SPECIAL REPORT: Alberta bitumen output to triple in next 10 years

Sept. 25, 2006
Forecasts show that bitumen production in Alberta from oil sands will almost triple in the next 10 years as many new projects come on stream.

Forecasts show that bitumen production in Alberta from oil sands will almost triple in the next 10 years as many new projects come on stream.

Companies continue to lease many potential oil sands areas in Alberta that may hold 173.7 billion bbl of remaining established reserves of bitumen, according to the latest Alberta Energy and Utilities Board (EUB) estimates.1

A variety of companies has secured acreage in the three areas in Alberta that have the most potential: Athabasca, Peace River, and Cold Lake (Fig. 1). Together, these three areas cover about 54,000 sq miles.

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Some companies, such as Petro-Canada, have established thermal in situ oil sands production and are partners in surface-minable projects already and have additional projects planned for their lease holdings using either more thermal in situ, such as steam-assisted gravity drainage (SAGD), or surface mining. Other companies without current bitumen production, such as North American Oil Sands Corp., have in the last few years leased large amounts of acreage and have plans to start bitumen production, also with SAGD.

Recent entrants to the area include Korea National Oil Corp., South Korea’s state-owned oil company, which recently bought in the Cold Lake region the Blackgold Mine from US-based Newmont Mining Corp. and has plans to produce about 35,000 b/d for 25 years, starting in 2010 with SAGD.

Some in situ projects produce bitumen through primary pumping methods, but most projects require thermal stimulation to recover the bitumen. Cyclic steam injection and SAGD are the most common thermal methods.

Also because of the high cost of natural gas, various companies have ongoing pilots and research projects for including solvents in the recovery process either included with the steam or in a vaporized form (Vapex) that could lower production costs.

The SAGD process typically involves drilling two horizontal laterals, one about 5 m above the other. Steam injected into the top lateral forms a steam chamber that heats the bitumen that flows into and is produced from the lower lateral.

The plans of both North American and Petro-Canada illustrate the types of projects that will begin during the next 10 years in Alberta’s oil sands.

Reserves estimates

EUB in its latest reserves and outlook report estimated that Alberta’s oil sands contained 1.69 trillion bbl of bitumen in place and have produced 5 billion bbl through 2005. Of the 173.7 billion remaining established reserves, the report said 10.2 billion bbl are under active development.

For calculating reserves from minable areas, EUB uses a combined mining and extraction recovery factor of 82%. It says this recovery factor reflects the combined average loss of 18% of the in-place volume by the mining operations and the extraction facilities. The recovery factor leads to its calculated 31.7 billion bbl of remaining established minable crude bitumen reserve as of yearend 2005, of which about one-quarter is under active development.

EUB based its estimated in situ initial established reserves on a minimum 10-m zone thickness in all zones except for the Wabiskaw zone in the Athabasca area, in which it used a 15-m cutoff. For primary recovery processes, it used a 3-m cutoff. Another of its criterion was a minimum saturation cutoff of 3% by mass in all deposits except for Athabasca and Cold Lake, in which it used a 6% cutoff.

For determining recoveries in areas outside of the active projects, it applied nominal recovery factors of 20% for thermal development and 5% for primary projects.

EUB estimated that the areas under active development held 2.6 billion bbl of remaining established reserves. It based these reserves on nominal recovery factors of 5% for primary schemes, 25% for thermal in the Cold Lake area, 40% for thermal in the Peace River area, and 50% for thermal in the Athabasca area.

Production forecasts

EUB forecasts that bitumen production for both mined and in situ bitumen will increase to 2.9 million b/d from 1.06 b/d in 2005 (Fig. 2). The mined portion increases to 1.8 million b/d from 625,000 b/d in 2005, while in situ production increases to 1.1 million b/d from 438,000 b/d in 2005.

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In 2005 about 8,000 wells in Alberta produced in situ bitumen at an average 57 b/d/well. The in situ and primary projects through yearend 2005 have produced 1.6 billion bbl of bitumen.

Operators of the three producing mining projects are Suncor Energy Inc., Syncrude Canada Ltd., and Albian Sands Energy Inc. Through yearend 2005, these projects had recovered 3.7 billion bbl of bitumen.

EUB included the following projects for estimating future bitumen recovery from mining projects:

  • Suncor’s existing production and expected expansions, including Voyageur.
  • Syncrude’s existing and expected expansions, including Stage 3 and Stage-3 debottleneck of the four-stage project that began in 1996.
  • Albian Sands debottlenecking projects and expansions scheduled for completion by 2011.
  • Canadian Natural Resources Ltd.’s (CNRL) Horizon project, approved by EUB in January 2004, with production starting in 2008.
  • Shell Canada Ltd. Jackpine Mine Phase 1, approved by EUB in February 2004, with production expected 2 years after the Muskeg mine expansion in 2011.
  • Petro-Canada’s Fort Hills project, approved by EUB in October 2002, with production starting in 2011.
  • Imperial Oil Ltd.’s and ExxonMobil Corp.’s Kearl mine, with start-up planned for 2010.
  • Total E&P Canada Ltd.’s Joslyn North Mine, expected to start producing in 2010.
  • Synenco Energy Inc.’s Northern Lights mining and extraction with an initial start in 2010.

The EUB report did not list specific projects used in its in situ bitumen production forecast.

North American

North American Oil Sands Corp. plans to develop a SAGD project in acreage that it has acquired in the last 2 years.

Formed in 2001, North American now employs about 42 people. Major shareholders of North American include Paramount Resources Ltd., ARC Energy Funds, and the Ontario Teachers’ Pension Plan Board. ARC is a Calgary investment company and the Ontario Teachers Pension Plan is Canada’s second-largest pension manager.

North American’s planned Kai Kos Dehseh project includes an upgrader in Edmonton to handle a maximum 160,000 bo/d of bitumen production by 2015.

The company holds interest in 226,560 gross acres of oil sands leases that contain an estimated 1.2 billion bbl of P50 (50% probability) resources, according to calculations made for the company by GLJ Consultants. Its holdings are in four core areas: Leismer, Corner, Hangingstone, and Thornbury that are surrounded by other company SAGD projects in various stages of completions (Fig. 3).

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“The leases are geographically concentrated to achieve critical mass, but benefit from risk diversification provided by reservoir variability,” according to Mike Langley, senior vice-president business development, for North American Oil Sands Corp.

Langley told OGJ that “most good areas in the oil sands areas are already under lease, with mostly speculative acreage remaining.” He added that North American has accumulated acreage since 2004.

North American’s planned projects include five distinct SAGD facilities and four smaller satellite hubs. Each hub will have a central processing facility for steam generation and bitumen processing and several phases of well development, as is typical for most SAGD projects, that will maintain each facility at capacity for the life of the projects.

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North American plans a stepped development program that starts with 10,000 bo/d production from the Leimer lease in 2008-10 (Fig. 4).

Its two-phase upgrader program will allow production from the other leases to reach 80,000 b/d in 2011 and 160,000 b/d by 2015. Phase 1 of the upgrader will include coking and hydrotreating, Phase 2 will include coking, hydroprocessing, and coke gasification (Fig. 5).

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As with most upgraders, the upgrader will process the extra-heavy crude into refinery-ready synthetic crude oil that can be processed into gasoline, diesel, and other fuels. North American plans to locate the upgrader near Edmonton to allow easy access markets for the products.

Langley said the company has delineated its leases with 121 wells boreholes and uses a 15-m cut off to determine producing formation. He expects recovery factors from the leases of 40-50%, based on results from established nearby SAGD projects.

North American also will test solvents to see if they improve SAGD recovery. Langley said North American will be able to obtain the solvents from its upgrader, once it is completed.

Water for the steam will come from more saline water found in deeper formations.

Langley sees no problem in obtaining natural gas for steam generation, but he said that the company will also be looking a lower cost power alternatives such as gasification of the heavy ends produced in the upgrader. The carbon dioxide from the gasification process has the potential use for enhancing oil recovery in many oil fields in Alberta, he added.

Langley expects government approval of North American’s plans by yearend 2006.

Petro-Canada

Petro-Canada has an integrated strategy for producing its oil sands resources (Fig. 6). Its plan expects to produce up to 320,000 b/d of synthetic crude and refined products after 2014.

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The plan combines upgrading capacity at Syncrude and Edmonton with a processing agreement at Suncor to produce 135,000 b/d of ultra-low sulfur refined products for its existing Edmonton refinery.

Included in the plan is a new upgrader outside Edmonton for upgrading bitumen from the Fort Hills mine. Petro-Canada’s share of the Phase 1 of the upgrader will be about 80,000 b/d. It also expects subsequent upgrader expansions as more bitumen becomes available.

Neil Camarta, senior vice-president for oil sands operations of Petro-Canada estimated that the company has about 10 billion bbl of recoverable bitumen in both its minable and in situ resources (Fig. 7).

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He said Petro-Canada uses a 90% recovery factor for its mines and 50+% recovery factor if “the dirt is good” to estimate resource potential.

Petro-Canada has a 12% interest in Syncrude that produces 350,000 b/d and is the world’s largest integrated mining and upgrading operation. Syncrude has operated for more than 25 years and Petro-Canada says it has used its experience at Syncrude for designing its Fort Hills integrated mining and upgrader project.

The company also is one of the first to initiate a commercial SAGD project. Its MacKay River project has produced for the last 3-years and Petro-Canada expects to reach the target production of 27,000-30,000 b/d by yearend 2006 (Fig. 8).

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The company notes that the 2.5 steam-to-oil ratio at MacKay is one of the best in the industry and credits the low ratio mostly to the high quality of sands with 80% bitumen saturation on the property (Fig. 9). Petro-Canada says operating costs at MacKay are in the range of $6 (Can.)/bbl of bitumen plus 1 Mcf of natural gas. At full production, it is targeting $4-5 (Can.)/bbl for costs other than gas.

Petro-Canada handles the environmental concern regarding water by recycling all water.

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Petro-Canada’s largest growth will come from the Fort Hills project that it and its partners UTS Energy Corp. and Teck Cominco Ltd. have target 2011 for first production. Petro-Canada estimates that the property has upside potential of recovering 2.8 billion bbl.

It expects the mine initially to produce between 100,000 b/d and 170,000 b/d, depending on the final configuration. Future expansions may increase production up to 400,000 b/d.

Petro-Canada will build its upgrader near to Edmonton to provide a better labor pool and lower construction costs. The upgrader will include delayed coking, the same as at Suncor and at its Edmonton refinery.

Petro-Canada expects to submit its commercial application for the Fort Hills project by yearend 2006 and expects a regulatory decision by late 2007, with construction lasting 3 years and first oil production starting in 2011.

The company has also several SAGD projects in its plans. An expansion at MacKay River, by 2010, will increase production by 40,000 b/d.

On its Lewis lease, it has evaluated the lease with 130 wells, or up to 8 wells/section in some areas. Canadian sections are 1 mile square. From this work it estimates that the lease contains a potential 3 billion bbl of bitumen resources.

It has also delineated the Meadow Creek lease with eight wells/section.

For both Lewis and Meadow Creek, Petro-Canada has not announced a definite timetable to first production.

Camarta noted that in situ recovery requires about twice the energy to recover 1 bbl of bitumen as mining and that Petro-Canada is investing in a pilot project to find new ways to reduce energy needs.

Reference

  1. Alberta’s Energy Reserves 2005 and Supply/Demand Outlook 2006-2005, ST98-2006, Alberta Energy and Utilities Board, May 2006.