Pipeline capacity could pose a greater constraint on future Canadian oil sands development than water or natural gas availability, government officials suggested on June 6.
"Pipeline capacity will be tight by 2007. There will be some incremental increases from then until 2009. Beyond that, more capacity will be needed," said Colette Craig, a resource analyst with the Canadian National Energy Board.

Refiners in Canada and the US Upper Midwest, Rocky Mountains, and Washington state are poised to take more crude oil, and export pipelines already have expanded in response, she said. But future export pipeline growth will depend on factors ranging from overseas competition to blends required for transportation and by environmental standards, Craig said.
"We have identified a number of refinery expansions. Some have been delayed, but with the widening differential between light and heavy crude oil, they may be accelerated," she said.

Her observations came during a presentation in Washington, DC, by three Canadian federal officials on NEB's latest oil sands outlook, which was released on June 1. That outlook forecasts production from oil sands growing to 3 mm bpd by 2015, a 40 % increase from the 2.2 mm bpd estimate in a report issued 2 years ago. Canada's oil sands production in 2005 was roughly 1.1 mm bpd, NEB said.
"Oil sands are going to be a major component of the energy supply picture out to 2030," predicted John McCarthy, the NEB commodities unit business leader, who led the presentation at the Centre for Strategic and International Studies.

Proposed new projects are divided roughly evenly between in-situ recovery and mining, with a little more weight on mining, NEB resource analyst Bill Wall said following the presentation.
Each method can present problems, noted Murray Smith, Alberta's Washington-based minister-counsellor. In-situ recovery has less visible environmental impact and requires less extensive reclamation than mining but consumes more water and gas. About2.5-4 bbl of water are required to produce each barrel of bitumen from oil sands, McCarthy said. Efforts are under way to use water more effectively by recycling it, storing it, or using less pure water, he added.
"You're likely to see that conditions for approval of many new mines will include better water management. It's not so much a matter of running out of water along the Athabasca River than it is maintaining its environmental integrity," McCarthy said.

Smith said ponds near oil sands mines in Alberta contain about 100 mm cf of water.
“There is technology using gypsum to break down the oil sands tailing fines in the ponds, but it's expensive," he said. He said the province's energy utilities board includes water management requirements in permits.
"Progress is being made. I think it's possible that the size of the ponds will be reduced in another 5 years," he said.

Wall said almost all new in-situ recovery processes use steam-assisted gravity drainage instead of cyclic steam generation. Production by both mining and in-situ methods is expected to consume 2.1 bn cfpd of gas by 2015, the report said. Supplies from the Western Canadian Sedimentary Basin should be able to meet that need, McCarthy said.
"The last 2 years have shown how dramatically conditions can change. It's possible even less gas will be needed to produce bitumen from oil sands. The market will dictate where it's used," he said.