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Pondering Arctic gas riddle Prospect of ‘clean’ gas fueling Alberta oil sands looms over Mac, North Slope projects Gary Park For Petroleum News
It’s a question that has dogged the Mackenzie Gas Project almost from the outset and is now bothering Alaskans.
It quite simply boils down to this: If gas from the Mackenzie Delta and the North Slope enters Alberta, what’s to stop it being consumed in the energy-hungry extraction and processing operations at the oil sands?
And, by extension, that translates into an even more telling question: Why, at a time of mounting concern over greenhouse gas emissions, would anyone think of using a relatively clean fuel to produce a dirty one?
The suspicions in Canada and Alaska are heightened by the obvious ownership links between the Mackenzie and North Slope projects and the oil sands.
Three of the Mackenzie Gas Project anchor-field owners — Imperial Oil (69.6 percent owned by ExxonMobil), ConocoPhillips (a Canadian branch plant of its U.S. parent) and ExxonMobil Canada (wholly owned by the Irving, Texas, supergiant) — all have obvious ties to two of the North Slope owners, ExxonMobil and ConocoPhillips.
That leaves Shell Canada (wholly owned by Royal Dutch Shell) as the final MGP gas owner and BP to complete the North Slope trio.
One way or another, all of the companies have multibillion-dollar stakes in the oil sands, capped off in December when BP — one of the last holdouts from the northern Alberta resource — struck an $11.7 billion joint venture with Husky Energy, acquiring half of Husky’s Sunrise thermal project in return for half of its Toledo refinery. On top of that, BP is evaluating its own oil sands leases in the Kirby area that could support an in-situ project of 70,000 barrels per day.
Appetite for gas to grow It all boils down to a need for gas to extract raw bitumen and convert it into synthetic crude. That appetite is forecast to grow substantially.
Canada’s National Energy Board has forecast an increase to 2.1 billion cubic feet per day in 2015 — about 12 percent of current Canadian gas output — from 700 million cubic feet per day in 2005, covering a tripling of oil sands output to 3 million bpd.
The Ziff Energy Group sets the bar even higher, projecting demand will rise from its estimate of 600 million cubic feet per day in 2005 to 2.4 bcf per day in 2015, when it, too, expects, bitumen production of 3 million bpd.
Compounding the challenges, Ziff forecasts gas volumes from the Western Canada Sedimentary basin will slide from 16.6 bcf per day in 2006 to 13.1 bcf per day in 2015, by when the MGP, if it proceeds at all, will be sending about 1.2 bcf per day to southern markets, covering barely one-third of the WCSB’s decline.
Ziff analyst Dave Vetsch predicted in mid-2006 that much or most of Northern Canada’s gas would be consumed by the oil sands sector, pointing to shrinking exports from Canada to the U.S. by 2015.
He also cited other factors that could increase oil sands demand for gas, particularly hydrotreating that removes sulfur and impurities from bitumen.
Vetsch said that as environmental regulations tighten, hydro-treating will play an even larger role, further hiking gas demand.
Although the Ziff study included estimated gas use by Alberta upgraders that are part of integrated projects, it did not factor in gas consumption by standalone merchant upgraders.
It noted that of the 14 projects that have been proposed but not built, 11 are in-situ (the rest are mining operations) which are heavier users of gas.
Technology could curb gas use However, Vetsch echoed a common industry message that technological advances offer some hope of curbing gas use over the long haul, but he cautioned it could be 2010 or later before those technologies are introduced.
Current yardsticks covering gas consumption in the oil sands vary, but here are some for each barrel of bitumen produced:
• Surface mines — 131 cubic feet;
• In-situ operations — 1,000 to 1,500 cubic feet;
• Petroleum coking — 168 cubic feet; and
• Hydrocracking — 490 cubic feet.
Upgrading bitumen into synthetic crude needs about 1,000 cubic feet of hydrogen for each barrel and it takes 400 cubic feet of gas to produce that hydrogen using steam methane reforming technology.
Gasification cheaper alternative Oil sands operators see gasification of coke and raw bitumen as a cheaper alternative hydrogen source and both Suncor Energy and Canadian Natural Resources are considering building gasification facilities, although Suncor CEO Rick George said in January that his company has so much on its plate that a serious push on the gasification front will likely be delayed until 2012.
North West Upgrading, a merchant upgrader, plans to gasify what is known as the “bottom of the barrel” to produce hydrogen for its internal needs, eliminating the purchase of gas.
The Alberta Chamber of Resources some time ago produced a study that said gasification of bitumen would be necessary for oil sands expansion because gas supplies would not be able to meet the rising demand.
West Hawk Development is another gasification advocate. It has plans to strip mine extensive coal reserves along the Mackenzie River and build C$2 billion worth of gasification plants to tie into the proposed Mackenzie pipeline, producing 480 million cubic feet per day and filling 20 percent to 40 percent of the system’s initial capacity.
Although some place current gasification technology on the same level as oil sands development in the 1960s, before Suncor pioneered commercial development, there is growing pressure in Alberta to figure out “clean” ways to exploit the province’s vast coal resources.
As Canadian governments start to roll out their climate change plans, oil sands and heavy oil producers will feel the heat to kick their addiction to gas.
Factored into that effort is the prospect of nuclear generated power — a contentious, long-range possibility, but one that never quite goes away.
Troubling thought But even harder to shake off is the diversion of Arctic gas from the Northwest Territories and Alaska to the oil sands, long before it has a chance to reach the major markets of southern Canada and the Lower 48.
The troubling thought of oil sands devouring MGP volumes goes back to the time when a 134-page study was posted on the Internet as part of 8,650 pages of documents in support of MGP construction and environmental applications.
Done by research firms Nvigant Consulting and Energy and Environmental Analysis for the MGP co-venturers, it said bitumen development would be the strongest Canadian force driving a “fundamental mismatch” between gas needs and supply growth in North America, suggesting the MGP would not be able to keep pace with the acceleration of oil sands expansion.
But former Alberta Premier Ralph Klein, in tackling the issue at a 2006 conference, was adamant the oil sands would not have preferential access to gas from Northern Canada.
“There’s an idea out there that northern gas will go into a pipeline in the Mackenzie Delta and come out in Fort McMurray, to be sucked up entirely by the oil sands operations. That’s not the case,” he said.
While some of the buyers of Arctic gas might be oil sands operators “they’re already going ahead with their expansions without waiting for this pipeline,” he said.
Just as important as the oil sands’ need for gas, Klein said gas from the Mackenzie Delta and North Slope offered the potential to meet Alberta’s dream of building state-of-the-art refining and processing, massive storage facilities and a world-scale petrochemical industry to deliver value-added products to North American and Asian markets.
As the Mackenzie and Alaska projects edge their way towards the starting gate, the debate about where gas from those pipelines should, or must end up is likely to get a wider airing.
But one analyst, who asked not to be identified, said tracking gas from both sources to a final destination will be as difficult as complying with looming U.S. regulations to bar “dirty” crude from the oil sands crossing the border into the U.S.
“What the Americans should try to do is ensure that if 4.5 bcf per day enters a pipeline on the North Slope, an identical volume of incremental gas reaches the Lower 48,” he said.
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