Gas development is accelerating in Canada, according to two government agencies that report healthy signs for reserves and production. In Alberta, still the source of about four-fifths of Canadian gas, production companies have nearly doubled their performance in the field. In 2000, a record 8,228 gas wells replaced 90% of the year’s production, the Alberta Energy and Utilities Board said in an annual review. In 1999, it took 6,015 wells to replace 56% of the province’s gas output.
Viewed as a whole from a national perspective rather than the old Alberta mainstay of production, Canadian supplies look stronger yet. Natural Resources Canada’s gas division said in an annual review and forecast that “production seems to be rising at a healthy rate–3.6% in 2000. The rate of production increase also appears to be accelerating. Admittedly, this is based on statistics to date (late spring), which are still preliminary. However, production will clearly be in much better shape this coming winter than it was last year.”
The federal department’s report reminded markets that the West is no longer the only place to look for Canadian supplies. The East Coast has become a factor, with production now under way and new drilling and development accelerating offshore Nova Scotia in the Sable Island region. “Although Canadian production overall grew 3.4% in 2000, most of this was from Sable Island. Western Canadian production grew only 1.4% last year.”
Yet the jury remains out on the West too, with deep and remote drilling plays still developing in northern British Columbia and Alberta as well as southern parts of the Northwest Territories which are within reach of pipelines. In northeastern BC, a single discovery known as Ladyfern has increased production by an estimated 400 MMcf/d, and the drilling it set off is continuing.
In Alberta, about half of the year-2000 wells were still low-cost, shallow efforts in the southeastern plains region of the province, where fast new methods of drilling are being compared to farm harvesting. Deeper and slower-moving exploration plays in remoter, harder terrain along the foothills of the Rocky Mountains remain in the developing stages.
Remaining Alberta reserves were estimated at about 43 Tcf as of the end of 2000, up slightly from 42.8 Tcf a year earlier. The AEUB is forecasting modest production increases in Alberta for the next year or two. But between 2005 and 2010, the AEUB expects the province’s output to shrink by about 2% per year unless more ambitious drilling for costlier but larger targets accelerates. The western Canadian industry continues to suffer from the effects of its late-1990s switch to a diet made up almost entirely of easy but small shallow drilling as a result of the period’s depressed oil and gas prices. Quick-hit wells generate instant sales and revenues, but relying on them affects productivity.
The AEUB reported that Alberta wells completed and connected in 1997 and 1998 recorded an average 32% decline in output during their first year in production. In 1990-91, the decline rate hovered in a range of 12-17%. Unless the pattern changes, annual Alberta gas production is projected to peak at about 5.3 Tcf in 2003 then fall gradually to about 4.8 Tcf by 2010. Among the unknowns are prospects for tapping vast coal deposits that carpet much of Alberta for gas. The AEUB said “coalbed methane holds the potential for significant reserves.” However, “there is a lack of information, particularly reservoir and production data, to enable a reasonable reserves assessment.”
In BC, which is likewise studded with immense coal deposits, the Geological Survey Branch in the provincial Ministry of Energy and Mines likewise says coalbed methane reserves are almost certain to run into many trillions of cubic feet. But also, as in Alberta, the geologists say coal gas remains too little tapped in Canada even by technical trials to generate reliable projections.
At an annual convention of the Canadian Society of Petroleum Geologists, BC survey staffer Barry Ryan observed that the coal-gas resource is almost certain to be immense. “British Columbia has a measured coal resource of over three billion tons. This is really an estimate of coal available for surface and underground mining. It is therefore to some extent an estimate of the coal resource not available for coalbed methane exploration because it is too shallow. The estimated coal resource to a depth of 2,000 metres (about 7,000 feet) is in the range of 250 billion tons, and it is this tonnage that is the resource base available for coalbed methane exploration.”
Another BC geologist – Marc Bustin, from the University of British Columbia’s earth and ocean sciences department – pointed to “vast resources” lying untapped even in easily accessible coal deposits. One example, known as the Ardley coal zone, occurs at depths of 2,200 feet or less in a geological structure called the Paskapoo Formation that carpets much of 24,000-square-mile south-central Alberta. Bustin reported that many of the Ardley seams are as thick as counterparts in the prolific Powder River Basin in the United States, where 9,400 wells have been drilled. There have been fewer than 15 known test wells into the Ardley coal zone, generating very preliminary estimates that it harbors 20-25 Tcf of gas. Ryan said “the gas is in the coal, and sooner or later the forceful combination of economic incentive and human ingenuity will get it out. Let’s hope sooner rather than later.”
While small by U.S. standards, there are signs of interest in coalbed methane in the Canadian industry. Nexen Inc. (formerly Canadian Occidental) is planning an exploration program. Over the past two years, the gas industry has paid about C$20 million (US$13.3 million) for coalbed exploration rights in southeastern and northeastern B.C. Canada’s top gas producer, Alberta Energy Co., has obtained permits for 13 test wells into a coalfield known as Elk Valley in southeastern BC. BP Energy Canada has taken out four permits for coal-gas drilling in northeastern BC.
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