Alberta oilsands projects will eventually burn more than half of the province’s natural gas production if current development trends continue, new forecasts show.
Gas use in the northern bitumen belt will jump by about 167% to 3.2 Bcf/d within 20 years, predicts the latest in an annual series of northern bitumen belt reviews by the Canadian Energy Research Institute (CERI), an independent agency supported by industry and government funds.
Over the same period, Canadian consensus projections collected by the National Energy Board (NEB) show Alberta gas production dropping by 35% into a range of 5.8-6 Bcf/d and then staying there as of the 2020s. The oilsands gas burn rate projected by CERI works out to 55% of future Alberta output.
The combined oilsands and gas supply trends are expected to change the energy trading relationship between Canada and the United States. “Considering how aggressively shale gas production in the U.S. has come on stream and the potential for shale production in Canada, meeting the industry’s future demand for natural gas should not be a concern,” CERI said. “It would be expected that Canada and the U.S. could be engaged in an energy exchange — Canadian oil for U.S. natural gas — that further enhances the trade relationship between the two countries.”
The CERI and NEB outlooks are both reference cases or outcomes rated as most likely to occur if the world and North American economies gradually recover from the 2008 global slump and energy prices just keep pace with a return to moderate currency inflation averaging 2.5% a year.
At 1.2 Bcf/d the current gas burn rate by Alberta oilsands complexes already equals the proposed initial capacity of the dormant C$16.2 billion Mackenzie Gas Project (U.S. dollar at par). The projections make little or no allowance for improvements in overall efficiency with gas in the bitumen zone, which spans 140,200 square kilometers (56,000 square miles) across Alberta, north of the provincial capital of Edmonton. Consumption is expected to continue averaging 0.6 MMBtu/bbl of production. Despite strenuous technical efforts, especially in the 2005-2008 high on the gas price cycle, gas use has remained stubbornly resistant to change.
The industry record has proved that not all oilsands deposits are equal, CERI pointed out. Gas use ranges from a minor issue at open-pit mines into shallow formations to 2 MMBtu/bbl of output from in-situ, underground production of layers deeper than 75 meters (250 feet) beneath the northern forest and muskeg swamp.
Difficult geological formations or poor quality reserves continue to elevate requirements for injections of gas-fired steam by in-situ projects that heat the bitumen underground into separating from the sand and flowing to the surface, the research agency said. At the same time, the proportion of oilsands production from in-situ projects is on the rise, with total gas use by the thermal projects offsetting reduced burn rates by the most efficient sites.
Only about 20% of Alberta bitumen is within reach of surface mining. Spectacular open pits, worked with jumbo trucks and shovels made on the scale of houses and apartment buildings, are concentrated in a city-sized area of intense development north of Fort McMurray that is readily accessible by road and the focal point of almost all environmental criticism of the industry as “dirty oil.”
Bitumen mining production is forecast to rise to 2 million b/d from 850,000 b/d. But in-situ output is expected to grow faster to 3.3 million b/d from 600,000. As a result, natural gas-burning thermal projects will account for a 60% and growing share of increasing production. The mining share, currently about 60%, will shrink to 40%.
Low natural gas prices have reduced the energy market incentive to improve the efficiency of thermal oilsands plants since 2007. But at the same time the industry faces a potentially steep increase in costs of complying with Alberta environmental regulation that includes steadily rising penalties for emissions of carbon-dioxide blamed for global climate change.
Unless green performance improvements are made, CERI forecasts that annual carbon-dioxide emissions by oilsands production will climb to 159 million metric tons from a current 45 million. The regime includes a little-known but active carbon cap-and-trade system that has been a one-of-a-kind Alberta institution for about five years. Industrial operations that emit more than 100,000 metric tons of carbon dioxide per year and fail to hit reduction targets set by the government must either buy audited carbon credits generated by cleaner industries inside the province or pay a penalty tax.
The provincial cap-and-trade regime increased the penalty to $20 per metric ton of excess carbon emissions as of 2012 from $15. After this year, the tax is scheduled to increase by 4.5% each year. As of 2011, the green tax collected $257 million and turned the cash over to the Alberta Climate Change and Emissions Management Corp. The venture is a nonprofit agency created by the government with industry veterans at the helm and a mandate to put the money into clean energy projects using cost-sharing deals with investor-owned enterprises.
CERI calls the Alberta carbon control regime “a rather hefty incentive to innovate” that is liable to add up to $200 billion in potential penalties for sticking with the industrial status quo over the next 35 years. The research institute estimates that total, annual oilsands greenhouse-gas emissions compliance costs — plant improvements, carbon credits and the carbon tax — will gradually increase to $12 billion as of 2045 from $747 million in 2011.
But the forecast rewards of oilsands development are so high that not even natural gas and environmental compliance costs are expected to slow down the action significantly.
“The oilsands are highly profitable, and an extremely good investment for oilsands operators, as well as the provincial and federal governments,” CERI said. The Alberta treasury alone is forecast to collect C$1.2 trillion in royalties over the next 35 years. Supply costs for the emerging generation of new projects — including a 10% rate of return on investment, as well as gas and environmental compliance expenses, are estimated to be C$44.75/bbl for in-situ bitumen, C$61.05/bbl for mined bitumen, and C$89.62/bbl for the Alberta industry’s top-of-the-line product of mined bitumen that is fully upgraded to refinery-ready synthetic light oil.
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