Devon Canada launched its long-awaited $30-million DOVAP heavy oil extraction test facility last week near Fort McMurray, while a battle between heavy oil and natural gas producers in the Athabasca oilsands appeared far from over.
“The government will continue to support this kind of (project) because we know that the payoff will be many hundred times our initial investment,” said Alberta Energy Minister Murray Smith during a commissioning ceremony at the site, about 55 kilometres northwest of Fort McMurray.
The province and federal government each provided $7.5 million while industry injected $30 million into the project that may quicken the pace to replace natural gas as the feedstock of heavy oil equipment.
The term DOVAP refers to the place name Dover, the site of a former underground oilsands test facility in the Athabasca oilsands, and the VAPEX process, whereby vapourized solvents are injected into heavy oil.
VAPEX is seen as a possible successor to steam-assisted gravity drainage (SAGD), a gas-powered process that creates steam to separate bitumen from the oilsands. The new process is also seen as a way to recover bitumen from zones that are considered too thin for traditional thermal recovery.
In the VAPEX process, two drills – an injector drill and a producer drill – are placed about 10 metres apart from each other and injected into the ground at 45-degree angles. Underground at a depth of 170 metres, the drills level off, with the injector 10 metres above the producer, to access the well horizontally.
The DOVAP site also has a SAGD facility, so Devon will compare and contrast the two processes.
“There’s a recycling of the solvent that is the economic driver here,” said Dean Britton of Devon Canada, as media toured a computerized control room and later a tunnel 180 metres below the site’s surface. “It’s a cycle of solvent around and around into the reservoir and back out of the reservoir.”
SAGD is causing financial, environmental and political headaches as natural gas reserves in the Western Canadian Sedimentary Basin become depleted while U.S. demand increases.
Canada must also reduce greenhouse gas emissions by 2010 in compliance with the Kyoto Protocol, and there are concerns about excessive potable water use and damage.
“We have a lot riding on VAPEX,” said Smith, adding that, if successful, the process will generate billions in new revenue for Alberta. He also indicated the province will likely provide more funding for the project if it becomes commercially viable.
“Attention to environmental stewardship is a top priority,” said Smith. “This fits – this fits like a glove.” Devon Canada president John Richels said VAPEX will help the company save money on above-ground facilities that will no longer be needed if the process proves commercially viable.
“There’s no water treatment, there’s no water recycling, there’s no cogeneration, a whole lot less sort of nuts-and- boltsy things that you have to put above ground,” said Richels.
(According to a Devon environmental safety officer, VAPEX will still require some water to lubricate the well site as the drilling machinery starts up, but water flow will be shut off once the bitumen begins to flow.)
Although the DOVAP pilot project is expected to last five to 10 years, making the race to replace natural gas a marathon instead of a sprint, Richels said all signs indicate the company will be able to produce bitumen at a lower cost and enhance its net-back.
The commissioning of the site culminated a 20-year quest to get the underground test facility up and running. But the question of how to appease natural gas producers is just beginning.
The EUB has decided to permanently shut in (i.e. shut down) more than 900 producing gas wells in the Athabasca oilsands region. Heavy oil producers argue that producing the gas, which lies on top of the oilsands bitumen, lowers the pressure in the reservoir, which makes it much harder to extract the bitumen. The EUB says the bitumen has an energy value 600 times greater than the gas.
Gas producers including Paramount Energy, which has the most gas production to lose in the Athabasca area, have banded together and launched two legal actions to overturn the EUB decision.
However, during the Heavy Oil Conference held last week in Fort McMurray, Harbir Chhina, vice-president of EnCana’s oil recovery business unit, said heavy oil and natural gas producers can work together in the oilsands. “Gas production does not have a negative impact on bitumen recovery,” said Chhina.
He said the EUB should rule on gas vs. bitumen on a site-by-site basis rather than make a blanket decision. But Smith countered that the EUB is already doing so by allowing companies to apply for exemptions from the scheduled Sept. 1 shut-ins.
As a result of the EUB’s decision, EnCana, which has also developed technology that uses submerged electrical pumps to bring natural gas to the surface, along with lower-pressure SAGD and solvent-injection systems, has exchanged natural gas and PNG rights with Devon at Christina Lake and Senlac pilot sites.
The province may compensate natural gas producers whose wells are shut in, Smith said, but Bob Dunbar, a senior research director with the Canadian Energy Research Institute, told Business Edge the shut-in wells only account for three per cent of gas production.
He predicted that with EnCana, Canada’s largest oil and gas company, supporting natural gas production over bitumen reservoirs, the EUB will shut in even fewer wells.
Dunbar said companies must find alternatives to natural gas to power heavy oil equipment, noting that gas reserves in the Western Canada Sedimentary Basin will decline in coming years.
“If oilsands projects use the same amount of energy in the future as they’re using today, they’d be consuming more than 10 per cent of all of Western Canada’s gas production – which is just too high,” said Dunbar.
“There’s two alternatives. They can either reduce their energy requirements or they can use other forms of energy.”
However, Rick Hyndman of the Canadian Association of Petroleum Producers (CAPP) warned new fuel sources don’t necessarily mean lower emissions.
“It’s quite possible by switching fuel sources in the oilsands, there will be no effect or a lowering of emissions,” Hyndman, a former deputy energy minister, told conference attendees.
Blaming the global rise in greenhouse gas emissions on rapid Third World population growth, he predicted Canadian emissions will be at least 100 megatons per year above the Kyoto target.
“By having onerous policies in place, we can make production in the oilsands less profitable,” said Hyndman.
Federal Natural Resources Minister Herb Dhaliwal has advised CAPP that Ottawa wants emissions to be 15 per cent below business-as-usual by 2010.
Hyndman said the 15 per cent target “went a long way” to easing investors’ concerns, but it left a gap between Kyoto’s targets and where Canada will actually wind up. He called on Ottawa and the province to harmonize their positions on Kyoto, noting Ottawa wants Canada to be at 94 per cent of 1990 emission levels while Alberta is aiming for 50 per cent of 1990 levels by 2020.
“Climate change is a long-term issue and we need a long-term strategy,” said Hyndman, adding “the real focus has to be on efficiency of end use.”
Meanwhile, a Canadian company, OPTI Canada Inc., will start construction on a $3-billion integrated SAGD upgrader at its Long Lake site next year.
When operations commence in 2006, OPTI Canada’s OrCrude process, which burns the heavy ends of the reservoir to produce synthetic gas and steam for power purposes, is expected to produce 70,000 barrels per day from 1.5 billion barrels worth of reserves at Christina Lake when operations commence in 2006.
The process does not use any surface water, said OPTI Canada president Sid Dykstra. But he admitted that the facility will increase carbon dioxide emissions by 0.18 tonnes, hiking costs by 40 cents per barrel.
“Long Lake provides a number of solutions to oilsands production,” said Dykstra.
