Touchstone Exploration’s July disposition of its Dawson asset is the lastest evidence against the future of toe to heel air injection (THAI), the much publicized in situ combustion (ISC) oilsands technology of the mid-2000s that fell off through unsuccessful piloting. But the demise of Petrobank (the predecessor to Touchstone) and its efforts to deploy THAI shouldn’t be seen as a blemish on ISC, say the technical experts who are active in successfully implementing this technology internationally.
The typical response to this statement by western Canadian producers, however, seems to be something like this: “Blemish? You mean in situ combustion actually works somewhere?”
Well, yes. There are economic ISC projects as far away as Russia, Kazakhstan and India, and as close as the Williston Basin of North and South Dakota. The Alberta industry still doesn’t fully appreciate this fact, nor that ISC works in all kinds of reservoirs, irrespective of depth, pressure, temperature, salinity, permeability or oil viscosity. According to ISC experts, the unit displacement efficiency of the technology is on average the highest of any enhanced recovery process, and it’s more energy efficient than steam injection.
“There are no mysteries to unlock in ISC,” says John Belgrave, president and chief executive officer of Belgrave Oil and Gas. “The technology works. It’s just that some people don’t get it.”
Belgrave’s expertise is sought after around the world. He is a former associate professor at the University of Calgary who worked with U of C’s Robert Gordon Moore and Raj Mehta, two Schulich School of Engineering professors who co-lead the In Situ Combustion Research Group, which consists of 11 researchers and about 10 graduate students. The school is also home to a laboratory for testing in situ combustion described as the best in the world.
Alberta producers might not “get” ISC today, but they might start to as environmental pressures mount and a new, potentially much lower, oil price reality sets in. New production efficiencies will need to be found.
“[ISC] is profitable at these oil prices,” Belgrave says. “There are ways to implement it. People don't know that. It has been demonstrated commercially and economically as a follow-up process to waterflooding and steam.”
When Petrobank was promoting THAI around 2006, the footnote in the sales pitch was that ISC is a proven technology that was already being used elsewhere. Strangely enough, the details of this never attracted much attention. For the record, here’s the short list of ISC successes.
In Romania, the Suplacu de Barcau project has been operating since 1964 and continues to this day. It produces about 8,000 to 10,000 bbls/d. In India, the Balol and Santha oilfields started in situ combustion in 1994 and produce about 15,000 bbls/d.
The Indian success is a source of pride for the University of Calgary's In Situ Combustion Research Group, which has collaborated on the project since 1993.
“They are now at about 50 per cent recovery in one part of the reservoir and 53 per cent on another part of the reservoir,” Mehta says. “Primary [recovery] was originally estimated at just six to eight per cent.”
South of the border, the Williston Basin in the Dakotas has seen nine light-oil ISC projects since 1978. In 2008, Continental Resources’s Cedar Hills North Unit in North Dakota was producing 11,500 bbls/d from ISC operations. “It was originally started by Koch Exploration Company in 1978,” says Metha. “Then Harold Hamm, the billionaire who owns Continental Resources, took over from Koch.”
Bellevue, La., has among the longest-running ISC projects. Oil was discovered there in 1921 and production peaked in 1923 at 7,000 bbls/d. In 1963, Getty Oil started an ISC pilot that in 1982 had 223 wells producing about 2,750 bbls/d. Today, Bayou State Oil Corporation continues to operate the project with modest production.
In Canada, ISC also has a rich history. Mobile Oil’s Battrum, Sask. project, which saw economic ISC production from 1965 to 2003, is just the tip of the iceberg.
“Battrum produced about 8,000–10,000 bbls/d,” Metha says. “When Exxon took over Mobil, they didn't want to have another technology, so they shut it down.”
According to an Oil & Gas Journal report, total world oil production from ISC in 1992 was about 32,000 bbls/d from 26 reported projects: 4,700 bbls/d came from eight U.S. projects; 8,000 bbls/d from 10 projects in the former Soviet Union; 7,300 bbls/d from three projects in Canada and 12,000 bbls/d from five projects in Romania.
Okay, so the technology works. But why isn’t it in the oilsands?
The short answer is that historic ISC field tests have succeeded in the oilsands, however, bitumen is a more challenging application than lighter oil because very heavy oil reservoirs require preheating before the combustion process can effectively move bitumen. A bigger challenge, according to Moore, is that in western Canada, there always seems to be someone who thinks ISC is no good, “mostly people who read too much and know too little.”
A general understanding of ISC has not emerged, partly because the technical literature on ISC is fragmented. This is partly because there have been numerous steps in the development of ISC over its 40-year development and partly because other technologies have overshadowed ISC.
Early tests in California, for example, ran into safety issues. The converted natural gas compressors that were initially used to compress air for the ISC process led to blow-by air in the compressor cylinders going directly into non-synthetic oil lubricant inside the compressors, which created peroxide that could explode. Early on, those safety concerns pushed the industry towards another technology that was being developed by Shell, steam injection. Steam took the lead, even as purpose-built air compressors allayed safety concerns in ISC.
Cyclic commodity price downturns and lower-hanging fruit took their toll on ISC. Early success in California ran into $0.63/bbl oil, Battrum into pro-rationing in the 1970s, and BP, which did important work in Canada on ISC, got shut in by the National Energy Program’s subsequent low oil prices in he 1980s. In 1977, oil production from Prudhoe Bay, Alaska, had a dampening effect on the industry’s interest in ISC similar to the impact the shale gas revolution had on Arctic gas development in Canada.
The application of ISC in very heavy oil reservoirs also took some time to figure out. When ISC was patented in 1923, it was originally intended for heavy oil because it was thought that high downhole temperatures would consume all the light oil. The early California tests proved that premise wrong. ISC worked fine in light oil, sending only 20–30 per cent of the oil up the stack.
ICS in Battrum produced 18-degree API oil, and in California heavy oil reservoirs, it was 14 degrees. In both cases, there was sufficient oil mobility for ISC (the warm California environment helped in the latter case). But in very heavy and cold reservoirs, such as in the Athabasca oilsands, ISC runs into problems in anything but short-interval well spacing designs.
“The combustion starts to move the oil, but you lose your gas saturation,” Moore explains. “It's like a snowplow pushing snow. If you have a straight blade it piles up and up. In a heavy oil reservoir, the heavy oil will build a high liquids saturation, which then will cause you no end of grief trying to get the air in.
“You have to realize that ISC is a displacement process. As you push the hot oil out into the cold part of the reservoir, it still needs to get to a production well.”
Belgrave is emphatic about this point. “Steam is a thermal process. It's more diffusive in nature. It heats by conduction and convection and so on, whereas combustion is a displacement process. People don't get that,” he says.
Of Petrobank’s THAI experiments, he says, “that team is to be commended for recognizing the potential benefits associated with combustion’s high displacement efficiency; however, THAI is/was geometrically challenged. It was a very good science project that expanded the conversation and knowledge considerably, but it was conceptually flawed from a commercial standpoint.
Belgrave continues, “SAGD uses well pairs, horizontal laterals. You can't do that with combustion from the get-go. It doesn't work in a bitumen situation without substantial preheating with steam. Steam will move vertically and migrate laterally. But combustion will only go where the flue gas goes. So if you have to vent the combustion process to the bottom well, that's where the combustion is going. It's not going to move out laterally.”
Making it work
ISC can work in the oilsands, but it needs to be implemented by people who have experience with the technology, Belgrave says. It also helps if the company can afford to take a longer a view of ISC development than typical public-company quarterly reporting affords.
Petrobank understood that in very heavy oil situations, combustion needs steam to condition the reservoir before injecting air to avoid the snowplow effect. It just didn’t get the well geometry right. But the lessons learned in other heavy oil ISC applications worldwide can guide an effective well design in the oilsands. There is no need to reinvent the wheel if technical experts can learn from one another.
This is the approach India took before launching its ISC work in Balol and Santha. It consulted with U of C’s In Situ Combustion Research Group. “We told them that if you want to inject a small amount of air, don't even try. Shut it down. Don't annoy your reservoir,” Mehta says, discussing the ISC learnings of that era. “This was in 1993. In 1996, we went there. They had two air compressors with a capacity of 65 million standard cubic feet per day each and they had very good production. The rest is history.”
Today, Moore says that the In Situ Combustion Research Group does a lot of international work but also some local consulting with companies such as Nexen and Cenovus. So the tide may be turning for ISC in western Canada.
Cenovus specializes in SAGD extraction but, since 2007 (as Encana), it has been conducting tests and pilots on a form of ISC it calls AIDROH (Air Injection Displacement Horizontal Oil Recovery).
“We have been using this method to recover small amounts of oil from bitumen deposits in northern Alberta, by igniting and thus heating oil below the natural gas zone [natural gas sits on top of the bitumen reservoir],” Cenovus says. “We have shown that it is possible to safely ignite in the natural gas zone and sustain combustion in a reservoir to increase its pressure. The heat thus created travels downward to heat bitumen situated below the natural gas zone, softening the oil sufficiently to allow us to pump it to the surface.”
The company says that AIDROH has the potential to reduce the amount of natural gas needed to generate steam in SAGD operations, which could help reduce steam to oil ratios.
“We believe AIDROH is an encouraging technology that may find large-scale application in suitable reservoirs. The technology is in the very early stages of development. In the next several years, we plan to do more lab testing and field trials to demonstrate that this technology has the potential to work on a larger scale.”
As for THAI, Touchstone says that it is still using the technology at its Kerrobert, Sask., property, although the project is evolving to a "more conventional operation with a focus on economic recovery."