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Eyeing the next technical generation Undeterred by current oil price environment and financial struggles, industry secures rights to bitumen carbonates Gary Park For Petroleum News
At a time when the blinds are being drawn and the shutters are going up on many oil sands projects, some producers are betting that a technological breakthrough will lead over the long term to commercial development of an untapped formation below the established bitumen formation in northern Alberta.
It’s a deposit that some estimate contains more oil potential than the 170 billion barrels of reserves that have been assigned to bitumen deposits that are being extracted by a variety of means.
Ignoring the current bleak outlook for the resource, an unidentified company paid C$21 million at an Alberta government auction in March for rights to 47,000 acres of bitumen carbonates beneath Shell Canada’s 80,000 barrels per day Carmon Creek project in the Peace River area of northwestern Alberta.
The successful bid, which averaged about C$2,238 per acre, was placed by brokers Britt Resources and Land Solutions Group. Neither they nor Shell would answer inquiries about who the bidder was.
Government geologists estimated the rights have 447 billion barrels of oil in place, of which 89 billion barrels are thought to be recoverable.
Development methods in infancy But methods to develop the carbonates are still in their infancy.
Unlike the oil sands, there is almost no geological pressure in the carbonate formations.
One of the best hopes of making a commercial breakthrough was Laricina Energy, which, in partnership with Osum Oilsands Corp., booked 128 million barrels of probable reserves at their 1,800 bpd Saleski Phase I pilot project in the Athabasca formation.
Laricina suspended work at the site in February, despite having completed 80 percent of the engineering, while it tried to raise C$350 million in a difficult investment climate to complete the C$520 million venture.
The privately held company’s search for ways to access the new geological formation experienced a setback March 31 when it was granted court protection from creditors after facing a demand for payment of C$150 million from the investment board that manages the Canadian government’s pension plan.
Laricina Chief Executive Officer Glen Schmidt told the Calgary Herald that the request was a difficult, but necessary, step for his company which lacks the funds to build a commercial operation at its two demonstration projects.
He said the court order gives Laricina the “time to manage its affairs so that the interests of all stakeholders are met.”
The company issued a warning in January that it was in technical default of covenants when fourth-quarter production of 1,255 bpd missed the promised target by 18 percent.
The pension plan board, which is Laricina’s largest single shareholder at 15.3 percent, said it concluded there was no reason to believe it could put its debt back into good standing, repay it, or make an acceptable restructuring proposal.
The board blamed the production record on technical challenges and “operational errors” and accused management of failing to take “prudent measures” to reduce spending.
Timing of development questioned Calin Dragoie, vice president of geoscience at Chinook Consulting Services, told the Financial Post that despite research efforts, the industry is years away from a “breakthrough” that would open the door to commercial development of the carbonates.
As well as Shell, Laricina and Osum, Husky Energy has been experimenting with in situ upgrading in the carbonate play through a series of pilot operations.
For more than 30 years, Shell has periodically tested in situ electric heaters to extract light oil from oil shale at a research project in the Piceance basin of northwestern Colorado.
In late 2004, the company extended those tests to northwestern Alberta, more than a year before announcing it had invested about C$500 million for a stake in the Peace River rights.
The pilot yielded several thousand barrels of light oil, pointing to success from a technical standpoint in breaking down bitumen viscosity in a reservoir that ranges from 8 to 10 degrees API, resulting in oil of 30 to 49 degrees API.
But Shell, for competitive reasons, has been reluctant to discuss how close it might be to a full-scale commercial application, noting that field tests are still focused on proving the in situ upgrading technology. Among other pioneers, E-T Energy, a small research and development venture, had success with its first field test in 2007. Rather than applying in situ upgrading, the E-T process used heaters to simply melt the bitumen so that it would flow to wells.
It drilled cheap, shallow wells targeting bitumen deposits that are too deep for surface mining and too shallow for steam injection and initially reported rates as high as 100 bpd from one well and recovery factors of 66 to 77 percent.
But, like so many junior players in the oil sands sector, E-T has gone quiet in recent years, with no updated information or news releases on its website.
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