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Oil sands under the gun Multi-year drought builds pressure for tougher conservation measures Gary Park Petroleum News Calgary Correspondent
After years of crippling droughts across much of Alberta, the provincial government and environmentalists are making a case for revising water management policy.
New measures could impose an added burden on the costly process of extracting 177 billion barrels of recoverable deposits in Alberta’s oil sand, interfere with enhanced recovery from conventional oil wells and set up obstacles to the emerging extraction of coalbed methane gas.
The government released a draft water strategy March 27 that proposes a pricing system, polluter charges and other “economic tools and incentives” to promote water conservation and change user patterns. The document declares Alberta aims to “eliminate uses for fresh water that remove it from the water cycle.”
Calgary attorney Brian O’Ferall, who represents energy companies, landowners and environmental groups, told a forum March 24 that the strategy will have consequences for the industry.
The independent Pembina Institute for Appropriate Development, in findings released April 10, urged the province to start charging industrial users to help conserve supplies.
“The single most effective mechanism to influence conservation and efficient use of any resource is achieved through a pricing signal,” said a new Pembina report. “The need to charge a realistic price for water has been recognized at both national and international levels.”
Environment Minister Lorne Taylor said Albertans have “clearly told us that all aspects of society, not just governments, need to be involved in water management and decision-making.”
However, Premier Ralph Klein softened the immediate threat to the oil patch, telling the legislature that exploration and production must be allowed to “take place without unduly putting a hardship on companies that are putting up millions of dollars to explore and produce. Energy is the primary engine that drives the economy of this province.”
Alberta Environment has calculated that since 1950, the amount of water licensed for use has soared to 2.1 trillion gallons from 236 billion gallons, with 47 percent going to irrigation, 25 percent to cool power plants, 11 percent for municipal uses and only 4.5 percent being consumed by the oil patch.
Steam use in oil sands But that share could be headed for an exponential rise as producers increasingly turn to steam-injection methods to extract bitumen from Alberta’s oil sands region — a process that uses about three barrels of water to produce one barrel of petroleum products.
Those involved in developing and using water-dependent technologies include most of the big names in the industry, with about half of Alberta’s oil production dependent on fresh water, according to some estimates.
EnCana’s Foster Creek project is the world’s first commercial plant to employ steam-assisted gravity drainage and is being joined by the Christina Lake venture. The company has an estimated 30 billion barrels of oil sands resource on its land and is targeting volumes of 100,000 barrels per day.
Petro-Canada launched its 30,000-bpd MacKay River project last fall, is advancing its 80,000-bpd Meadow Creek development in partnership with Nexen Inc. and is planning a third steam-injection project. In addition, it is spending C$5 billion to reconfigure and expand its Edmonton refinery to process 170,000 bpd of bitumen, replacing 85,000 bpd of conventional light crude that currently is handled by the refinery.
Imperial Oil’s Cold Lake project is on track to produce 180,000 bpd later this decade, while ConocoPhillips Canada, Canadian Natural Resources and Suncor Energy all are working on plans for steam technology projects.
Industry leaders, anxious to avoid conflict, have indicated a willingness to consider more stringent conservation, but are calling for a cost-benefit analysis before any proposal becomes official policy. They want to ensure that any measures apply consistently to all sectors and don’t discriminate against oil and gas.
Options include pressure on the industry to recycle water used for enhanced recovery and to use saline groundwater rather than fresh water whenever possible.
The Canadian Association of Petroleum Producers has noted that the government’s requirement for companies to use saltwater before tapping into fresh water has boosted saline use 10-fold and lowered fresh water injection by 80 percent over almost three decades, although some water in the enhanced recovery process is removed from the cycle.
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