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Alberta wants value from oil sands resources Government explores closer integration of oil sands, petrochemical sectors to refine bitumen in Alberta and offset tightening supplies of ethane feedstock Gary Park Petroleum News Calgary Correspondent
Natural gas from the Mackenzie Delta and Alaska and abundant oil sands resources hold the key to an evolving strategy in Alberta to gain value-added benefits from upgrading, refining and petrochemicals.
The provincial government has flagged its desire in recent weeks to ensure its finite natural resources are used wisely to prolong their “vital place” in the Alberta economy.
In releasing a 20-year plan March 19 that charts a course for growth in research, technology and value-added products, the government said it is “committed to not only manage our traditional resources for maximum benefit but also to broaden our economic and social horizons,” said Dave Hancock, the cabinet minister in charge of the plan.
He had been preceded earlier this year by speeches that put heavy emphasis on capturing more of the wealth from Arctic gas and the oil sands.
Mark Hlady, chairman of the government’s standing policy committee on energy, told an oil sands summit that talks are taking place between the Alberta Chamber of Resources, the government and industry that could see a task force explore greater integration of the oil sands and petrochemical industries to deliver value-added petrochemical products.
He said action is imperative, given the opportunity new oil sands projects offer for “effective planning and co-development of integrated oil sands-petrochemical clusters.”
He noted that a joint industry-government study last year concluded that integration of oil sands upgrading, refining and petrochemical units is “technically and economically feasible.” Supplies for plants tightening Although chemicals and petrochemicals account for 20 percent of Alberta’s exports and the plants are “very competitive” on a world scale, they rely on tightening supplies of ethane and ethylene, Hlady said.
In addition to using bitumen as a low-cost feedstock, he said joint developments offer the advantage of a smaller environmental footprint and would contain the sources of greenhouse gas emissions.
If the government can facilitate the use of plentiful, low-cost bitumen byproducts as petrochemical feedstocks, Alberta could be highly competitive with the U.S. Gulf Coast refining sector, Hlady said.
He said the current discussions point to the petrochemical sector receiving 200,000 barrels per day of oil sands output and 80,000 to 120,000 bpd of ethane from Mackenzie Delta and Alaska gas (assuming a pipeline from the North Slope crosses through Alberta) over the next 10 to 15 years.
An C$8 billion refinery complex would be the catalyst in moving Alberta to the value-added stage, Hlady said, noting that currently 5,000 bpd of benzene and other gases are being shipped out of Alberta to the Gulf Coast and Eastern Canada, where they are turned into other products. Change in depreciation needed But attracting the capital investment could necessitate the Canadian and Alberta governments making capital costs 100 percent deductible against revenue, rather than depreciating over the life of a project, he said.
On the industry’s side, he suggested companies could share in utilities and infrastructure to minimize capital and operating costs, while creating hubs at strategic locations to make full use of the infrastructure.
Chris Holly, director of oil sands issues and planning with the Alberta Energy Department, told a Canadian Institute oil sands conference that the government’s objective is to see an increasing share of bitumen production remain in the province for processing.
“Where it makes sense, we would like to see the value-added production here,” he said.
George Rhodey of Rhodey and Associates echoed that view, insisting that Canada should refine the upgraded bitumen and export the petroleum products to the United States.
“Let’s keep the values in Canada,” he said.
Holly said there is growing pressure in the oil sands sector to lower the natural gas price risk to create some fuel on site.
The government and industry are in hot pursuit of ways to either reduce the use of natural gas, or use the gas more efficiently in bitumen recovery.
The government’s 20-year strategy said Alberta will “actively encourage the extraction of coalbed methane ... that has the potential to offset declining conventional natural gas reserves ...” Recovery projects large energy consumers Bob Dunbar, senior research director at the Canadian Energy Research Institute, noted that thermal in-situ recovery projects in the oil sands are “very large” energy consumers, burning about 1,000 cubic feet of gas for every 1 barrel of bitumen produced.
He said it is possible the oil sands could one day use about 10 percent of all gas produced in the Western Canada Sedimentary Basin, putting upward pressure on gas prices across North America, while creating incentives for more efficient gas use.
But Dunbar is hopeful that improved in-situ recovery techniques and non-gas fuel options, such as coal or nuclear power, could be economically competitive, even at “conservative” gas prices.
The urgency of developing those alternatives is echoed by the Canadian Chemical Producers’ Association, which reported a 6 percent increase in production last year to C$20 billion — even though exports were down 3 percent at C$12 billion — and is counting on another 5 percent hike this year.
But the association said higher feedstock and fuel costs had a dramatic negative impact on petrochemical margins, forcing the temporary closure of some plants.
With natural gas costs rising from US$2 per million British thermal units in 1990 to the current US$5.60 the advantage of cheap natural gas is now “one of our most pressing problems,” said Vice President David Goffin.
That makes the association one of the greatest boosters of the Mackenzie Gas Project, which it plans to tell regulators is desperately needed.
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