Big news: In March, the government of Alberta announced that -- for the first time in its 100-year history -- the province was home to more than $100 billion worth of major projects that have been recently completed, are currently under construction or are scheduled to begin within two years.
Bigger news: Energy investment leads the pack, with $69 billion allocated for projects in oil sands, $6 billion in oil and gas, $2 billion in pipelines and $4 billion in power projects.
Biggest question: What happens next?
Jim Dinning, a top energy executive and a well-known public figure in Alberta, has some suggestions for Alberta’s future prosperity, and it involves moving beyond a simple oil and gas economy to integrating less attractive or marginalized carbon fuels like coal, coke, asphaltenes and biomass into the energy pyramid.
According to Dinning, the Alberta government must invest more of its windfall profits from oil and gas royalties into research and development that will transform the province into "the clean energy powerhouse of the world."
Dinning is the former executive vice-president of TransAlta Corporation, a power company and Canada’s largest producer of wind energy and, until recently, chairman of the Canadian Clean Power Coalition. He envisions the construction of a multi-billion dollar, clean-burning coal facility that will reduce the province’s reliance upon natural gas, a commodity that is subject to price volatility and increasingly constrained by supply in North America.
He wants to "put the margin back into marginal carbons.
"If you put all your eggs into another basket, especially one like natural gas, you can get hooked," Dinning said. "The last thing that we want to do is to shut down those carbons that are marginal."
Dinning -- the provincial government treasurer from 1992-97 who’s preparing to take a run at Alberta’s top political job -- said the gasification of marginalized carbons to produce energy will enable Alberta to meet its expanding energy needs and exceed emissions reductions under the Kyoto Protocol by up to five times.
"We want to be on the leading edge of design technology and eliminate emissions through the technologies that we develop, rather than through regulation," he said. "An international protocol (Kyoto) shouldn’t dictate what should happen in Canada and, in so doing, hobble a carbon asset. Kyoto can’t match a made-in-Canada solution."
Dinning called for Alberta to increase R&D spending to levels enjoyed during the hey-day of AOSTRA (Alberta Oil Sands Technology and Research Authority). Then, during a 20-year period, AOSTRA received nearly $1 billion in government support for R&D studies that are widely credited in the development of a commercial oil sands industry.
"In energy research, the Alberta government is doing more than any other province," Dinning said. "Is it enough? The answer is no."
Kicking the (Natural Gas) Habit
According to Dinning, "injecting natural gas into the oil sands to produce oil is like turning gold into lead."
In a 2004 report on Canada’s oil sands, the National Energy Board stated that natural gas costs can comprise up to 50 percent or more of total operating costs in a thermal -- or steam assisted -- in situ project.
Dinning described gasification technology that offers an elegant solution to the natural gas crunch that Alberta’s heavy oil producers will face during the next decade. According to a 2004 Canadian Energy Research Institute (CERI) report, natural gas consumption for oil sands extraction and refining -- currently sitting just below a billion cubic feet per day -- could skyrocket to between 2.2 and 3.7 billion cubic feet per day by 2017, leaving many wondering where the gas will come from to fuel future expansions.
Even the proposed Mackenzie Valley pipeline -- scheduled to ship 1.8 billion cubic feet per day from the Canadian Arctic to Alberta -- would not feed the oil sands producers’ growing appetite for natural gas.
However, CERI’s study predicted a "very robust future" for Alberta’s oil sands industry during the next 13 years -- given a "reasonable" outlook for oil prices. The study was based upon conservative commodity prices -- US$25 per barrel for West Texas Intermediate and US$4 per million British thermal units for natural gas.
The stakes are huge. With 2.5 trillion barrels of crude bitumen in place, and remaining established reserves of 178 billion barrels, Alberta’s oil sands are second only to Saudi Arabia’s total reserves. In 2004, Alberta’s oil sands industry produced about a million barrels per day, or close to 50 percent of Canada’s total daily oil production. Based on CERI’s most likely growth scenario, daily production from Alberta’s oil sands could hit 2.2 million barrels of synthetic crude and unprocessed crude bitumen by 2017.
Derivatives of the gasification process include value-added products for Alberta’s energy economy:
- Hydrogen, needed to upgrade heavy oil.
- Synthesis or "syngas," to generate electrical power and steam.
- Carbon dioxide to inject into subsurface reservoirs for enhanced oil recovery projects.
- Ammonia and urea, feedstocks of the petrochemical industry.
"Alberta is the sweet spot where geology meets geography," Dinning said of the plans for a clean coal facility near Edmonton. "Virtually no other place in the world has all of the elements where they come together in such an integrated fashion."
While environmentalists often describe "clean coal" as an oxymoron, proponents point out that the gasification process generates emissions comparable to those produced by natural gas power plants. The ability to "fix" carbon dioxide (the main greenhouse gas), nitrogen and sulfur into feed stocks for the petrochemical industry means that emissions can be further reduced.
Gasification technology has been successfully used in the refining, petrochemical and power industries since the late 1940s. The two global leaders are the Royal Dutch/Shell Group of Companies and the General Electric Company. GE Energy currently operates 16 facilities in the United States, 22 in Europe and 27 in Asia. Globally, GE Energy produces more than five billion cubic feet per day of syngas. According to a GE spokesperson, the company is targeting China, the United States and Alberta for new business opportunities.
OPTI Canada Inc.’s Long Lake project, 40 kilometers southeast of Fort McMurray, will employ Shell’s gasification technology to produce syngas, power and hydrogen from asphaltenes, the bottom or heavy ends of the oil barrel. The 21,000-hectare Long Lake oil sands lease is estimated to contain 7.1 billion barrels of bitumen in place. Phase One will develop a 6,700-hectare area containing an estimated 1.1 billion barrels of recoverable bitumen reserves and resources.
OPTI’s project represents the first commercial gasification project in Canada. Operated as a 50/50 joint venture with Nexen Petroleum Canada, the $3.4-billion Long Lake project is also the first SAGD (Steam Assisted Gravity Drainage) operation in the Athabasca oil sands region to include onsite upgrading and refining capabilities.
OPTI’s unique combination of extraction and upgrading technology makes it the poster child for the new wave of energy efficient oil sands mega-projects.
At Long Lake, the liquid asphaltenes are sent to the gasification unit where they are converted into synthetic gas (or refinery off-gas), steam and hydrogen. The synthetic gas, or "syngas," has a heating capacity of about 300 British thermal units per standard cubic feet, as compared to 1,000 British thermal units/standard cubic feet for natural gas.
The syngas will be used to generate steam for the SAGD process. Instead of flaring excess syngas, this "free" energy source will be harnessed to generate power onsite in the cogeneration facility.
Excess power will be sold to Alberta’s deregulated power grid.
Bridge to the Hydrogen Economy
According to the Canadian Clean Power Coalition (CCPC), a national association of coal and coal-fired electricity producers, North America’s hydrocarbon reserves are skewed by coal, which comprises 92 percent of the reserves; oil and gas total the remaining 8 percent.
Alberta’s coal reserves -- often described as infinite -- are immune to the price fluctuations seen in natural gas.
"Coal is not a carbon that should be shelved," Dinning said. "Coal is not only cheap, it’s not volatile."
According to Dinning, 70 percent of Alberta’s electricity is generated through conventional coal fired facilities.
In 2004, the CCPC released the results of a two-year study on clean coal. "Gasification is the right technology for coal in the future," explained Dinning. The study contemplates the construction of a $2 billion to $3 billion demonstration plant, most likely in Alberta, by 2010.
Dinning’s comments were echoed by Duke du Plessis, a senior advisor with Alberta Economic Development and the Alberta Energy Research Institute (AERI). AERI is one of three Canadian government participants in the CCPC.
"I think the conditions are right for this technology to come into commercial use," du Plessis said. "Coal is the bridge to the hydrogen economy that everyone talks about. Hydrogen is a clean fuel, and is increasingly being viewed as a fuel of the future."
However, it is unclear who will pay for the demonstration plant.
"The barrier is going to be getting the funding in place," du Plessis said.
"Why hasn’t the coal utility business done this before? Because we haven’t had to," Dinning said.
Market forces and the need to reduce greenhouse gas emissions under the Kyoto Protocol, he added, are powerful agents of change and energy integration.
Coke: A New Energy Source
Alberta’s oil sands contain dense and viscous bitumen with a high ratio of carbon-to-hydrogen molecules; in other words, they are hydrogen deficient compared to conventional crudes.
Upgrading to a synthetic crude can be accomplished by two methods:
- Coking, which rejects carbon molecules. This process produces a solid, coal-like waste by-product.
- Thermal hydrocracking, which adds hydrogen molecules.
Suncor Energy Inc. and Syncrude Canada Ltd. operate Alberta’s two largest oil sands mines near Fort McMurray, complete with onsite upgrading and refining capabilities. Both companies create deasphalted oil through a coking process. OPTI’s OrCrudeÔ process, in comparison, creates upgraded synthetic crude through thermal cracking.
In March, Suncor filed a regulatory application to construct a third oil sands upgrader at its mine site near Fort McMurray -- preliminary cost estimates are $5.9 billion, with an additional $600 million to build a petroleum coke gasifier. According to Patty Lewis, a spokesperson for Suncor, the addition of a third upgrader will boost production to 550,000 barrels per day by 2012.
The coke gasifier will be the first of its kind at an oil sands mining operation.
Lewis described the coke gasifier a "key component" of Suncor’s expansion. However, she categorized the gasification project as "early days." Suncor expects that gasifier will consume about 20 percent of the coke produced from the new upgrader.
"We’ve got a long way to go to prove this technology," she said, "but we’ve got time on our side, and the technology is evolving."
Using coke as an alternative energy source -- while seemingly attractive -- presents some challenges for Alberta’s oil sands industry:
- On the one hand, a coke pile represents a waste by-product from the upgrading process that can be gasified to produce energy.
- On the flip side, a coke pile is a valuable carbon sink, and a commodity that can be used in the future to offset greenhouse gas emissions under the Kyoto Protocol.
Suncor has been burning sulfur rich coke in its boilers for decades at its mine near Fort McMurray. However, the gasification of the coke -- which will liberate carbon dioxide gases -- must be offset by carbon dioxide capture and sequestration. And, that might require the construction of a pipeline to transport carbon dioxide south where it could be used in Enhanced Oil Recovery (EOR) projects or sequestered in depleted oil and gas reservoirs.
The challenge, according to Lewis, "is how do we build this gasifier and fulfill our commitments to Kyoto?
"Suncor is weighing the balance between a good business decision and long-term environmental responsibility," she added.