Technology

Bitumen oilsands: Slick science

N-Solv Corp. just might have a better, cheaper, greener way to recover bitumen.

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.”

Feltin calculates that only a small fraction of Alberta’s bitumen resource can be recovered by SAGD. “It’s small and highly localized,” he says. Without more refined technologies, much of current bitumen now leased for steam production will simply remain locked in the ground. “I think technologies such as N-Solv have huge applications in the oilsands,” says Feltin. “Industry needs technologies that work.”

Nenniger’s technique also uses gravity drainage but replaces the steam with a solvent, propane. As the vaporized gas condenses against a wall of bitumen, it warms up the hydrocarbon to 40º C and chews away at the gunk, pore by pore, “like a Pac-Man.” The process leaves behind nasties like asphaltenes and heavy metals that are too dirty to burn and eventually end up in landfills. “The production rate with solvent at 40º C exceeds SAGD at 230º C,” adds Nenniger. In other words, SAGD overheats the resource. “The key is to get rid of the steam so you can reduce the extraction temperature,” he says.

The MIT grad, who worked in Petro-Canada’s research department for several years and later ran his own consulting business, started working with the solvent-driven process in the late 1990s. His father, Emil Nenniger of Hatch Associates, ran experiments in the 1970s and 1980s showing that cold solvents worked but produced bitumen at uneconomic rates. The inventor of SAGD, Roger Butler, later proposed a combination of steam heat and solvents with drive gases such as nitrogen and methane. But this process, known as VAPEX, has performed poorly in field tests. In 1999, Nenniger came up with the idea of letting a solvent create a little bit of extra heat during the condensation process. After the Alberta Energy Research Institute ran a simulation model declaring Nenniger’s novel idea “ worthless,” the scientist knew he had found an unplowed field. “I concluded AERI’s computer model was ‘worthless’ because it contradicted the published data.”

Hatch, the engineering firm, so liked Nenniger’s idea that it put together a team of engineering superstars to run a multimillion-dollar set of lab experiments four years ago. A 2005 evaluation of the N-Solv process by the Alberta Research Council concluded that it increased oil production rates by a factor of 50 (compared to VAPEX), recovered 70% of the product and even substantially upgraded the bitumen by leaving metals, sulfur, nitrogen and the coke-forming materials in the ground. “These were spectacular results by an independent third-party lab,” says Nenniger.

Other experts agree. Nenniger’s technology is exactly the kind of innovation that Canada desperately needs in the oilsands, says Clement Bowman, a pioneer in the field and the founding chairman of Alberta Oil Sands Technology and Research Authority (AOSTRA). “We are in the third chapter of the oilsands story and now have issues with water, hydrogen and CO2 which are really critical,” he says. “We have to change direction.”

Last year, Bowman co-authored a report published by the Canadian Academy of Engineering that pinpointed obstacles to sustainable development in the oilsands. The report described bitumen extraction with solvents as an “immature” science and said “financial support is needed for field testing processes that look promising based on bench scale testing.” In a recent interview with Canadian Business, Bowman explained that, “I still feel the same way. We’ve got to start to doing this.” He said little research was done on solvents in the 1970s because the economic margins of return for bitumen production at the time were so low. “Water was considered free then,” said Bowman.

Nenniger’s N-Solv process is now one of several potential technologies trying to resolve SAGD’s water, gas and CO2 woes. “SAGD was a revolutionary technology for its time…but now we have to do some things differently,” concurs Eddy Isaacs, executive director of AERI, a provincial body with a mandate to develop, implement and adapt innovative energy technologies.

Isaacs says that a number of technologies, including N-Solv, hold promise. Calgary-based PetroBank Energy and Resources Ltd., for example, is experimenting with a process known as THAI that burns bitumen formations underground by injecting air . But high temperatures (400º C–650º C) and dirty fuel mean that THAI will produce much higher levels of CO2 than even SAGD. “We think a lot of the greenhouse gases will stay in the ground,” says Isaacs.

Another Calgary firm, E-T Energy Ltd., is experimenting with electricity to heat up the bitumen. But if the source of energy comes from a coal-fired power plant then “it’s not wonderful for carbon production,” adds Isaacs. Other companies are using bitumen byproducts as a source of fuel to replace natural gas, but all substantially increase CO2 production. Such tinkering makes carbon capture and storage essential.

But unlike many of these technologies, N-Solv actually solves more problems than it creates — in the lab, at least. Because N-Solv doesn’t burn natural gas to make steam, it reduces CO2 emissions by 85% compared to SAGD. Because it makes a cleaner product, fewer carbon emissions occur during the upgrading. Moreover, N-Solv is 600%–800% more energy efficient than SAGD. With no need for water treatment or steam generators, the process dramatically reduces infrastructure costs. The process does require highly pure propane, which is recovered and reused and currently cost competitive with the natural gas costs of SAGD. “If you can reduce the extreme extraction temperatures used by current technologies, all kinds of virtuous things happen,” says Nenniger.

But so far, the engineer has had no luck convincing the provincial government of the virtuous consequences of funding a field project. His latest rejection letter from AERI simply states that the process “didn’t rank sufficiently high for approval.” In contrast, the federal government’s Sustainable Development Technology program has set aside $8.6 million for a pilot project. Isaacs says that N-Solv has made an application, but he “can’t comment on that….It’s under review.”

To most analysts it’s now clear that Alberta’s in situ bitumen won’t reach projected production rates of three million barrels a day by 2020 without several novel technologies that can reverse the extravagant energy and water intensities of SAGD. Feltin at Tristone Capital argues that both the provincial and federal governments need to take a more active role in developing greener and cheaper technologies by increasing the funding for R&D. Nenniger couldn’t agree more. “The oil industry badly needs less wasteful technologies,” he says. “We really need to test the process in the field to see if it works the way we expect.”