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Busting the Canadian Shale Oil Bakken Myth
By Andrew Topf
Oil Price, Al-Jazeerah, CCUN, June 17, 2015
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
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
"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.
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
ConocoPhilllips 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
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.
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.
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
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. Quebec 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.
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.
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