First it was the Mackenzie Gas Project, now the shutters are being erected around the Central Mackenzie Valley as Canada’s North retreats even deeper into hibernation, ending for the foreseeable future the once-limitless hopes of developing trillions of cubic feet of natural gas and billions of barrels of oil.
The latest blow is word from Imperial Oil that it is looking for a buyer of its Norman Wells oil operations, the most northerly commercial oil venture in Canada, which are only four years away from celebrating a century of production.
However, the company said that although a definitive sale decision has not yet been made, it has acknowledged the significance of such a move by opening discussions with Sahtu community leaders about the plan.
Imperial, 67.5 percent owned by ExxonMobil, said it will market the 11,000 barrels per day oil field this quarter, including a fuel distribution center.
Drilling began in 1920
Imperial first drilled for oil in Norman Wells, a town about 100 miles south of the Arctic Circle in the Northwest Territories in 1920 and followed that by opening a refinery which supplied fuel to military operations in Alaska and the Yukon during the Second World War.
Then the company opened up markets in southern Canada and the Lower 48 through a 520-mile, 50,000 bpd Enbridge pipeline connecting Norman Wells with Zama in northern Alberta.
Imperial estimates the field has yielded about 250 million barrels during its lifetime, although output has steadily dwindled to the point where the pipeline is now carrying only about 11,000 bpd.
Currently, Norman Wells, after a 1982-84 expansion that exploited waterflood methods, has about 166 producing wells and 163 injectors.
Whether or not Imperial is successful in attracting a buyer and what will happen to Norman Wells if it fails are open questions.
Retreat from Canada’s Arctic
But one conclusion is beyond debate: This development is further proof that the industry’s majors are staging a quiet retreat from Canada’s Arctic, ending the rapidly growing excitement over prospects in the Central Mackenzie Valley.
Only three years ago John Hogg, vice president of exploration and operations at Calgary-based MGM Energy, said the Canol shale in the NWT could hold “billions and billions of barrels” of light-sweet crude.
The NWT estimated that up to 3 billion barrels was recoverable, matching the scope of the Bakken in North Dakota, Saskatchewan and Manitoba.
In addition to Imperial, Shell, ConocoPhillips and Husky Energy were among those lured to the region, investing more than C$600 million to acquire exploration leases and giving the NWT government hope that it could switch from the failed Mackenzie Gas Project to oil.
It didn’t take long until the turnaround in oil prices collided with the extreme costs of exploring such as harsh, remote region, where Hogg said that hauling equipment to sites costs more than one-third of sinking a well in the permafrost, raising per-well costs to “tens of millions of dollars.”
In 2013, Husky, having spent C$376 million on acreage rights, was weighing the possibility of building an all-season road to its land, prompting then-Chief Operating Officer Rob Peabody to observe that “these are early days and we will proceed cautiously.”
Analysts were already warning that if Alberta was having difficulty shipping oil sands bitumen out of the province, what hope was there of delivering shale oil from the NWT to markets? And that’s the unspoken challenge underlying Imperial’s decision to retreat from a frontier play to its much larger business farther south.
