of PanCanadian's test wells were drilled in southern Alberta, where it has a huge land base, existing infrastructure and extensive experience in punching shallow wells quickly and cheaply. The firm is using single drilling rigs and aiming for drilling costs of under C$100,000 for pilot wells on the Plains. The manager of PanCanadian's CBM program, Chow says his firm is also looking outside southern Alberta as it tries to determine which coals are best suited for CBM output. "We didn't want to focus on one specific area, take two or three shots and then say, 'That's our CBM program,'" he says. "We took a regional program and experimented with a lot of different technology, including some we developed, just to see how we could quantify the resource." The company, one of the largest conventional gas producers in Canada, has tried a variety of drilling, cementing and fracturing techniques, with varying results for gas and water production. Several industry sources report the company is using high-volume nitrogen fracs, involving as many as 10 pumping units, at some of its more successful wells. Chow says, "There have been surprises, but to be honest we've been pretty encouraged and we've actually accelerated our program. We've shortened our time cycles between exploration and the pilots and hopefully we'll make a recommendation on development a little earlier as well." The firm is looking for flowing pressures of less than 50 pounds per square inch, since desorption (the release of gas molecules physically adhering to the internal surface structure of the coal) increases as pressure declines. Environmental issues Dewatering the coal is critical to reducing pressure. Disposing of the liquid, a hot button in the U.S. and the subject of several different lawsuits, is a key environmental issue. All produced water-fresh or saline-in Alberta is to be disposed of underground. British Columbia allows surface disposal of freshwater subject to an environmental assessment and ongoing monitoring and sampling. With much of North America short of potable water, CBM's byproduct could be valuable to arid southern Alberta. Gatens at MGV Energy says the issue needs to be resolved, since freshwater is considered by statute a resource deserving to be conserved and managed. "We've got to work with the irrigation bodies, Alberta Environment and the Energy and Utilities Board to determine what kind of rules will govern the extraction of that water and how that water will be handled," he says. "We don't know about the quantity and quality of water...but it's possible we could treat it and make it usable. It could be a valuable asset to the province, but at the same time, it could create a burden on producers [if the water requires much treatment before being released.]" Royalty regimes could also use some adjustment, says Wojahn of Alberta Energy. While British Columbia is making changes to encourage CBM production, Alberta's existing structure for low-productivity wells does not reflect high capital costs incurred by producers during the dewatering phase. "It takes up to 18 months before the highest cash flows are realized. The royalty programs need to take that into account because you're spending all this money and not getting peak revenues for 18 months," Wojahn says. Smaller firms The need for large land-holdings and capital programs means the most active players on the Canadian CBM scene tend to be bigger firms. Ellis and others say small companies have done well in unconventional plays in the U.S., particularly the Powder River. However, the huge slump in gas prices in the past year favors bigger companies with the financial resources to ride out troughs, like the one currently engulfing the industry. "We have not altered our coalbed-methane program based on the current price environment," says Ellis at Burlington Resources Canada. "We're looking more toward the longer term, since coalbed-methane and other unconventional-resource plays are multiyear programs. You have to be a firm believer in the long-term fundamentals of gas and have the resources to weather the cycles to really commit to unconventional-resource plays." But some smaller firms are playing in the field. Priority Ventures Ltd. is working on a project on Vancouver Island while Osprey Energy Ltd. holds rights to coal gas on the opposite side of the country in Prince Edward Island. Another junior, Promax Energy of Calgary, is using its large land spread, some 330,000 acres near Cessford in southern Alberta, to gain an inside look at the still unproven play. The firm has teamed with Trident Exploration Corp., with the latter agreeing to spend C$2.5 million this year drilling 12 holes, including one deeper test that plunges 1,100 meters. Promax president Alex Lemmens thinks deeper and thicker coal deposits, such as the Mannville found about 850 meters underground, have good potential for CBM production. His firm is most interested in beds that are at least four meters thick. "It is a gas-charged environment, which is deep enough to give substantial reservoir volumes," he says. "If coalbed methane exists in the Western Canada Sedimentary Basin, there could be as much gas as there is in all of the Arctic and conventional basins combined." Lemmens says a large land position is important because it's likely commercial projects will be developed on 40-acre spacing, meaning 16 wells per section. Since Promax already owns seismic data and infrastructure, including a water-disposal facility, the foray into the unknown is "gravy on top of gravy," in the words of Lemmens. "There is no risk to us," he says. "We're going to drill this anyway, for the shallow gas, and we'll use our infrastructure to produce the coalbed methane. If Trident does produce the Belly River coal, their pressures will be the same as our shallow gas. If they do the Mannville, their pressure will be the same as our deeper gas. Since we have a two-level system, they could feed into either system." Alberta Energy's Wojahn says technology could be another barrier to smaller firms. Canada's asymmetrical deposition (with coal deposits progressively buried farther underground as one travels west) means existing technology cannot always be directly applied. "We'll take the learning that we can from parallels in the U.S., but Canadian coal technology really requires home-grown solutions that directly reflect the uniqueness of the coals that we're studying," he says. "We don't seem to have in Canada coals that lend themselves to a low-tech solution such as the Powder River-type coals, where a very simple process allows the completions to go forward." As the service side improves, more standardized applications could open the CBM door to smaller firms which may not have the desire or the financial resources to pioneer technology, Wojahn says. While big and small companies have been successful in the U.S. with CBM, all run lean and focus tightly on costs, say experts at Sproule & Associates who have consulted on CBM projects in the U.S., Canada and Mexico. Leslie O'Connor, manager of Sproule's Denver office, says controlling costs is critical to being successful in the niche. She estimates both U.S. and Canadian coal gas can be economic with a wellhead price of US$1.50 per million British thermal units. "Because of the immaturity of the CBM play in Canada, it will be at least five years before you're going to see a definitive effect on markets in terms of supply and demand," she says. Wojahn says Nymex gas prices probably need to average $3 to $4 per million Btu for CBM to be economic in Canada under current fiscal regimes. Record drilling in western Canada last year, fueled by strong commodity prices in the first half, contributed to a small increase in daily gas production. Decline rates in new wells are averaging 20% to 30%, but Ellis says it is much too early to say whether CBM can fill that gap. "I think there is a tremendous amount of potential out there. But to say it could be developed at a pace that could offset conventional production declines would be a pretty big stretch." One Calgary analyst has estimated Canadian CBM production during the next decade will climb to 1 billion cubic feet per day, or about 6% of current daily output. If the prediction is to come true, an explosion in commercial projects is needed. PanCanadian is the only firm talking about making a decision this year, and Alberta Energy, Burlington and others are a long way from making similar judgments. Sproule's Seidle succinctly sums up the near-term situation for CBM in Canada: "What happens in the next 12 to 18 months is going to be very critical for coalbed methane in Canada. It could be a very significant contributor to Canadian gas in five years or it could be completely off the radar screen. Most likely it will be somewhere between."

Comments