Coal bed methane the energy industry's next big play?
by Robert Simpson

In an open field, eight kilometres south of Corbett Creek, Alberta, a cluster of gas wells is pumping coal bed methane, the oil industry's next moneymaker - or so it hopes.

Though extracting coal bed methane (CBM) is a relatively new idea in Canada, a 20-year history of success in the United States has firms lining up to take the chance here.

How much of a chance is still anyone's guess. Canada is the world's 12 th largest coal producer and has huge coal reserves in British Columbia, Alberta and Nova Scotia. But nobody knows the resource's true potential, or even how much gas is recoverable.

"The resource estimates and the gas recoverability rates are all over the place," says Rob Woronuk, senior analyst, Canadian Gas Potential Committee.

According to the Canadian Gas Potential Committee, estimates of the CBM gas resource nationwide could range anywhere between 187 trillion cubic feet (tcf) to about 460 tcf. The Alberta Energy and Utilities Board estimates Alberta's reserves at 135 tcf to 410 tcf. Only 20 tcf of CBM will supply U.S. gas needs for a year.

"The real question is not how large the resources are but how much can be recovered and we just haven't had enough experience to determine that yet," says Woronuk.

San Juan Basin

Recoverable resources unknown

There are several uncertainties when trying to determine the amount of recoverable methane gas. Every CBM project is unique, and while some of the technology from the U.S. experience is helpful, the Canadian coal beds are typically less gassy and less porous, making it harder for the methane to flow to a well bore.

"Extracting CBM has some formidable technical challenges," says Tim Jeffery, director of investor relations for Nexen Inc. [NXY-TSE].

Coal bed methane is a natural gas found in most coal deposits and created over the millions of years it takes to convert plant material into coal. The methane in a coal seam is not stored as a compressed gas but absorbed chemically into the coal and held in place by the overlying rock and water pressure.

While CBM can be extracted using conventional natural gas technology, the similarity ends there. Methane can't be extracted until the water that permeates coal beds is pumped off because it traps the gas in the coal. This dewatering lowers coal bed pressure and is like taking the cork out of a bottle of champagne, the bubbles (methane) come to the top. Dewatering often means dumping 12 to 15 gallons of water a minute from each well -- a process that must continue for a year on average before maximum methane production kicks in.

Regulatory and Environmental

Regulatory and environmental issues associated with dewatering have many in the CBM industry concerned. "The question is what to do with the water," says Woronuk.

Here a lesson could be taken from the U.S. experience. Ask any rancher in the coal bed methane-rich Powder River Basin of Wyoming and they will tell you the biggest problem is the water. The state's CBM industry now produces enough water to supply thousands of people per day, but instead much of the water, which ranges from fresh to brackish, is simply spilled on the ground.

Not surprisingly the State is awash with lawsuits and land disputes and according to the Wyoming Wildlife Association, the massive development of coal bed resources is jeopardizing thousands of square miles of aquifers that feed the headwaters of the region's rivers and streams. Association spokesmen say that water resources are at risk that could be damaged for 200 to 1000 years.

In Canada, there is a stronger regulatory framework to build on, including established rules for water disposal, but the rules are still decidedly sketchy when it comes to CBM and differ in each provincial jurisdiction.

In Alberta, ground disposal of any kind of oilfield water is governed by the Energy and Utilities Board, while surface water handling -- unless it is stored in tanks -- falls under the jurisdiction of the Department of Environment.

Under the status quo, CBM developments would require a combination of permits from both authorities to proceed. But special circumstances unique to CBM production also require outright rule changes.

Alberta tightened environmental laws in 1999 to make surface discharge an unacceptable practice, despite exemptions granted to the coal industry for tailings ponds. Likewise, oil and gas operators are not allowed to have evaporation ponds under an interpretation of the current rules.

More serious than the issue of dispersing dirty water is the issue of what to do with fresh water produced from coal seams -- dewatering non-saline aquifers is against the Alberta Environmental Protection Act. Any other type of groundwater use requires diversion permits.

In September 2001, the Alberta Department of Energy delivered a report of CBM that recommended establishing subcommittees to look at specific sections where changes might be made, including environmental rules. But the report itself doesn't represent government policy and the lack of regulatory clarity adds another level of uncertainty.

Closer Zoom of San Juan Basin

Technical challenges

Although the exploration risk for finding coal beds is minimal, that's not where the risks end. The geological and technical risks are huge and make CBM production a capital-intensive proposition on par with Alberta's mega-project oil sands developments.

For starters, each CBM play is unique, requiring different techniques for drilling, completing and stimulating wells. If the coal bed is too shallow pressures are not high enough to absorb the methane on the coal surface and if it's too deep the pressure is shut off and collapses the fracture, making it impossible to retrieve the methane gas. Ideal conditions in Canada are between 400 and 1000 metres (1200-3000 feet) below the surface.

The San Juan Basin in Colorado holds its methane in 30 to 60 foot thick coal beds that lie 1,600 to 3,300 feet underground. The gas in the Powder River Basin lies in more permeable seams at a depth of 600 feet.

Production can be tricky and potential players need a large land base, as the wells produce at very low rates and it can take up to two years to reach peak levels. But once in production, the CBM well's production continues for several years -- some U.S. wells are still producing after 20 years.

The initial capital investments are huge and success is not guaranteed because the amount of gas that can be produced depends not only on the correct depth, but on the thickness and lateral continuity of the coal, the level of permeability that is controlled by the amount of fracturing or cleats, and other barriers such as impermeable layers and faults or folds that keep the gas trapped within the coal seam.

"The key to coal bed methane production is a large land position, as it requires a large coal seam to make the play economic," says Jeffery. CBM extraction also requires twice as many wells as a natural gas play. Instead of one hole per 640 acres, CBM demands as many as one well every 80 acres, costing between C$100,000 to 400,000 per well.

The challenge for all the companies involved in CBM extraction is clearly to achieve economies of scale to be competitive with U.S. producers who have drilled more than 13,000 wells since 1990 and

produced 3.5 billion cubic feet of gas per day last year.

Drilling wells cheaply and efficiently is what will make or break economies. Several Canadian technologies, such as coil tubing and horizontal drilling, will help with the tricky task. But they will have to be modified to deal with the uncertain nature of CBM.

New Technology

For almost six years, the Alberta Research Council has been working with the Canadian, U.S. and other governments to enhance methane recovery by injecting carbon dioxide from large producers of greenhouse gases into coal beds. The technique has helped increase recovery from the San Juan coal beds, but research in Alberta is still inconclusive.

The process is called enhanced coal bed methane recovery and is similar to the popular practices of using CO 2 injection to enhance

production from oil reservoirs. In this method the injected CO 2 is

absorbed by the coal and stored in the pore matrix of the coal seams, releasing the trapped methane that can be sold for a profit. The process results in two or three molecules of CO 2 absorbed for each

molecule of methane released. In this closed process, the CO2

produced from the coal-burning or methane-burning power plants is injected into the CBM reservoirs to produce more methane, and the cycle continues.

Speculation is that over the next five years Canada could see as many as 1000 CBM wells and the gas play could be as large as 1 billion cubic feet -- significantly less than the Canadian Gas Potential Committee's estimates of up to 486 tcf leading some to speculate that CBM will not offset North America's dwindling natural gas reserves in any significant way. Time will tell.