by Andrew Topf of Oilprice.com
The financial pages of Canadian newspapers have been full of headlines lately announcing the potential of two large shale oil fields in the Northwest Territories said to contain enough oil to rival the Bakken Formation of North Dakota and Montana.
The report by Canada’s National Energy Board (NEB) evaluated, for the first time, the volume of oil in place for the Canol and Bluefish shale formations, located in the territory’s Mackenzie Plain. It found the “thick and geographically extensive” Canol formation is expected to contain 145 billion barrels of oil, while the “much thinner” Bluefish shale contains 46 billion barrels.
The report did not estimate the amount of recoverable oil, but points out that even if one percent of the Canol resource could be recovered, that represents 1.45 billion barrels. The calculation immediately had reporters comparing Canol and Bluefish to the Bakken, where the latest USGS estimate shows 7.4 billion barrels of technically recoverable oil (this includes the Three Forks Formation underlying the Williston Basin straddling North Dakota, Montana, Saskatchewan and Manitoba).
“Northwest Territories sitting on massive shale oil reserves on par with booming Bakken field in U.S.,” enthused the Financial Post. “NEB and GNWT study finds 200 billion barrels of oil in the Sahtu,” gushed CBC News, referring to a region of the sprawling territory that cuts across three provinces and touches the Arctic Ocean.
In truth, energy industry followers would do better to read a more subdued story in Bloomberg News, titled “Drop in oil prices means no drilling in Canada’s biggest shale reserves.” Because while the report from the NEB does indeed point to a very large pool of potential shale oil, getting it out of the ground will be no small feat, especially at today’s prices.
Before getting into the explanations, a little history and context.
Petroleum geologists have known about the Canol (short for Canadian oil) shale play at least since 2010, when ConocoPhillips bid $66 million to secure the rights to explore an 87,000-hectare parcel known as EL470. Thought to be the source rock of the Normal Wells discovery, which has yielded over 226 million barrels of conventional, light sweet crude since it was found in the 1920s, the Canol formation sparked a flurry of exploration activity around 2012-14. The area has seen 14 exploration licenses granted and $628 million in work commitments over the last five years.
ConocoPhillips, Imperial Oil, Shell Canada and Husky Energy are the major leaseholders in the Canol, along with MGM Energy, an Alberta-based junior that originally hitched its wagon to the Mackenzie Gas project, a proposed natural gas pipeline that would run 1,200 kilometers along the Mackenzie Valley to connect northern onshore gas fields with North American markets. The project was approved by the NEB in 2010.
But with U.S. shale gas flooding the market, the proposed pipeline, led by Imperial Oil, no longer made sense, so MGM turned its attention to unlocking Arctic shale oil. The company gobbled up 189,000 net acres in the Canol, and in 2013 did some drilling at one of its four licenses in the play. Shell, Husky and ConocoPhillips have also drilled wells, but in all, only about 20 have penetrated the formation, according to John Hogg, the former vice president of exploration and operations at MGM, who is now president of Skybattle Resources Ltd., a consulting company.
In 2014 MGM was taken over by Paramount Resources after failing to find a partner to help fund development of its shale oil prospects, including its main exploration license known as EL466. That license was estimated to have 625 million barrels of oil in place.
“We know there is a tremendous resource here,” Hogg told Alberta Oil in a feature report on the Canol in 2013. “What we don’t know is how much has the potential to be economically developed.”
Indeed that is the question on the minds of oil investors as they digest the latest numbers of potential barrels of oil under the Arctic tundra. The two formations have more oil in place than any other shale deposit assessed by the NEB, including the Montney region and Duvernay field. Globally, their significance is harder to assess. If all 191 billion barrels were technically recoverable, they would represent over half of the 345 billion barrels of global recoverable shale oil resources, more than the top four countries, Russia, the U.S., China, and Argentina, combined. But as was mentioned earlier, the NEB did not do that recoverable-oil calculation.
Knowledgeable oilmen like Hogg say that the Canol, while highly prospective, is a long-term game that will have to wait until oil prices rise. ConocoPhillips and Husky have both suspended exploration in the play, scared off by the oil price rout.
Hogg told Bloomberg that exploring the Canol costs three to four times more than in northeast British Columbia, where the Montney Basin has been a hot zone of oil and gas exploration recently. That’s because the region lacks key infrastructure. A winter road is the only means of trucking drilling equipment to the Mackenzie Valley, with no all-weather road linking the potential oilfields to southern Canada. According to Hogg, a 500 to 800-barrels-a-day per well operation would only be profitable with oil at $75 a barrel (the Bakken produces an average of 630 barrels a day per well currently). WTI crude closed at $59.13 on Friday, June 5th.
Even if oil prices climb higher, those hoping for a Canadian Bakken need to be aware of the byzantine regulatory environment the Northwest Territories operates under compared to business-friendly Alberta to the south. Companies must submit applications to multiple regulators, versus a single regulator in Alberta With environmental assessments typically taking over 18 months to complete.
The Canol and Bluefish are shale oil formations, so companies will have to drill horizontal wells and use hydraulic fracturing to extract the oil. Fracking is a controversial practice that has not gone over well in other parts of Canada. Québec and Nova Scotia have banned it, along with the state of New York in the United States. Considering that most of the communities in the Mackenzie Valley are small and aboriginal, where the people see themselves as stewards of the land, it is quite unlikely that a big expansion of oil and gas production in the area would be allowed to go forward unopposed.
Then there’s the historical enmity towards new pipelines in the Northwest Territories. Pulling the oil out of the ground at economical prices is one thing, but getting it to southern markets is quite another. The Mackenzie Valley Pipeline to move natural gas from the Beaufort Sea through the Mackenzie Valley into Alberta has been frequently delayed due mostly to opposition from aboriginal groups. The closest the pipeline ever came to fruition was to receive federal Cabinet approval in 2011. The project is now estimated to cost $20 billion and no-one knows if and when market conditions will be favorable.
In late 2014, there was another proposal to transport bitumen, the tarry substance from which oil sands crude is derived, to Tuktoyaktuk, a hamlet on the coast of the Arctic Ocean. But again, the participation of native tribes is deemed crucial to the project. The experience of Enbridge, which is trying unsuccessfully to gain public acceptance of a plan to move oil sands crude across northern Alberta to a port on the British Columbia coast, does not hold much hope for the Northwest Territories, as far as new pipelines go.
Put it all together, and the potential of Canadian Arctic shale turning into another Bakken appears rather remote. Lack of infrastructure, low oil prices, a difficult regulatory environment, and a population that has traditionally opposed the expansion of oil and gas pipelines, are all factors working against this monster resource from ever moving beyond “in place” to anything resembling a set of producing fields.