A winter drilling season with potential to fulfill Canadian northern oil visions has begun, with an adventurous spirit driving bits down into an all but untouched shale deposit known as the Canol.
The fresh target, 650 kilometers (400 miles) beyond the top of Alberta in the frigid central Mackenzie Valley district of the Northwest Territories, arouses a mood of frontier fortune hunting among industry earth scientists.
“Crack it with a hammer and you smell the oil,” geologist John Hogg said last week, describing a thick, dark-colored Canol outcrop beside a tributary of the Mackenzie River to a shale oil and gas symposium held in Calgary by CI Energy Group.
The formation, near Norman Wells, looks so rich that Hogg said participants in the exploration are footing five-fold higher costs than even the stiff bills paid for wells in untried territory of northern British Columbia and Alberta. The organic material content of the shale is consistently rich, averaging 6-8% and running as high as 27%. Further drilling is expected to prove that the deposits are premium grade light crude, in the range of 37-40 API.
As vice president of MGM Energy Corp., Hogg belongs to a small but dedicated crew of frontier drilling veterans eager to achieve the first production on 8,000 square kilometers (3,200 square miles) of prospects along the northern river and on the Mackenzie Delta. MGM, sporting an iconic polar bear image in its corporate logo, was created and endowed with most of its properties six years ago as a northern exploration specialist by Calgary-based Paramount Resources Ltd.
Expectations of rapid growth by MGM faded when shale production and falling prices across North America overtook the Mackenzie Gas Project, freezing out the $16 billion production and pipeline scheme (see NGI, April 9, 2012). However, unconventional drilling technology for tight oil and liquids-rich gas has revived northern ambitions to stimulate the highest level of activity in the central Mackenzie region in nearly 30 years.
MGM is drilling an exploration well with partner Shell Canada Ltd. ConocoPhillips Canada is drilling two more. Husky Energy Inc. is revisiting two exploration wells that are known to have found oil in order to conduct hydraulic fracturing that will show how much production modern technology can achieve.
The work is on extensive drilling rights packages that companies scooped up at auctions that the Canadian federal government held as the region’s land and minerals owner during 2011 and 2012. Rather than cash, payment is in work commitments. The sales fetched pledges of more than $600 million in exploration within about five years. During the last round of central Mackenzie Valley exploration, Chevron Canada drilled half a dozen wells north of the current hot spot near Fort Good Hope in the mid-1980s. Little was disclosed about the results, except that they did not justify trying to go into production with the technology available at the time.
Strong results are needed to warrant advancing into northern development. Exploration work starts over from scratch every winter drilling season in the remote Canol shale region, where there are no roads, bridges or other year-round infrastructure to support industrial operations.
About one-third of Canol drilling expenses go into building and maintaining ice roads, Hogg reported. Just to reach the Norman Wells operating base requires moving heavy hardware by summer barge trains or winter ice roads for about 240 miles north on the Mackenzie River. From Norman Wells out to the MGM well site is another ice road haul of 12 miles on the river then nine miles on a spur to the company’s exploration lease. “Unfortunately the roads we build melt every spring,” Hogg said.
The drilling rigs only work during the three most reliably frozen months of the year, when the river ice and ground stay cold enough to support heavy equipment. In the Canol region, not far south of the Arctic Circle line of demarcation where winter darkness runs around the clock and the sun stays up 24 hours a day in high summer, temperatures and winds are often harsher than at Inuvik and Tuktoyaktuk, the main towns on the Mackenzie Delta nearer the moderating influence of the Beaufort Sea.
Offsetting the harsh conditions is almost a century of knowledge that the central Mackenzie, unlike the Delta or the Beaufort, is rich in oil. A thick conventional deposit, contained in a 380-million-year-old fossil reef laid down in the Devonian geological age, was discovered at Norman Wells in the 1920s and has produced more than 300 million barrels to date.
Hogg and exploration geology peers Colleen Sherry and Roy Benteau described the Canol shale as the “source rock” for the Norman Wells conventional deposit, saturated with oil that was unable to flow out of dense shale and migrate to the Devonian-age trap formation. Hogg said that if the winter drilling turns out well the main obstacle against swift development will be northern Canada’s notorious regulatory maze, which is tougher sledding than the frosty environment that cold-climate industry long ago developed equipment and techniques to survive.
In the Canadian north resource developers contend with about a score of federal government regulatory agencies, and another 10 territorial and aboriginal authorities. Obtaining all the permits necessary for a single exploration well takes six to 15 months, as opposed to six to eight weeks in Alberta, Hogg reported. He estimated that a 20-well commercial development program will take three to five years — and possibly as long as seven years — under the current northern Canadian regime.
Shale developers will also need a larger pipeline than the 30-year-old route that Enbridge Inc. operates between the Norman Wells oilfield and northern Alberta, Hogg said. With capacity for 50,000 b/d — and about 13,000 b/d of that still taken up by the aging Norman Wells conventional production — the line has only half or less of the space that will be needed by central Mackenzie Valley development, he estimated.
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