With over 200 billion barrels of bitumen in place, the Cold Lake deposit represents an elephant oil resource by any measure. True, it’s usually been overshadowed by the Athabasca oilsands, more than six times larger in volume, that lie immediately to the north. But nearly $100 billion in Athabasca projects remain deferred or cancelled. At Cold Lake, in contrast, new projects are being launched and established producers continue to expand.
“The first thing you look for is a quality reservoir, which means the rock. If you get the rock right, you have a good chance at success,” Richard Todd, chairman and CEO of Osum Oil Sands Corp., told an investment symposium sponsored by the Canadian Association of Petroleum Producers (CAPP) in late June. “Cold Lake is the rock-solid foundation for our company. It’s the best of the best in the Canadian in situ oil business. It’s the region where the most thermal in situ production comes from. Between 10 and 15 per cent of Canadian oil production comes from this area.”
Osum’s Taiga thermal project targets bitumen production of 35,000 barrels per day. The private company has shot 20 kilometres of 2-D seismic, 32 square kilometres of 3-D seismic, and drilled 52 core holes on its 29-section prospect. A commercial application is scheduled for this year, with first oil expected in 2014. “We are planning on going to full production. We are not a land flipper,” Todd said.
The company is high on Cold Lake for a number of reasons. Bitumen is a higher quality than in the Athabasca region, at an average 11°API. The Cold Lake deposit is also closer to market, meaning lower transportation costs. But probably most important is the long experience developers have in thermal in situ production at Cold Lake. Because of this experience, less upfront experimentation is necessary before commercial development. “There’s no need to pilot; we are going right to commercial development,” Todd told the CAPP investor meeting.
Osum has raised $375 million to finance Taiga. Horizontal wells are planned for both steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). Besides well pads, the project’s components include a central steam generation plant plus steam delivery and product recovery pipelines. Water treatment and recycling, bitumen treatment, and deep wells for safe disposal of concentrated brackish water will also be installed. Osum is evaluating the possibility of electricity cogeneration to increase overall energy efficiency.
Imperial Oil Limited was the pioneer producer at Cold Lake, first piloting thermal development in the area in 1960s before launching commercial production in 1985. Since then, the company has developed 13 commercial CSS phases. Daily production now averages 150,000 to 160,000 barrels from over 4,000 wells located on approximately 200 pads. Its leases total 190,000 acres.
Imperial’s next move at Cold Lake will be the Nabiye bitumen development, with a resource base of 250 million barrels. When completed, Nabiye will produce 30,000 barrels a day. Imperial received regulatory approval for the expansion in 2004, but has since changed its plans in response to new technologies. Those amendments should be filed with provincial authorities later this year.
The alterations include a 170-megawatt cogeneration facility and pad layout changes that will reduce the production footprint. Sulphur recovery units have also been added. The original Nabiye plan also calls for the construction of steam generation, bitumen and water processing facilities, and other field facilities. When the project was first proposed, Imperial put the cost at around $700 million. No new cost estimate has been released.
Imperial president and CEO Bruce March expects the Nabiye expansion to be on stream by 2015. March said the development would follow the pattern established by previous expansions at Cold Lake. “We’ve been steadily able to grow production using the phased development model-the ‘design one, build many’ approach,” he explained. In his view, staging development enables Imperial to better manage costs and “add in new technologies to enhance recovery.”
Since 2002, Imperial has also internally developed a process called LASER (liquid-assisted steam-enhanced recovery) that’s expected to increase bitumen recovery by 10 to 15 per cent. LASER is designed for mid- to late-life CSS wells where steam has to travel further before contacting the bitumen. The technology involves adding diluent to the steam before it’s being injected. Imperial has now filed an application with the Energy Resources Conservation Board to deploy LASER for all of its existing Cold Lake wells.
EnCana Corp. and its partner ConocoPhillips are also continuing to develop their leases at Foster Creek on the Cold Lake Air Weapons Range. Phases D and E at Foster Creek were commissioned in the second quarter of 2009, each adding 30,000 barrels per day of new production capacity. The expansion is now ramping up and is on target to exit 2009 at more than 90,000 barrels per day.
Also, in the second quarter of this year, a regulatory application was initiated for Foster Creek’s phases F, G, and H. Again, each phase is designed at about 30,000 barrels per day. While the partners have yet to receive regulatory approval or internally sanction the three new phases, EnCana’s executive VP said the project is scheduled to proceed promptly. “We have not slowed down any of our developments like some of the other operators had done when the oil prices slowed down,” said John Brannan, who’s also president of EnCana’s integrated oil division.
EnCana reports that the most recent expansions at Foster Creek came in at a cost of around US$15,000 per flowing barrel, as expected. “I think we haven’t seen substantial cost reductions because a lot of the things that we bought, like steam generators and steel and those kind of things, are ordered and bought ahead of time,” Brannan said. “We may see some reductions as we go into these future phases.”
The EnCana executive VP added that worker productivity is improving. “We’re not having the turnarounds that we had when we lost crews and stuff to other major projects in the Fort McMurray area and those kind of things,” Brannan said. “We think that we’re cutting some time off of [new projects]. We used to say it’d take, say, 36 months; now we’re saying maybe we can do them in 30 months. So ultimately, when we do these new projects, hopefully we’ll see some improvements if the market conditions stay where they’re at today.”
EnCana is also working to increase recovery at existing facilities at Foster Creek through a new technology it recently patented called wedge wells. These horizontal wells are drilled between two existing well pairs, tapping the “wedge” of bitumen stranded between them.
Canadian Natural Resources Limited (CNRL) also has a long record of success in the Cold Lake oilsands. The company currently has 120,000 barrels per day of capacity from its thermal operations at Primrose, Burnt Lake, and Wolf Lake. In addition, CNRL says it has potential incremental thermal capacity of approximately 285,000 barrels per day of incremental thermal production, spread between the Athabasca and Cold Lake deposits. At Cold Lake, its bitumen resource is estimated at 11 billion barrels.
CNRL completed its most recent expansion, its Primrose East project, last October. Located about 15 kilometres from its existing Primrose South steam plant and 25 kilometres from its Wolf Lake central processing facility, the Primrose East expansion added 40,000 barrels per day of capacity. Steve Laut, president of the Calgary-headquartered firm, described its thermal assets as “the most underappreciated and misunderstood part of our portfolio. They are clearly a hidden gem.”
To reveal the value of that gem, CNRL has plans to add 30,000 to 60,000 barrels per day of in situ production every three years for the next 15 years. According to its original Primrose plans, another 23 well pads will be drilled over the next 25 years to maintain production in the area. Simultaneously, CNRL is now focusing on the southern Athabasca oilsands. “At Kirby, our next 40,000 barrel day of incremental production, we expect to receive regulatory approval this year,” Laut said. “Before we kick off the development, we’ll need this regulatory approval, as well as the completion of the detailed engineering design work.”
Pengrowth Trust is in the early stages of developing its Lindbergh assets in the Cold Lake region. The company drilled five vertical core hole wells in the first quarter of 2009 as it moves towards launching a pilot project. Bill Christensen, VP of strategic planning and reservoir exploitation for Pengrowth, said the Calgary-based trust has 1.7 billion barrels of bitumen in place on its leases, and hopes to develop a project producing 10,000 to 20,000 barrels per day.
The pilot SAGD project is expected to commence in 2012 with commercial production planned for 2016. Christensen said Lindbergh could have a big impact on the future of the trust. If successful, the thermal project could account for an estimated 40 per cent of Pengrowth’s proven-plus-probable reserves.
Husky Energy, one of Canada’s most successful oil developers (East Coast, China, and Lloydminster) is convinced that its Cold Lake Tucker in situ project is on the brink of success. Thirty-two well pairs drilled in 2006 failed to meet expectations of 30,000 barrels per day. In 2007, optimization work continued on the original wells and eight new well pairs were drilled.
“Tucker is one of the best projects, producing in the range of 3,000 to 5,000 barrels per day,” Husky CEO John Lau told analysts during its second-quarter telephone conference. “We have no intention to push production up yet, because of volatility in the oil price, but we’ll definitely keep our options open.” The company plans on the second project reaching volumes of 5,000 to 6,000 barrels per day by year end.
Shell Canada and Devon Energy are two more powerful players in the Cold Lake play. Shell’s Orion project at Hilda Lake can produce 10,000 barrels per day, but a proposed doubling of that capacity is on hold while the company reworks its oilsands plans. In 2008, Devon drilled 321 wells at its Iron River and Manatokan cold production properties, and plans another 130 in 2009.
Budgeting for new thermal in situ projects is beset by uncertainties over crude prices, construction costs, and government levies on greenhouse gas emissions. Calgary-based consultant Bob Dunbar, president of Strategy West Inc., told the Global Energy Conference in June that new SAGD projects will require a stable WTI light oil price of US$70 to US$80 per barrel to yield a 10 per cent return on investment.