Operators are turning increasingly to sophisticated in situ techniques to tap deeper formations in the oil sands regions of northern Alberta. But surface mining operations still account for the largest share of investment dollars and growing production.
The oil sands sector is projected to produce more than 50% of Canada's oil by 2010 and is expected to make a significant contribution to North American supply.
About 80% of an estimated 300 billion bbl of bitumen can be recovered only by techniques such as steam-assisted gravity drainage (SAGD) instead of conventional surface mining. Operators say SAGD also has the advantage of being more environmentally friendly than surface mining.
However, established mining operators such as the Syncrude Canada Ltd. consortium, Suncor Inc., and Shell Canada Ltd. are all involved in major ongoing expansion efforts. And they account for much of the $24 billion (Can.) spent or committed to date to increase oil sands production. An additional $25 billion in projects is under consideration over the next decade (see table). Click here to view Alberta-Approved Oil Sands Projects.pdf.
All of the firms mentioned in this report are based in Calgary-except where noted otherwise-and all dollar amounts are Canadian dollars.
Syncrude Canada
Syncrude Canada Ltd., the largest mining operator and oil sands producer, is continuing with an expansion program to increase its production by 40% to 368,000 b/d by 2005. The four-stage Syncrude 21 program, with planned spending of $8 billion for 1996-2007, is now in its third stage.
Consortium owners have approved $4 billion in capital spending, and the third stage is proceeding, including a major expansion of the upgrader at Syncrude's original Mildred Lake mining site and addition of a second production train to the Aurora Mine, which began operations in 2000. Aurora is 22 miles northeast of Syncrude's original mine.
Upgrader expansion is expected to be completed in time for start-up in late 2003. The upgrader project will include new froth treatment and diluent recovery units, as well as a new fluid coker, distillate hydroprocessor, two new hydrogen plants, a sulfur plant, an amine plant, and a sour water treater. A flue gas scrubber will be added, as will new cooling towers and a condensing turbine generator. The work will increase Syncrude production by more than 100,000 b/d to about 135 million bbl/year.
Phase 4 of the program is scheduled to begin in 2004 and run to 2008 with a projected cost of $2.3 billion. It will include a third production train at the Aurora Mine and the final stage of expansion of the Mildred Lake upgrader. It is expected to increase Syncrude production to 170 million bbl/year.
The group spent $828 million in 2001 on capital projects and has earmarked $2 billion this year, including about $1.75 billion planned for the engineering, procurement, and construction related to the Stage 3 expansion project. Syncrude says $1 out of every $4 is being spent on improving environmental, health, and safety performance and the introduction of new technology.
Syncrude has been working to reduce its operating costs, which rose to $18.47/bbl in 2001 from $17.20/bbl in 2000. Fourth quarter 2001 unit operating costs dropped to $15.86/bbl as a result of operating improvements at the Aurora Mine and completion of repairs to a Finer operating unit. Syncrude says it expects operating costs in 2002 to be $16.50-17.50/ bbl, reflecting increased production and a focus on operating reliability and cost reduction.
Shell Canada
The Athabasca Oil Sands Project (AOSP), in which Shell Canada Ltd. is lead partner, is nearing completion, and the construction phase is at its peak. Shell has a 60% interest, and US major ChevronTexaco Corp. and Western Oil Sands LP each hold 20%.
The project has an estimated cost of more than $5.2 billion (Shell's share is $3.6 billion) compared with an original total cost estimate of $3.5 billion. Shell spending in 2002 includes $890 million for the joint project and $100 million for modifications to its Scotford refinery. The project includes the Muskeg River Mine and extraction plant in the Fort McMurray region, a bitumen upgrader adjacent to Shell's Scotford refinery and refinery modifications, a power plant, and other related facilities. There will also be a 24-in. pipeline to move bitumen south from the mine to the Scotford upgrader near Edmonton and a 12-in. line to return diluent north to the mine.
Shell says the Muskeg River Mine is now more than 80% complete, and the upgrader is 70% complete. The first batch of diluent was moved in April, and the pipeline systems will be commissioned in the third quarter. The first crude production is scheduled for late 2002 or early 2003. Shell expects the Muskeg Mine to reach full production of 155,000 b/d by mid-2003. The mine will have a 30-year life, and Shell has a resource of about 9 billion bbl of bitumen in the area.
A Shell spokesman said the company is now looking at a number of other options for additional oil sands expansion in the area.
These would include expansion of the Muskeg River Mine operation to 225,000 b/d during 2005-10. Another option under consideration is development of the Jackpine Mine, a new mining operation on Lease 13, where the Muskeg River Mine is located. Shell says that property has a capacity of 200,000 b/d of bitumen production. A second phase of the Jackpine Mine, on other leases with potential production of 100,000 b/d, is also a long-term option. The company's long-term goal is production of 530,000 b/d.
Shell said the company is looking at all the options for future expansion, and a regulatory filing for Jackpine Phase 1 is expected shortly.
Suncor
Suncor Energy Inc. completed its $3.4 billion Millennium mining expansion project in late 2001 and has increased its production capacity to 225,000 b/d from 115,000 b/d. A Suncor spokesman said there are still a few minor kinks in the Millennium operation, but it is now hitting its production target of 225,000 b/d more frequently. Production for first quarter 2002 averaged 212,300 b/d.
The company originally estimated oil sands operating costs in the first quarter would be $10.50/bbl, but they ended up at $16.35/bbl. The increase was attributed to one-time events and costs incurred in bringing forward maintenance, a power outage, and extremely cold weather. There were also costs related to the transition to Millennium facilities. Suncor now expects costs to average $12.50/bbl this year and has set a target of $8.50-9.50/bbl over the next 18 months.
Suncor now is focusing on two new long-term projects, the Firebag in situ project and the long-term Voyageur expansion project.
The Firebag SAGD project first phase is now under construction 25 miles north of the company's existing oil sands operation on leases covering more than 620 square miles with estimated resources of 9.6 billion bbl of bitumen.
Firebag is seen as a four-phase project, with each phase adding 35,000 b/d to production for a total of 140,000 b/d. The initial phase would increase Suncor production to 260,000 b/d by 2005. Suncor also would add a vacuum tower complex and upgrading capacity to handle the additional Firebag production.
The company says it will apply this year for regulatory approval for the Voyageur project, part of a plan to increase oil sands production capacity to 500,000-550,000 b/d over the next 10 years. It said preliminary cost estimates for Voyageur will be made late in 2002, after market analysis, engineering, and environmental and socioeconomic impact assessments.
Canadian Natural Resources
Canadian Natural Resources Ltd. (CNRL), one of Canada's largest independents, is completing project definition and plans filing for regulatory approvals by midyear for its Horizon oil sands project on leases in the Athabasca sands 50 miles north of Fort McMurray.
CNRL Vice-Pres. Real Doucet says the project, with an estimated $8 billion price tag, will involve four major components: surface mining and bitumen processing, in situ operations, an upgrader, and associated infrastructure.
Construction is slated to begin in 2004, subject to regulatory approvals. Doucet says the three-phase project would involve commissioning and start-up in 2006-07, with full production of up to 300,000 b/d of bitumen by 2010. CNRL says the Horizon project has potential for recovery of more than 5.6 billion bbl of bitumen over an estimated 50-year life span.
Doucet says CNRL plans to finance the oil sands project through cash flow but is also open to a joint venture approach. He said no decisions have been made about pipelining.
TrueNorth
TrueNorth Energy Corp. recently completed a detailed design and feasibility study for its Fort Hills oil sands mining project 56 miles north of Fort McMurray, increasing estimates of both costs and reserves from original estimates. A public hearing on the project before the Alberta Energy and Utilities Board is scheduled for July 2.
TrueNorth Pres. and CEO David Park said cost estimates for the project have increased to about $3.5 billion from $2.5 billion, and reserves estimates increased to 2.8 billion bbl from 2.4 billion bbl, with a life of 40 years vs. 30 years previously.
The project would include an open pit, truck-and-shovel mine, two bitumen processing trains, and associated infrastructure.
TrueNorth has done extensive drilling on the 39,535 acre property to delineate reserves.
The project calls for two phases: the first to be completed in 2005 with production of 95,000 b/d and a second designed to double production to 190,000 b/d in 2008.
TrueNorth hopes to receive regulatory approvals for the project this summer and begin construction this fall.
Park said drivers for increased costs for the project are industry issues not specific to the TrueNorth project. Major oil sands mining projects have recently exceeded original cost estimates by up to one third, with demand for skilled labor a significant factor.
The True North CEO said it is critical that the project stay on schedule and move efficiently through the regulatory process.
TrueNorth Energy is a wholly owned unit of Calgary-based Koch Petroleum Canada LP and is operator for Fort Hills with a 78% interest. UTS Energy Corp. holds 22%.
TrueNorth said it is expected that most of the Fort Hills bitumen would be upgraded and refined at Koch Industries Inc.'s Pine Bend refinery near St. Paul, Minn.
Petro-Canada
Petro-Canada is emerging as a leader in development of large-scale commercial in situ projects using SAGD production technology.
The company's $300 million Mac- Kay River in situ project is already under construction. The company has filed a regulatory application and is evaluating a second in situ project at Meadow Lake in the Athabasca region.
A spokesman said the 30,000 b/d MacKay River project is currently on schedule and on budget for full production in mid-2003.
Petro-Canada has a 100% interest in MacKay River, its first commercial SAGD oil sands project.
The company holds 76 sections of land in the area, 37 miles northwest of Fort McMurray.
The current project covers only 11.5 sections and has estimated reserves of 230-300 million bbl of bitumen to support production of 30,000 b/d for 25 years. The reserves estimate was based on extensive seismic and more than 200 delineation wells.
Petro-Canada was a participant for a number of years in thermal recovery pilot projects in the region. SAGD uses pairs of horizontal wells. Steam is injected into the upper well, where it heats and mobilizes the bitumen. The steam condenses back to water and flows to the surface along with the bitumen through the lower production well. The water is then separated, treated, and reused to generate more steam.
Petro-Canada's application for the Meadow Creek project, 28 miles south of Fort McMurray, covers the $700-800 million in situ project and a major refinery conversion at its Strathcona refinery, east of Edmonton, estimated to cost $4-5 billion.
The conversion program would allow the refinery to produce low-sulfur gasoline and replace its existing crude feedstock with bitumen. The first phase would convert the refinery's conventional light crude capacity to upgrade and refine 85,000 b/d of bitumen by 2007.
A possible second phase would add 85,000 b/d by 2010. A third phase of the in situ operation would be considered if the second phase of the refinery conversion is approved.
Petro-Canada holds a 75% interest and Nexen Inc. 25% in the Meadow Lake in situ project, with production of up to 80,000 b/d slated for 2007 start-up.
Long Lake
Another major in situ venture, the Long Lake project 25 miles southeast of Fort McMurray, is a joint venture of OPTI Canada Inc. and Nexen.
Nexen, which acquired a 50% working interest, will be operator for the SAGD project. It will involve a 3,000 b/d pilot project this year and a 35,000 b/d commercial project. Bitumen will be upgraded on site using patented OrCrude technology developed by OPTI's parent company, ORMAT Industries Ltd. OPTI will be responsible for design, construction, and operation of a 60,000-70,000 b/d upgrader, with a planned completion date in 2006. A second phase could add 70,000 b/d. OPTI has been operating a 500 b/d demonstration plant in the Cold Lake area since April 2001, processing bitumen from both the Cold Lake and Athabasca sands.
OPTI and Nexen also have formed a joint venture to develop additional opportunities in the Athabasca sands to upgrade both their own and third-party bitumen using OrCrude technology. OPTI has obtained from Nexen a 50% interest in 32 sections of land in the same region with plans for initial delineation work as soon as possible.
EnCana
EnCana Oil & Gas Ltd. (formerly AEC Oil & Gas Ltd.) has applied for regulatory approvals to build Phases 2 and 3 of an existing SAGD in situ project at Foster Creek in the Cold Lake area.
The $290 million first phase is ramping up to 20,000 b/d after starting up at 15,000 b/d in fourth quarter 2001. The $480 million second phase is expected to push output to 65,000 b/d by 2005, and the $230 million third phase would reach 100,000 b/d by 2007.
Another in situ project, at Christina Lake, is to begin steaming in the second quarter of this year, with production start slated for the third quarter. Phase 1 would ramp up to 10,000 b/d by 2003, followed with 40,000 b/d for Phase 2 (no date set yet), and 70,000 b/d expected in 2008. Total estimated outlays for this project would be $500 million.
