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Sticky side of oil sands Plant outages highlight negatives of northern Alberta tar-like bitumen resource, but massive deposits are backbone of industry Gary Park Petroleum News Canadian Contributing Writer
It’s well understood that Canada’s future as an oil producing nation rests heavily with the 170 billion barrels of recoverable bitumen resources in northern Alberta.
In the latest production outlook report by the Alberta Energy and Utilities Board, output of the tar-like bitumen was reported to average 1.1 million barrels per day in 2004, compared with the ever-shrinking conventional crude volumes of 602,000 bpd.
The regulator said Sept. 15 that only 19.7 billion barrels of conventional oil remains to be found in Alberta, compared with 315 billion barrels that could be extracted from the oil sands.
As a raft of new projects comes on stream, the board estimates Alberta’s total output will climb over the next decade to 2.8 million bpd from 1.72 million bpd. Bitumen not a slam dunk But removing bitumen from the immense deposits of northern Alberta, while spared the usual risks of wildcatting, is far from a slam dunk.
Just how uncertain, is captured in a brief snapshot contained in a new 58-page National Energy Board short-term outlook for Canadian crude.
Buried in the heart of the study and wrapped up in less than a page is a synopsis of what can go wrong with the oil sands over a few months.
One of the core problems was a sequence of outages at all three integrated mining and processing operations — the Syncrude Canada, Suncor Energy and Shell Canada-operated Athabasca facilities. Disruptions first plagued producers in late 2004 and extended into the first quarter of 2005, all of them affecting upgraders used to convert raw bitumen into refinery-ready crude. As a result, the federal regulator projects that synthetic crude production will drop by 12 percent this year to an average 571,000 barrels per day.
The worry, according to the board, is that “reliability of supply could become more of an issue as (Western Canada’s) conventional light production declines.
“As well, upgrader outages could lead to future (price) discounts after production levels are restored to compensate refiners for the risk of potential unreliable supply,” it said. Other short-term market concerns Other major short-term market concerns identified by the study that are inherent to the oil sands sector included:
• Insufficient supplies of diluent needed to move heavy crude to market. Tackling this concern requires longer-term answers, including a possible import condensate pipeline paralleling two proposed out-going oil sands pipelines — Enbridge’s Gateway system and Trans Mountain’s northern option — between Edmonton and the British Columbia coast. As well, Enbridge is pondering shipping diluent on its mainline from Chicago back to the Edmonton and Hardisty hubs in Alberta.
• Using synthetic crude as a replacement for traditional diluent does not make much sense, given that the crude is trading at a premium that is not fully recoverable in heavy blends, particularly when the price of light crude is high.
• A wide price differential between light and heavy crudes will “continue to have severe consequences for heavy crude producers,” whose prices have not kept pace with West Texas Intermediate.
• A lack of pipeline capacity could also impact the light/heavy differential by “causing a disconnect of prices from the global price.” Enbridge plans to switch from light to heavy crude on a 140,000 bpd expansion of its Terrace system from Saskatchewan to Minnesota over the next two months, but the board cautions that “this will have to be well timed so as not to impact prices and the market.”
• Ongoing oil sands quality concerns could cause refinery process issues, although the problems are being tackled with new oil sands blends.
• Decisions must be made in the near term to open up new markets in preparation for the long-term growth of output. Board expects pipeline application On an upbeat note, the board said it is confident a major pipeline application will be filed and a clearer understanding on the next step for market expansion (to California and Asia) will be known by mid- to late-2006.
Spurred on by sustained high oil prices, oil sands operators and investors have been encouraged to develop additional projects, raising expectations for mining and in-situ operations to 1.3 million bpd in 2006, or 20 percent above 2004 levels, the board said.
It said production from integrated mining, extraction and upgrading plants has doubled over the last five years to 650,000 bpd, although the unplanned outages will keep actual volumes well short of that peak.
In-situ bitumen production, using a variety of technologies other than mining to remove the raw bitumen, has increased by 34 percent over the same period to 386,000 bpd.
On the global front, the board said key drivers likely to underpin the market through 2006 include a strong demand growth for transportation fuels in China.
It also forecasts:
• Non-OPEC supply growth will be 1 million bpd in 2005 and 1.3 million in 2006.
• The resulting call on OPEC will be 29.5 million bpd in 2005 and 30 million in 2006.
• OPEC’s spare capacity will be limited to about 1 million bpd over the next two years.
• Transportation bottlenecks and the lack of spare refining capacity worldwide were issues in 2004 and are expected to be problematic in 2005 and 2006.
• Geopolitical risks will continue to be a concern.
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