North american oil sands: history of development, prospects for the future

International Journal of Energy, Environment and Economics

Volumn 16, Issue 2-3, 2009, Pages 291-314

  Humphries, Marc ^a  

^a Analyst in Energy Policy Resources Science   (United States)

Author keywords

[No Author keywords available]

Indexed keywords

CRUDE OIL; ENVIRONMENTAL ISSUE; EXPORT; HYDROCARBON EXPLORATION; HYDROCARBON RESERVE; IMPORT; INORGANIC MATTER; INVESTMENT; OIL PRODUCTION; OIL SAND; OIL SUPPLY; RESEARCH AND DEVELOPMENT; SOCIOECONOMIC IMPACT;

CANADA; NORTH AMERICA;

EID: 68949143537     PISSN: 1054853X     EISSN: None     Source Type: Journal    
DOI: None     Document Type: Article

References (79)

1. DOE, EIA, International Energy Outlook, 2006, p. 29.
2. U.S. Department of Energy, EIA, Annual Energy Outlook, 2006.
3. Oil Sands Fever, The Environmental Implications of Canada's Oil Sand Rush, by Dan Woynillowicz, et. al, The Pembina Institute, November 2005.
4. Reserves are defined by the EIA as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Resources are defined typically as undiscovered hydrocarbons estimated on the basis of geologic knowledge and theory to exist outside of known accumulations. Technically recoverable resources are those resources producible with current technology without consideration of economic viability.
5. In-situ mining extracts minerals from an orebody that is left in place.
6. Canada's Oil Sands: Opportunities and Challenges to 2015, An Energy Market Assessment, National Energy Board, Canada, May 2004, p. 5.
7. API represents the American Petroleum Institute method for specifying the density of crude petroleum. Also called API gravity.
8. Diluents are usually any lighter hydrocarbon; e.g., pentane is added to heavy crude or bitumen in order to facilitate pipeline transport.
9. Canada's Oil Sands, May 2004, p. 10.
10. Canada's Oil Sands, May 2004, p. 4.
11. DOE, EIA, International Energy Outlook, 2006, p. 29.
12. Canada's Oil Sands, NEB, June 2006.
13. World Energy Investment Outlook, 2003 Insights, International Energy Agency (IEA), 2003.
14. Canadian Oil Sands, May 2004, p. 25.
15. The U.S.-Canadian dollar exchange rate fluctuates daily. As of early October 2007 the exchange rate is U.S.$1 = C$0.9969. In December 2006 the exchange rate was U.S.$1 = C$1.15.
16. Oil Industry Update, Alberta Economic Development, Spring 2005.
17. Oil shale is a compact rock (shale) containing organic matter capable of yielding oil.
18. U.S. Tar-Sand Oil Recovery Projects -1984, L.C. Marchant, Western Research Institute, Laramie, WY, p. 625.
19. Hydrocarbon-wetted oil sand deposits require different technology for bitumen extraction than that used for Alberta's water-wetted deposits. Oil sands are characterized as having a wet interface between the sand grain and the oil coating; this allows for the separation of oil from the grain. U.S. oil sands do not have a wet interface making the separation difficult.
20. Phone communication with B. Tripp, Geologist, Utah Geological Survey, May 2004.
21. Phone communication with Richard Meyers, Department of the Interior specialist in oil sands, September 2004.
22. Presentation by Earth Energy Resources, Inc., at the Western U.S. Oil Sands Conference, University of Utah, September 21, 2006.
23. Development of America's Strategic Unconventional Fuels Resources, Initial Report to the President and the Congress of the United States, Task Force on Strategic Unconventional Fuels, September 2006.
24. The measured pace is based on sufficient private investment capital as a result of government policies but little direct government investment. An accelerated pace would imply a global oil supply shortage and rely more on significant government investment.
25. Development of America's Strategic Unconventional Fuels Resources, Initial Report to the President and the Congress of the United States, Reference no. 17.
26. The ARC was established in 1921, housed at the University of Alberta in Edmonton, and funded by the provincial government of Alberta. Its mandate was to document Alberta's mineral and natural resources. Today, the ARC is a wholly-owned subsidiary of the Alberta Science and Research Authority (ASRA) within Alberta's Ministry of Innovation and Science. The ARC has an annual budget of $85 million.
27. The Influence of Interfacial Tension in the Hot-Water Process for Recovering Bitumen From the Athabasca Oil Sands, by L.L. Schramm, E.N. Stasiuk, and D. Turner, presented at the Canadian International Petroleum Conference, paper 2001-136, June 2001.
28. Syncrude Canada Ltd. when first organized as a consortium of major oil companies comprised: Imperial Oil (an affiliate of Exxon), Atlantic Richfield (ARCO), Royalite Oil (later combined with Gulf Canada), and Cities Services RandD (See The Syncrude Story, p. 5). Its ownership has changed over the years as indicated in the text. Its current ownership structure is as follows: Canadian Oil Sands Ltd. (31.74%), Imperial Oil (25%), Petro-Canada Oil and Gas (12%), Conoco Phillips Oil Sands Partnership II (9.03%), Nexen Inc. (7.23%), Murphy Oil Co. Ltd. (5%), Mocal Energy Ltd. (5%) and the Canadian Oil Sands Limited Partnership (5%).
29. GCOS, Ltd., was later renamed Suncor.
30. A Billion Barrels for Canada, The Syncrude Story, pp. 44-45.
31. The Alberta Energy Company (AEC) was created by the government of Alberta in 1975. Fifty percent was publicly owned. The government phased out is equity interest and in 1993 sold its remaining interest. The AEC and PanCanadian Energy Corporation merged in 2002 and became EnCana. EnCana sold its interest in Syncrude in 2003. For more details see Alexander's Oil and Gas Connection, "Company News North America," January 15, 2004.
32. The Syncrude Story, pp. 72-73.
33. Ibid, p. 98-99.
34. Ibid, p. 104.
35. Ibid, p. 122.
36. Ibid, p. 136.
37. The Alberta Energy Research Institute: Strategic Research Plan, 2003.
38. ARC, Guide to the ARC, 2001-2002. The ARC's more recent focus on developing in-situ technologies is beginning to shift back to surface mining RandD. They believe that their role is to help many of the newcomers to the industry develop "best practices" technology. The ARC sees itself as an ongoing player in the RandD business because of the huge challenges related to environmental quality, cost reductions, and the need for new upgrading technologies and refinery expansions.
39. Oil Sands Technology Roadmap, p. 20.
40. Oil Sands Industry Update, AED, June 2006, p. 7.
41. Oil Sands Technology Roadmap: Unlocking the Potential, Alberta Chamber of Resources, January 2004 p. 23.
42. According to the National Energy Board Report, one thousand cubic feet of natural gas is required per barrel of bitumin for SAGD operations. Canada's Oil Sands, May 2004.
43. Canada's Oil Sands, June 2006 p. 4.
44. Canada's Oil Sands, Opportunities and Challenges to 2015, An Energy Market Assessment, May 2004, National Energy Board, Canada, p. 108.
45. Canada's Oil Sands, June 2006.
46. Overview of Canada's Oil Sands, TD Securities, January 2004, p. 19.
47. NEB, June 2006, pp. 20-21.
48. COS, 2004, p. 9.
49. COS, 2006, p. 5.
50. COS, 2004, p. 18.
51. The generic oil sands royalty regime consists of three parts: the lease sale, a minimum 1 % pre-payout gross revenue royalty, and a 25% post-payout net revenue royalty. The payout period is the time it takes a firm to recover all allowable capital costs including a rater of return.
52. Oil and Gas Fiscal Regime, Alberta Resource Development of Western Canadian Provinces and Territories, p. 39, 1999.
53. Oil Sands, Benefits to Alberta and Canada, Today and Tomorrow, Through a Fair, Stable and Competitive Fiscal Regime, Canadian Association of Petroleum Producers, May 2007, Appendix B.
54. Our Fair Share, Report of the Alberta Royalty Review Panel, September 18, 2007, p. 7.
55. Our Fair Share, Report of the Alberta Royalty Review Panel, Ibid., p. 27.
56. Overview of Canada's Oil Sands, T.D. Securities, January 2004, p. 7.
57. The New Royalty Framework, October 25, 2007.
58. Oil and Gas Taxation in Canada, January 2000, PriceWaterhouseCoopers.
59. Canadian Department of Finance, Economic Statement, October 30, 2007.
60. There are 5 PADD's in the United States. PADDs were created during World War II as a way to organize the distribution of fuel in the United States.
61. DOE/EIA, Annual Energy Outlook 2006 with Projections to 2030, February 2006.
62. "Oil Sands Producers Facing Pipeline Capacity Constraints," The Energy Daily, August 7, 2007.
63. Greenhouse gas emissions include carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, periluorocarbons, and sulfur hexafluoride.
64. COS, 2004, p. 62.
65. COS, Ibid., p. 63.
66. Oil Sands Fever, by Dan Woynillowicz, et al., The Pembina Institute, November 2005.
67. COS, June 2006, p. 39.
68. Oil Sands Fever, op. cit.
69. Canada's Oil Sands (water conservation initiatives), pp. 66-68.
70. Canada's Oil Sands, p. 68.
71. Canada's Oil Sands, Ibid., p. 69.
72. For more on byproducts, see Canada's Oil Sands, p. 70.
73. Canada's Oil Sands, Ibid., p. 71.
74. Canada's Oil Sands, Ibid.
75. Oil Sands Industry Update, AED, June 2006, p. 29.
76. Section 369 of Energy Policy Act of 2005.
77. Development of America's Strategic Unconventional Fuels Resources, September 2006, p. 5.
78. Oil sands account for 174 billion barrels of Canada's total 179 billion barrel oil reserves. Further, the Alberta Energy and Utilities Board estimates that Alberta's oil sands contain 315 billion barrels of ultimately recoverable oil. Canada's Oil Sands: Opportunities and Challenges to 2015: An Update, June 2006, National Energy Board.
79. In-place oil is a continuous ore body that has maintained its original characteristics.