Exploration And Production In Canada
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Crude Oil

  • Canada produced almost 3.7 million barrels per day (bbl/d) of total oil in 2011, an increase of nearly 200 thousand bbl/d from 2010. Of this, 2.9 million bbl/d was crude oil and a small amount of lease condensate.
  • Oil production in Canada comes from three principal sources: the oil sands of Alberta, the conventional resources in the broader Western Canada Sedimentary Basin (WCSB), and the offshore oil fields in the Atlantic. Production from the oil sands accounted for over half of Canadian oil output in 2011, a proportion that has steadily increased in recent decades. In total, Alberta was responsible for almost 75 percent of Canadian oil production in 2011, according to an analysis of data from Statistics Canada. Other noteworthy producing provinces are Saskatchewan, with almost 14 percent of national output from its share of the WCSB, and offshore areas of Newfoundland and Labrador. Production in conventional offshore reserves off of the eastern provinces comes from mature oilfields, with few opportunities to mitigate decline rates. Accordingly, western provinces are expected to comprise an increasing proportion of overall Canadian oil production in the future.
  • Canada is expected to be one of the largest sources of growth in global liquid fuel supply, in both the near-term and long-term. Recent editions of EIA's Short-Term Energy Outlook forecast that Canada's production will grow by an annual average of approximately 200 thousand bbl/d in 2012 and 2013. Looking forward, the 2011 International Energy Outlook projects that Canadian production could grow to 6.6 million bbl/d by 2035 due to an expansion of unconventional output from the oil sands.

Oil sands

  • Canada's most important oil producing region is the Alberta sands, especially the Athabasca deposit. The oil sands – also referred to, often pejoratively, as the "tar sands" – are permeated with bitumen, which is a form of petroleum in solid or semi-solid state that is typically found blended with sand, clay, and water in its natural state.
  • Unconventional techniques are required of operators in the oil sands, which use two predominant methods to extract petroleum: traditional pit mining on the surface and in-situ production underground. When mined at the surface, bitumen-rich earth is shoveled into trucks for separation at a processing facility. Surface mining has historically been the largest source of production from the oil sands, but its share is expected to decline over time because approximately 80 percent of bitumen reserves are situated too deeply underground to be accessible to surface mining.
  • The other method, in-situ extraction, entails the injection of steam into underground formations to soften the bitumen and pump it to the surface through wells. Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) are the two leading in-situ extraction techniques. Given the sophisticated and expensive techniques involved, oil sands production has a relatively high break-even price: commonly cited ranges are $40-70/bbl for new in-situ projects and $80-100/bbl for new surface mining projects. Consequently, oil sands investments are uniquely sensitive to sustained changes in oil prices.
  • Once extracted, bitumen is a heavy, viscous type of crude oil. In order to flow in a pipeline, the bitumen must be diluted with condensate or other light oils or "upgraded" by complex processing units ("upgraders") into a light, sweet "synthetic" crude oil (SCO). Of the crude oil and equivalent production reported by Statistics Canada in 2011, roughly 28 percent was synthetic crude oil and 25 percent was non-upgraded crude bitumen.
  • The largest oil sands projects are surface mining operations, though there are a greater number of in-situ projects. The most notable current and planned oil sands operations include:
  • Syncrude Canada is a joint venture by leading oil sands operators in mining and upgrading operations in Aurora North Mines Oil Sands Project and Mildred Lake Mine Oil Sands Project, with a total estimated capacity of approximately 350 thousand bbl/d. Syncrude received regulatory approval for a roughly 200 thousand bbl/d expansion in Aurora South, but the completion of the project has been pushed back until the next decade.
  • Suncor Energy's production averaged 305 thousand bbl/d of upgraded SCO and non-upgraded bitumen in 2011, less than the nameplate capacity from its core Millennium Mine Oil Sands Project, as well as the Firebag Oil Sands Project and MacKay River Oil Sands Project. Suncor has announced a number of planned greenfield and brownfield expansions, of which an additional phase of Firebag is the closest to fruition (planned start-up in 2013). Other phases of Firebag, which would add another 200 thousand bbl/d, are expected by the end of the decade. A second phase of Mackay River and the Voyageur upgrader are expected for 2016 or later. Suncor also plans to jointly develop the Fort Hills mine (190 thousand bbl/d) with Total around the same timeframe, along with its Joslyn mine.
  • Shell Canada is the leading owner and operator of the Athabasca Oil Sands, which includes the Muskeg River mine (155 thousand bbl/d), Jackpine mine (100 thousand bbl/d), and the Scotford upgrader. Shell also has two small in-situ projects in the Cold Lake and Peace River deposits. A 100-thousand bbl/d expansion of Jackpine is scheduled for 2014, with other projects for later years in various stages of planning and regulatory review.
  • Canadian Natural Resources has two significant producing projects, as well as a number of large planned projects. Horizon Oil Sands Project is an integrated mining and upgrading facility that can produce 110 thousand bbl/d of light, sweet SCO in its first phase. Horizon will undergo process improvements and small expansions over the next few years, with much larger expansions tentatively planned for the more distant future. Its other large project, Primrose/Wolf Lake, has an in-situ capacity of 120 thousand bbl/d. The company also plans to bring online the in-situ Kirby Oil Sands Project, with first-phase peak production of 40 thousand bbl/d after start-up in 2013 or 2014 and expansions possible by 2016. Later this decade and into the next, Canadian Natural Resources aspires to construct other medium-sized in-situ projects, including Grouse, Birch Mountain, Leismer Oil Sands Project, and Gregoire Lake.
  • Imperial Oil operates one of the largest in-situ projects, Cold Lake, which has a current capacity of approximately 140 thousand bbl/d and could grow further with a 40-thousand bbl/d CSS expansion in 2014. Its Kearl Lake Oil Sands Project is among the most important new projects due in the short-term. Over the next year, it is supposed to ramp-up to an initial capacity of 110 thousand bbl/d, followed by an increase to 145 thousand bbl/d by the end of 2015. Imperial Oil has received regulatory approval for a total future Kearl capacity of up to 345 thousand bbl/d.
  • Cenovus operates two large in-situ projects, Foster Creek Oil Sands Project and Christina Lake Oil Sands Project, through a joint venture with ConocoPhillips. Foster Creek was the first commercial SAGD project and now produces approximately 120 thousand bbl/d. Production from its next three phases is expected to start in 2014, and ultimately to increase capacity to 210 thousand bbl/d after 2017. Christina Lake has been developed in three phases: the first two phases, of almost 60 thousand bbl/d in total, is joined by a 40-thousand bbl/d expansion that began its production ramp-up in the summer of 2012. Future expansions could increase production to almost 300 thousand bbl/d.
  • Devon Canada operates the Jackfish Thermal Heavy Oil Project, which includes one fully operational stage, one in construction, and one planned, each of which have a capacity of 35 thousand bbl/d. Jackfish II began production in June 2011 and is supposed to attain full production capacity by the end of 2012, while Jackfish III is scheduled to come online in 2015.
  • Nexen, a CNOOC subsidiary, operates the Long Lake Oil Sands Project. It includes a SAGD facility that is producing approximately 35 thousand bbl/d from the first tranche of well pads. The company plans to increase output to 72 thousand bbl/d of bitumen, from which 60 thousand bbl/d of SCO will be produced from an upgrader that became operational in 2009. The next phase of Long Lake, Kinosis, has a planned capacity of 15-25 thousand bbl/d, which could be followed by larger expansions in future years.
  • ConocoPhillips produces almost 30 thousand bbl/d from the first phase of the Surmont in-situ project, with an expansion to 100 thousand bbl/d planned for 2015. It also acts in a 50-50 partnership with Cenovus on Christina Lake and Foster Creek.
  • Husky Energy operates 30 thousand bbl/d of current production, through the Tucker in-situ project in Cold Lake. It plans to eventually bring online a much larger Athabascan in-situ project, known as Sunrise. Sunrise Oil Sands Project will developed in three phases over the 2014-2020 timeframe, with an initial capacity of 60 thousand bbl/d and eventual capacity of 200 thousand bbl/d.
  • MEG Energy operates 25 thousand bbl/d of combined production from the first two phases of the Christina Lake in-situ project. A 35 thousand bbl/d expansion is currently underway. A third phase is in regulatory review, which would add 150 thousand bbl/d for a total project capacity of over 200 thousand bbl/d.
  • PetroChina recently purchased the MacKay River Oil Sands Project and Dover in-situ projects from Athabasca Oil Sands Corp. Neither project is currently producing at a commercial scale, but the first phase of MacKay River is scheduled to come online in 2014, at 35 thousand bbl/d, with an eventual expansion to 150 thousand bbl/d.
  • Statoil's presence in the oil sands is focused on the Kai Kos Dehseh Oil Sands Project. A 40-thousand bbl/d expansion of the limited production there is planned by 2015.
  • Sunshine Oil Sands has announced three separate in-situ projects that it intends to bring online over the next decade, with a combined future capacity of 150 thousand bbl/d. However, over the next few years, initial phases of each project will only produce approximately 10 thousand bbl/d.
  • Total received regulatory approval for the 100-thousand bbl/d Joslyn North mine, but the company has reportedly not yet made a final investment decision. It would jointly develop Joslyn and the Fort Hills mine with Suncor.
  • All forms of oil and gas development pose environmental challenges and risks, but concerns about the environmental implications of oil sands production are unique and in some respects more acute. Many objections to oil sands development center upon the relatively energy-intensive and carbon-intensive extraction and processing methods required. Calculations of the climate impacts of oil sands development are complicated and often yield different results but, caveats and exceptions aside, well-to-tank greenhouse gas emissions are typically higher for oil produced from the oil sands than oil produced through conventional means. The potential to exacerbate climate change is merely one of the environmental costs that accompany the development of Canada's oil sands. Other environmental concerns regarding oil sands development relate to land use, water use, water quality, the impacts of toxic tailing ponds, and the possibility of oil spills from pipelines emanating from producing regions.
  • Environmental tradeoffs are inherent in the use of any energy source, and even between different types of oil sands technology. For example, while the land use impacts of in-situ production are arguably less severe than they are for surface mining, the energy inputs can be higher. Federal and provincial authorities have issued regulations to ameliorate the environmental impacts of oil sands development. Nonetheless, there have been domestic and international attempts to impede future oil sands expansions for environmental reasons, including through opposition to new export infrastructure.

Western Canada Sedimentary Basin

  • The traditional center of Canada's oil production has been the Western Canada Sedimentary Basin (WCSB), which stretches from British Columbia across Alberta and Saskatchewan to Manitoba. This basin contains some of the most abundant supplies of oil and natural gas in the world. The WCSB remains a significant source of conventional oil production, despite the fact that it was surpassed by unconventional output from the oil sands in 2006. According to an analysis of data from the National Energy Board, of Canada's production of crude oil and equivalent in 2011, approximately 18 percent was conventional light crude production from WCSB provinces and an additional 14 percent was conventional heavy crude from Alberta and Saskatchewan.
  • The depletion rates of conventional oil production in the WCSB are expected to fall in the coming years, as enhanced recovery techniques are applied to old wells and new resource deposits. In particular, technological advances like horizontal drilling and hydraulic fracturing have made tight oil production from shale formations an increasingly attractive alternative to conventional petroleum production. According to National Energy Board data, tight oil production in the WCSB exceeded 200 thousand bbl/d by the end of 2011 and was quite evenly divided between Alberta and Saskatchewan, with smaller amounts of production from Manitoba. The two most prolific plays are the Bakken Oil Field – which stretches across southern Saskatchewan and Manitoba as well as the northeast corner of Montana and North Dakota – and the Cardium formation in Alberta. In the United States, the Bakken has been largely responsible for the recent growth in U.S. crude oil production.


  • Most offshore oil production in Canada occurs in the Jeanne d'Arc Basin, off of the eastern shore of Newfoundland and Labrador. Light crude oil production from offshore areas in eastern Canada amounted to approximately 265 thousand bbl/d in 2010, which was almost 10 percent of Canada's total crude oil production. Most of Canada's offshore output derives from the Hibernia Oil Field, which came online in 1997 and is operated by ExxonMobil, accounting for over 150 thousand bbl/d of production in 2011. Two other significant fields in the region are Terra Nova Oil Field and White Rose Oil Field. Terra Nova is operated by Suncor on behalf of a large consortium and accounted for slightly more than 40 thousand bbl/d of production in 2011, a substantial decline from the levels achieved in the last decade. Husky Energy operates White Rose, which also produces well below its peak levels, at 35 thousand bbl/d in 2011. In May 2010, Husky started production at the North Amethyst field, which is one of the satellites to White Rose that could offset declines elsewhere and extend the field complex's production life. The large Hebron Oil Field, which could have up to 1 billion barrels of recoverable heavy oil resources, is expected to begin production by 2017.

Natural Gas

  • Canada's offshore exploration and production is confined by numerous regulatory and legal impediments. A 1972 moratorium proscribes field development off the Pacific coast, where there are an estimated 9.8 billion barrels of recoverable resources. A federal review of offshore drilling prevents progress in the Arctic, but oil majors such as Imperial Oil, ExxonMobil, BP, and Chevron have invested to secure acreage in the Beaufort Sea.
  • Canada is the third largest producer of natural gas, but trails both the United States and Russia by a considerable margin. Dry natural gas production increased in 2011, after declining from peak levels reached in the first half of the last decade. EIA estimates that Canada produced 6.7 Tcf of gross natural gas in 2010 (18 billion cubic feet per day, Bcf/d), of which 5.9 Tcf was marketed (5.4 Tcf of which was dry natural gas), 730 Bcf was reinjected, and 55 Bcf was vented or flared. The vast majority of Canada's natural gas production derives from conventional production in the WCSB. Alberta produced over two-thirds of Canada's gross natural gas in 2011, according to Statistics Canada data, with most of the remainder coming from British Columbia.
  • Although production of conventional natural gas is undergoing declines due to reserve depletion, technological advances have spurred rapid investment in the region, and natural gas production from the WCSB will increasingly come from shale gas, tight gas, and CBM. A number of major and independent companies, including Encana, Apache, Devon, Quicksilver, and Nexen, are already active in British Columbia's Horn River shale play. Foreign interest in the resource was also demonstrated by the joint development agreements that Encana signed with CNPC and Korean Gas Corp. (KoGas) in 2010. Shale gas production in Canada is currently limited, and the shale gas basins in eastern Canada are in even earlier stages of exploration and development.
  • Offshore natural gas production has been focused primarily off the coast of Eastern Canada, in the Scotian Shelf geological area. The most mature project is the Sable Offshore Energy Project (SOEP), in which ExxonMobil has a majority stake. SOEP produces as much as 500 million cubic feet per day (MMcf/d) from an area that is described by operators as one of the largest known natural gas deposits remaining in North America. Encana is developing another major natural gas project off Nova Scotia, the Deep Panuke Gas Field, which is set to come online in 2013. The project is designed to produce 300 MMcf/d initially, with estimated recoverable reserves of over 600 Bcf.

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