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Bright natural gas flares dot the North Dakota landscape amid an oil boom that is changing the energy dynamics of North America. (Nathan VanderKlippe/The Globe and Mail)
Bright natural gas flares dot the North Dakota landscape amid an oil boom that is changing the energy dynamics of North America. (Nathan VanderKlippe/The Globe and Mail)

In U.S. energy renaissance, flares of fear for Alberta’s oil patch Add to ...

A glance at the big numbers might prompt questions about how Canada could possibly be concerned about U.S. market access. In 2011, according to the BP Statistical Review of World Energy, the U.S. consumed 18.8 million barrels a day. It produced 7.8 million a day. The gap has long been filled with imports, and even the giddiest of optimists don’t see that gap closing any time soon, if ever. Bentek sees U.S. production rising to 11.6 million a day by 2022. The International Energy Agency pegs it at 11.1 million.

That leaves a sizable percentage of American cars and trucks that will still need foreign oil to burn – and many believe a healthy chunk of that foreign energy will come from a Canada rapidly growing to meet the need. The IEA expects oil sands output to double by 2025, while Bentek sees Canada pumping 90 per cent more barrels by 2022.

“When you put it together – the oil sands, it’s all needed,” says Eric Newell, the retired chief executive of Syncrude Canada Ltd.

Then consider the makeup of the U.S. refining industry, which has spent vast sums to re-tool refineries to suck up huge volumes of Fort McMurray’s heavy crude. Refinery upgrades set to take effect by mid-2013 will add 310,000 barrels a day of thirst for heavy oil in the U.S. Midwest. At the same time, Gulf Coast refineries operate best with 3.4 million barrels a day of heavy crude – today, with declining supplies from Mexico and Venezuela, they are a million short. That alone is a major market, not to mention the likelihood that many of those refineries would, if given the choice, ditch South and Latin American product for Canadian.

Canadian Natural Resources Ltd., which compiled the heavy oil refining numbers, has used them to argue that the days of the deep discount are almost over. In fact, “we are bullish on heavy oil pricing in the near, mid and long term,” president Steve Laut said last week.

Yet for Canada, what one hand lunges at, the other turns away. Refinery demand is not fixed, and it is surprisingly simple for refineries to gear back toward light oil. It cost BP PLC $3.8-billion to retrofit its Whiting, Ind., refinery to run more heavy oil. Valero Energy Corp. is now installing a unit, called a flash tower, at its Three River, Tex., refinery to boost its ability to process very light oil from the Eagle Ford play. That retrofit costs in the “tens of millions” of dollars, said Valero spokesman Bill Day. It’s such a cheap upgrade, the company is contemplating where else it can do the same.

“We’re looking at it at our Corpus Christi and Houston refineries,” Mr. Day said.

Such modifications could “certainly” change how much heavy crude Gulf Coast refiners seek out in coming years, said Roger Ihne, a Houston-based refining market specialist at Deloitte & Touche. And though any change would stand to hurt Mexico and Venezuela long before it hurts Canada, it’s clear that change is afoot.

“They’re going to do everything possible to lighten up that crude run,” Mr. Ihne said.

A TECHNOLOGY BOOST

“Go ahead and open the well,” Nathan McKelroy, a service supervisor with Nabors Drilling, says in a low voice, speaking into a black headset.

A moment later: “Ready with all the chemicals?”

Then: “Let’s do it, man.” One by one, he calls for power to 10 pumps. A few steps from him, inside a narrow mobile command trailer parked a kilometre from the Canadian border, two technicians flick at a pair of touch screens.

The roar is immediate, from the trucks parked just outside the trailer that produce a rush of diesel power. The thunder grows as each pump, in turn, spools up to pump water, chemicals and 23 tonnes of sand 2.5 kilometres below the earth. A flat-screen panel in front of Mr. McKelroy shows the wellhead pressure leap upward just under 5,000 pounds per square inch. Deep underground, the pressure is fracturing the earth. This is the 21st frack of 32. It will last roughly 45 minutes. Then it will be repeated again, and again, and again, each frack taking another 23 tonnes of sand and triggering another chest-rumbling display of horsepower.

A decade ago, industry technology wasn’t advanced enough to economically extract the oil here, trapped in rock that feels like sidewalk concrete. But when this operation is done, it will race to the surface, liberated by the cracks fractured into the rock. This well, called Aldag, belongs to Crescent Point Energy Corp., which names its U.S. wells after Saskatchewan Roughriders. Not far from here, another well pumped out 2,500 barrels of oil in one day – unusually high for the area, but an unmistakable sign that great riches lie beneath.

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