Alberta Development Context
Alberta has long been the centre of Canada’s oil and gas industry and is at the forefront of a broader transition within the global industry toward “unconventional” hydrocarbon resources. Compared to conventional oil, unconventional oil is more difficult and expensive to produce as it consists of an array of liquid foundations, including tar sands (International Energy Agency [IEA], 2013). In Alberta, this transition is marked by the aggressive development of the tar sands as well as ventures into several other types of hydrocarbons entailing new production methods, new costs, and new risks.
The Alberta Energy Regulator (AER) reports Alberta’s total conventional crude oil production in 2012 to be 203 million barrels, with established remaining reserves sat at 1.7 billion barrels (of the initial 18.4 billion barrels). Conventional oil reserves are located across the province, concentrated mostly in large areas of central Alberta as well as pockets in the northwest and the southeast areas. While the industry has historically been dominated by four of the multinational, integrated “supermajors” – Imperial Oil/ExxonMobil, Shell, Gulf (now Chevron), and Texaco (also now Chevron) – over the last several decades there has been a rise of major domestic oil and gas companies.
Since peaking in 1973, Alberta’s production of conventional oil (light, medium, and heavy) has been slowly declining. However, recent introduction of new production methods such as horizontal drilling using multistage fracturing technology, various “enhanced recovery methods”, along with the government’s introduction of new drilling incentives, are predicted to reverse this trend and allow for a temporary 10 year boost in production levels by targeting tight oil formations and oil remaining in already developed oil fields.
The last decade has seen a massive influx of capital into tar sands development. Major deposits of bitumen are located in a 142 000 km2 area of northern Alberta, which is further divided into three main areas: Peace River, Athabasca, and Cold Lake. The Canadian Association of Petroleum Producers (CAPP) estimates capital expenditures in the tar sands to be $13B in 2010, compared to $11B in 2009, and $18.1B in 2008, putting total capital investment at over $100B. Additionally, there have been major public expenditures to promote the development of the tar sands that are difficult to fully quantify, in forms such as technology research and development, royalty holidays, tax credits and an unprecedented public relation campaign..
The Alberta Energy Regulator estimates there are 1.84 trillion barrels of bitumen in Alberta. Of that amount, 167.9 billion barrels of bitumen can be feasibly recovered using current technology. The enormity of these reserves has launched Canada into place as having the third largest oil reserves behind Saudi Arabia and Venezuela. Production of crude bitumen in 2012 was 704 million barrels, up from 541 million in 2009.
Bitumen is both mined (when found close to the surface) and extracted through various in-situ methods (for example, steam-assisted gravity drainage or cyclic steam stimulation) which extract the bitumen through wells. While mining projects are more established and have garnered much of the media attention, about 80% of the remaining established bitumen reserves are recoverable through in-situ methods. There are currently five mining projects in operation, all of which are in the Athabasca region: Canadian Natural Resources Limited’s Horizon, Shell’s Muskeg River/Jackpine, Suncor’s Millenium/Steepbank, Syncrude’s Mildred Lake and Aurora, and Imperial Oil’s Kearl. There are also currently twenty-seven in-situ projects operating under the following companies: Cenovus, ConocoPhillips, Devon, Japan Canada Oil Sands, MEG’s, Nexen, Canadian Natural Resources Limited, Husky Oil, Imperial Oil, Shell, Suncor, and North Peace. There are many more projects that are under construction, have gained regulatory approval, or are in the process of seeking such approval, and various other major international oil companies have invested in the tar sands, including Total, StatOil, Sinopec,China National Petroleum Corporation, and BP.
Synthetic crude oil, of which there are various types, is produced through an upgrading process which adds hydrogen to raw bitumen. There are currently five upgraders operating in the province (with several expansions and new projects planned): Shell Canada Scotford, CNRL Horizon, Nexen/OPTI Long Lake, and those operated by Syncrude and Suncor. Together in 2010, Syncrude and Suncor produced over 70% of the province’s synthetic crude oil output.
Similarly to developments in the oil sector, a significant movement is underway to develop unconventional sources of natural gas, such as coalbed methane (CBM) and shale gas, as well as increasing levels of sour gas production. Pools of natural gas underlie huge swaths of southern and central Alberta, as well as the tar sands area, with much of the production located in the Foothills. As of 2011, the AER estimates remaining established reserves of conventional natural gas to be 35.3 Trillion Cubic Feet or Tcf (of an initial established reserve of 184 Tcf), with a production level in 2010 of 3.8 Tcf. Production peaked in 2001, and since at least 1983 additions to reserves have been outpaced by production levels.
The AER estimates about a third (1.16 Tcf) of CBM’s initial established reserves (3.58 Tcf) have been produced to date, with 2012 production levels at 292 Bcf. Most CBM activity is found in Horseshoe Canyon coals (including Upper Belly River CBM), where the highest initial gas-in-place estimates are found, while other production is occurring in the Corbett area of the Mannville CBM deposit.
Initial movement into developing shale gas is underway, with AER currently attempting to estimate reserve levels and industry undertaking exploratory drilling. Shale underlies most of the province, and indications are that more than 15 shale formations potentially contain pools of shale gas. The Alberta Geologic Survey estimates that five of these formations could contain 1,291 trillion cubic feet of shale gas. Most drilling activity is concentrated on the Colorado Group shales located in the Wildmere area in eastern-central Alberta, while exploration continues in Nordegg in western-central Alberta, as well as the Muskwa area in northwestern Alberta. Estimates as to the size of shale gas reserves in Alberta have ranged widely, with a high of twice as large as the initial-in-place volume of conventional natural gas.
Sour gas contains high levels of the toxic gas hydrogen sulphide (H2S) (AER uses >0.01%). Production of sour gas occurs across southern Alberta, with production concentrated in the central and western Alberta regions. High-concentration sour gas is found in the foothills and west central Alberta. AER estimates about a fifth of Alberta’s remaining gas reserves are sour, and about 17% of these reserves contain levels of H2S greater than 10%. gas According to the AER sour gas accounts for 30% of natural gas production in Alberta as of early 2014.
Sources:
http://www.iea.org/aboutus/faqs/oil/
http://www.aer.ca/data-and-publications/statistical-reports/st98
http://www.capp.ca/GetDoc.aspx?DocId=184463&DT=NTV
http://www.strategywest.com/downloads/StratWest_OSProjects_2011_01.pdf
http://treasuryboard.alberta.ca/docs/GOA_ResponsibleActions_web.pdf
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The content for this province was peer-reviewed in Sept 2013. We’d like to acknowledge the assistance of the external reviewers and Dave Campanella, Dave Vasey, Amanda Chrisanthus and Leanne Ross who contributed to this webpage content.
