Before the first commercial oilsands mine started up in 1967, owner Suncor Energy built a dike around a sandbar in the Athabasca River adjacent to its plant, known as Tar Island. The low-lying basin was meant to capture the tailings, mostly sand and clay but also some toxic chemicals left over after removing most of the bitumen, or tarry oil, from the ore. As time went on, though, the tailings did not settle, bond and dry out as expected. As the level of the pond rose, Suncor repeatedly raised the dike, and built more ponds.
Today the Tar Island dike looms about 100 metres above the river and the plant, almost to the level of the surrounding northern Alberta benchland. Until recently, it was a monument to the industry’s shame, a liquid waste problem for which oil companies had no solution. But instead of the black and lifeless lake that lay impounded behind it just two years ago, now there is a firm, rolling meadow sprinkled with snags for hawks to roost on and boulders to create wildlife habitat. Where the earth is bare, it is marked with deer tracks.
“This is a day that many of us at Suncor have been looking forward to,” Suncor president and CEO Rick George told gathered politicians, reporters and Suncor employees at a reclamation ceremony at the renamed Wapisiw Lookout on Sept. 23. “We said we’d be the first in the industry to reclaim a tailings pond, and we delivered.”
As recently as 2006, such an event would have been unthinkable. That was the year Suncor, unsatisfied with the results of its existing consolidated tailings program, began testing a new process called tailings reduction operations, or TRO. This time the company dredged up the stubborn mature fine tailings after just three years of settling in the pond, added a polymer and pumped it onto a sloping beach to dry—which it now did, to a chunky clay, in a matter of weeks. The technology can reclaim in just a few years what previous methods could not do over four decades.
Attacking tailings accumulated over that entire period, Suncor has reclaimed its first pond, is working on another two and has five more it plans to drain over the next two decades, expecting to reduce the surface area of its tailings ponds by about 80%. “Eventually, we’ll come to the point we’ll just have one operating pond at a time,” George told reporters at the ceremony. The company also plans to share its technology with other producers—for a price.
Suncor’s victory over tailings hasn’t yet altered the sludgy imagery opponents of oilsands development favour in their documentaries and advertising campaigns, though. More than any other image, it is toxic tailings that sells the message of the oilsands as a “dirty” source of oil. In fact, TRO is just one of many advancements different companies and researchers have developed in recent years not only to help remedy the sins of the past but to ensure the oilsands operations being started up today and in the near future will be substantially cleaner than the ones on which the popular image of the resource is based. The dirty-oil label undeniably fit a history characterized by massive and long-term disruption of the landscape, lakes of toxic wastewater and carbon emissions from extraction and upgrading as much as 50% greater than that of conventional oil. But it doesn’t match the new projects expected to double or triple the industry’s output that, realistically, represent the nub of the debate. Indeed, within just a few years there will be oilsands operations as clean as the only immediate alternative: imported conventional oil.
An inescapable fact is that the oil consumed in North America is getting dirtier. A bit of history: when the famous Leduc No. 1 well near Edmonton blew in 1947, launching Canada’s modern oil and gas industry, the gusher pushing skyward was said to be light and pure enough to pour into your gas tank. With much of the world’s accessible, light crude of this sort now exhausted, more and more of the oil we consume comes from heavy grades (the so-called bitumen derived from oilsands being among the heaviest) that require more refining and therefore entail higher emissions and other undesirable byproducts. In addition, oil imported to the United States—with the exception of Canadian bitumen—comes from farther and farther afield, often from countries like Nigeria with dubious environmental accountability, meaning its well-to-wheels carbon footprint, including diesel burned shipping the stuff by tanker, is increasing. (If you expand your definition of “dirty” to include resources from countries that abuse human rights, disregard labour standards or fund terrorist organizations, as conservative commentator Ezra Levant does in his new tome, Ethical Oil: The Case for Canada’s Oil Sands, the range of options shrinks even more.)
Two independent studies commissioned by the Alberta Energy Research Institute in 2008 concluded that the life-cycle carbon emissions (including burning it in your car engine) of oil derived from the oilsands was just 10% greater than the average from all sources and slightly less than that from the heavy-oil industry in California, a state that has adopted a low-carbon fuel standard that would exclude the product of the Canadian oilsands. (In fact, the volume of Alberta crude that ends up in California is, by dint of pipeline configurations, negligible.) A similar wells-to-wheels study released in September by IHS Cambridge Energy Research Associates out of Massachusetts found fuels derived from oilsands to be just 6% more carbon intensive than the average of all oil sources consumed in the U.S.
As it is, synthetic crude from the oilsands is 38% less carbon-intensive than it was 20 years ago, thanks to productivity improvements as simple as using larger dump trucks to transport the ore rather than smaller dumpers and conveyor systems. Suncor reports that it has cut its greenhouse-gas emissions (GHGs) per barrel by 45% over the same period.
Then consider the evolution of the industry itself. The oilsands layer in northern Alberta can be thought of as a Frisbee stuck diagonally in the sand at a beach. Only the very northern end, north of Fort McMurray, emerges at the surface and can be mined. Four-fifths of the recoverable resource lies deep underground in places like Conklin, Peace River and Cold Lake where, in 1985, Imperial Oil began the first in situ, or oilsands drilling operation using a technique called steam-assisted gravity drainage (SAGD, pronounced “sag-dee”). Currently, 44% of oilsands production is in situ, and Alberta’s Energy Resources Conservation Board anticipates it will surpass 50% by 2015.
In other words, most current and future expansion in the oilsands will be in situ projects, and these will not be encumbered by two of the three biggest knocks against the oilsands: radical surface disruption and tailings ponds. SAGD projects typically involve a central plant where steam is produced and piped to nearby drill pads, then down to the oilsands layer where it melts the bitumen, a semi-solid form of oil, into a consistency fluid enough to be collected in horizontal well bores and pumped back up to the surface. By and large, the surrounding forest and wetland are left intact and can be returned to a wild state relatively readily following the completion of industrial activity. Yet you don’t see these in the current “Rethink Alberta” ad campaign, or in any of the imagery coming from the environmental movement. You instead see the strip mines and ponds.
SAGD still has the problem of carbon emissions, mostly produced in the generation of steam. In fact, the carbon intensity of the in situ sector is higher on average than the mining side. However, this industry is younger than oilsands mining, and is still perfecting its techniques. Newer SAGD plants such as Connacher Oil and Gas’s Great Divide have managed to nearly eliminate fresh water use—they use non-potable water from aquifers and recycle it—and reduce GHG emissions by about 20% compared to the industry average through more efficient burning of natural gas, cogeneration of electricity and reduced heat loss on the steam’s journey underground. Further pilot projects by juniors and majors alike, such as Laricina Energy’s use of solvents in combination with steam, promise to further reduce the emissions associated with SAGD. Cenovus Energy, one of the largest SAGD producers, is also experimenting with solvents in the field. Norway-based Statoil ASA, which plans to start up its Kai Kos Dehseh project later this year, recently set itself the goal of cutting its emissions there by 40% within 15 years.
Still, getting carbon emissions from in situ projects down near the level of conventional oil will take more than that, which is where the new alternatives to SAGD come in. In late 2008, Nexen and Opti Canada started up their Long Lake operation, which was a first among major in situ projects in that it gasifies the on-site bitumen resource itself rather than burning natural gas from the North American pipeline grid to generate its steam. Production results from Long Lake’s startup have been disappointing—as of July, it was producing 28,500 barrels per day instead of the 55,000 it was expected to by now—but it has met environmental expectations.
More promising may be a system called toe-to-heel air injection (THAI), developed by Petrobank Energy and Resources. THAI foregoes steam (and therefore water use) altogether, instead liquefying the bitumen with an underground “fire front.” Technically speaking, this so-called combustion process still produces carbon dioxide, but most of that is left underground rather than being emitted into the atmosphere.
Petrobank has demonstrated THAI for four years now at a pilot project called Whitesands, and its encouraging results have helped make the company a darling of the TSX. (As important to its market value as its oilsands properties is its intellectual property, which Petrobank has already licensed to companies including True Energy Trust and Baytex Energy Trust, its partner in the Kerrobert heavy-oil project. THAI is not only applicable to the oilsands but to heavy-oil reservoirs worldwide.) Not only is THAI more environmentally friendly than SAGD, it will produce 17% more oil from the same reservoir, McDaniel and Associates Consultants concluded in a recent assessment of the project. That makes it much more attractive to other producers, even in the absence of onerous CO2 restrictions. This year, the company is ramping up a much larger oilsands project called May River.
THAI may be the leading alternative in situ process to SAGD in operation right now, but it is not the only one. Privately held E-T Energy in 2008 launched a 1,000-barrel-per-day pilot called Poplar Creek using electricity to heat the bitumen underground. Depending on the source, electricity can be renewable and emissions-free, in addition to which the company claims its process may be the most cost-effective out there, coming in at about $10 a barrel in operating costs and $10,000 per flowing barrel in capital costs. Meanwhile, Excelsior Energy, a junior recently acquired by Athabasca Oil Sands, plans to use its own version of combustion, Combustion Overhead Gravity Drainage, at a 1,000-b/d test well awaiting regulatory approval.
These are all things that have been or will soon be demonstrated in the field and hardly fit the description of dirty oil. But there are ideas demonstrated in the laboratory that could bring the oilsands’ carbon emissions and other drawbacks down to the level of conventional oil or even lower.
Privately held Value Creation, founded by former Royal Dutch Shell refining scientist Columba Yeung, originally intended to use a concept known as colloidal physics to upgrade the bitumen in the ground at its Terre de Grace property. Under recessionary strain, the company entered into an agreement this year with BP PLC to develop Terre de Grace using SAGD technology. Yeung maintains that the project will be able to incorporate Value Creation’s proprietary Accelerated Decontamination upgrading process, which means the oil brought to the surface will already be partially upgraded and refinery-ready. In July the company applied to Alberta’s Energy Resources Conservation Board to drill a 1,000-b/d pilot well.
A similarly magical process to colloidal physics is under development at the Alberta Ingenuity Centre for In Situ Energy at the University of Calgary. Pedro Pereira-Almao, a heavy-oil researcher who left Hugo Chavez’s Venezuela, has developed a catalyst that can “crack” complex bitumen molecules into simpler synthetic crude. In theory, producers could inject the catalyst into heated oilsands and perform most of the work of upgrading the bitumen in the reservoir—with little surface disruption, no tailings and no carbon emissions whatsoever.
“Harmful materials like sulphur compounds, metals, nitrogen compounds that will end up producing harmful gases or solids, we leave them there and just extract a good quality oil,” Pereira-Almao, AICISE’s co-director, explains in a video posted on the research institute’s website. “The need for large investments at the surface, as well as the need for remediation of the environment, will be reduced.”
Despite the promise of such technologies, the industry has its work cut out for it satisfying non-governmental organizations that insist that all the technological improvements are being offset—and then some—by the cumulative growth of the industry.
“There are some interesting technologies out there, but they still represent a small portion of the total industry,” says Simon Dyer, director of oilsands for the Pembina Institute, a Calgary-based environmental organization that supports “responsible” development of the oilsands. In March, the institute published a report card focused on the in situ industry, the first of its kind from an NGO, entitled Drilling Deeper. The report acknowledges the strides many industry players have made, noting, “Simply meeting industry best practices could dramatically improve environmental performance.” The authors surveyed nine of the largest in situ operations, all using SAGD. Suncor’s Firebag and Mackay River projects, Cenovus Energy’s Foster Creek and Imperial’s Cold Lake received passing grades on five ecological criteria. At the bottom of the list, with a 25% grade, was Canadian Natural Resources’ Primrose/Wolf Lake.
“I can understand the frustration of some of the people in the industry,” Dyer says. But he insists that for all the new technology, “it’s not getting better environmentally. It’s getting worse.” Dyer adds that readier solutions will come from policies such as hard limits to emissions or land use rather than “getting industry to squeeze down its footprint.”
In the court of public opinion, though, producing oil that is no dirtier than conventional crude would be a key benchmark that the industry could be proud of and would more effectively counter ad campaigns like “Rethink Alberta,” popular polemics such as the Neve Campbell-narrated documentary Dirty Oil and U.S. politicians who would block oilsands-bearing pipelines. When will that day come? “It could be relatively quickly,” says Michael Burt, vice-president and managing director of the In Situ Oil Sands Alliance (IOSA), a group set up last year to distinguish the in situ sector from the higher-impact mining side of the oilsands industry. He suggests that certain projects, such as the pilots of IOSA members Petrobank and Laricina, may already be there. It’s harder to say how long it might take to get the broader industry to the same level of environmental performance, especially while the regulatory carrots and sticks for doing so remain weak. If hoary giant Suncor can green yesteryear’s tailings ponds, though, change on a grand scale is possible—perhaps sooner than we think.