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Meet Iris Evans | Downstream | Patch test | The GHG quandary
All that John Nenniger needs to reduce greenhouse-gas emissions in the oilsands by 85% is a cool $60 million and a 300-metre field of gooey bitumen. He doesn’t need carbon capture and storage service because his process hardly makes any. Nor does it consume groundwater or burn vast quantities of valuable natural gas. “From a scientific point of view,” he explains, “this technology is a great opportunity to significantly reduce the energy requirements for tarsands extraction.”
While two companies have offered the well-respected oilpatch engineer prime real estate for a field project, Nenniger is still waiting for provincial government funding. So far, he has collected five rejections. Yet a 2005 laboratory test of his technology by the Alberta Research Council showed such impressive results that even heavy hitters in the oilsands research community such as Clement Bowman say the kind of technology being explored by Nenniger is exactly where the oilsands needs to go.
Nenniger, the quiet 53-year-old CEO of N-Solv Corp., a Calgary-based firm with high-profile investors such as Hatch Ltd. (Canada’s second-largest engineering firm) and Enbridge Inc. (TSX: ENB), frankly admits that he’s more a scientist than a promoter. Nenniger, whose grandfather was the “N” in Canada’s largest engineering firm, SNC-Lavalin Group Inc., says that he just wants to do the science right. He, too, knows that “good technology developments are inherently upsetting to the status quo.” And that just may be his biggest problem.
The status quo that Nenniger wants to upset is something much bigger than Fort McMurray’s open-pit mines. Only 10% of Alberta’s bitumen (oil mixed with sand, clay and heavy metals) can be extracted by brute force. The remainder, which lies too deep for mining, requires some sort of technological finesse. To date, these underground reservoirs (imagine an asphalt highway 15 metres thick and nearly 500 metres underground, capped by water or gas) can only be recovered with what engineers call in situ technologies. The most popular method is steam-assisted gravity drainage (SAGD), a 31-year-old science project with a steep learning curve and some mighty environmental issues. Nenniger thinks he has found a way to do it better, cheaper and greener.
SAGD is now the hottest ticket in the oilpatch. Over the next decade, companies as varied as Norway’s Statoil and France’s Total plan to invest $80 billion in nearly 80 SAGD projects over an area about the size of Vancouver Island. By 2020, SAGD projects could produce nearly one million barrels a day of bitumen (that’s what the mines now produce) and thereby increase Alberta’s GDP by nearly $150 billion. “There is perhaps no other uniquely Canadian technology that has as much potential to contribute to the development of this province and the country as a whole,” concluded a 2006 University of Calgary study.
But SAGD, a water and natural gas hog, is anything but sustainable. First, a company must burn lots of natural gas to boil up clouds of steam (250º C), a process that creates tonnes of greenhouse gases. (A barrel of bitumen extracted by SAGD creates three times the amount of carbon dioxide, or CO₂, as the mined product.) Then, it must inject the equivalent of three barrels of pressurized steam down a well bore to transform a substance stickier than tar into one barrel of bitumen. Once liberated, the bitumen drains downward with the help of gravity to a horizontal pipe that pumps the molasses-like product to the surface. There, the water is separated from the bitumen and recycled for more steam injection.
The whole process is so energy intensive that, if SAGD were used to tap just 80% of recoverable bitumen (138 billion barrels), it would consume the entire gas supply of Western Canada. Not surprisingly, natural gas now accounts for 60% of the costs of SAGD, and many advocates of nuclear power in the oilsands argue that these consumption patterns are crazy.
The consumption of groundwater also poses real problems. Many operators now use saline water from deeper aquifers, but must spend more energy desalinating it. As even a report by the U.S. Congressional Research Service notes, the process “generates huge volumes of solid waste which has posed serious disposal problems.”
The technology also has a substantial surface footprint. A typical project occupies a 25-square-kilometre area and directly destroys 7% of the land. But the technology’s supporting roads, pipelines and seismic lines industrialize the forest so completely that it makes the land inhospitable for much wildlife. A 2008 report by the industry- and government-funded Cumulative Environmental Management Association disclosed that SAGD, as currently designed, would extirpate caribou, fish, bear and moose over a region 400,000 hectares in size. Even better industrial practices don’t make much of a difference. “They don’t change the destination for wildlife, but it does take longer to wipe them out,” explains land use ecologist and study contributor Brad Stelfox. “With SAGD, there is a profound loss of species.”
To date, SAGD has promised steady bitumen wealth but delivered inconsistent production and rising costs because no two projects are finding the same conditions. Alberta’s oilpatch regulator, the Energy Resources Conservation Board, has a little-known website where it annually posts in situ progress reports. They make interesting reading. In 2006, Total E&P Canada Ltd. suffered a major blowout after injecting too much steam at a well pad for its Deer Creek–Joslyn project, creating a 300-metre crater in the forest. It also reported “overall inability to inject steam at higher rates and thus ramp up production rates.”
In 2008, Suncor Energy reported that the steam-oil ratio for its Firebag project had increased from 2 to 3.65 and that emissions of highly toxic sour gas “continues to be much higher than expected.” Husky Energy Inc. has yet to post an annual report on its $500-million Tucker thermal SAGD project for 2008, but last year it realized it had drilled approximately one quarter of its 32 wells in the wrong location and is now trying to fix its $200-million mistake.
“SAGD is not a slam dunk,” notes Chris Feltin, an institutional research analyst at global energy advisory firm Tristone Capital. “When the steam hits the reservoir, things don’t always work out as anticipated.”
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