Order Code RL34258
North American Oil Sands: History of
Development, Prospects for the Future
November 19, 2007
Marc Humphries
Analyst in Energy Policy
Resources, Science, and Industry Division
North American Oil Sands: History of Development,
Prospects for the Future
Summary
When it comes to future reliable oil supplies, Canada’s oil sands will likely
account for a greater share of U.S. oil imports. Oil sands account for about 42% of
Canada’s total oil production and oil sands production is increasing as conventional
oil production declines. Since 2004, when a substantial portion of Canada’s oil sands
were deemed economic, Canada, with about 175 billion barrels of proved oil sand
reserves, has ranked second behind Saudi Arabia in oil reserves. Canadian crude oil
exports were about 1.64 million barrels per day (mbd) in 2004, of which 1.62 mbd
or 99% went to the United States. Canadian crude oil accounts for about 13% of U.S.
net imports and about 8% of all U.S. crude oil supply.
Oil sands, a mixture of sand, bitumen (a heavy crude that does not flow
naturally), and water, can be mined or the oil can be extracted in-situ using thermal
recovery techniques. Typically, oil sands contain about 75% organic matter, 10%
bitumen, 10% silt and clay, and 5% water. Oil sand is sold in two forms: (1) as a raw
bitumen that must be blended with a diluent for transport and (2) as a synthetic crude
oil (SCO) after being upgraded to constitute a light crude. Bitumen is a thick tar-like
substance that must be upgraded by adding hydrogen or removing some of the
carbon.
Exploitation of oil sands in Canada began in 1967, after decades of research and
development that began in the early 1900s. The Alberta Research Council (ARC),
established by the provincial government in 1921, supported early research on
separating bitumen from the sand and other materials. Demonstration projects
continued through the 1940s and 1950s. The Great Canadian Oil Sands company
(GCOS), established by U.S.-based Sunoco, later renamed Suncor, began commercial
production in 1967 at 12,000 barrels per day.
The U.S. experience with oil sands has been much different. The U.S.
government collaborated with several major oil companies as early as the 1930s to
demonstrate mining of and in-situ production from U.S. oil sand deposits. However,
a number of obstacles, including the remote and difficult topography, scattered
deposits, and lack of water, have resulted in an uneconomic oil resource base. Only
modest amounts are being produced in Utah and California. U.S. oil sands would
likely require significant R&D and capital investment over many years to be
commercially viable. An issue for Congress might be the level of R&D investment
in oil sands over the long-term.
As oil sands production in Canada is predicted to increase to 3 million barrels
per day by 2015, environmental issues are a cause for concern. Air quality, land use,
and water availability are all impacted. Socio-economic issues such as housing,
skilled labor, traffic, and aboriginal concerns may also become a constraint on
growth. Additionally, a royalty regime favorable to the industry is currently under
review. However, despite these issues and potential constraints, investment in
Canadian oil sands will likely continue to be an energy supply strategy for the major
oil companies.
Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
World Oil Sands Reserves and Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
What Are Oil Sands? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
U.S. Oil Sand Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Canadian Oil Sand Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
History of Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Role of Industry and Government . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
U.S. Oil Sands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Canadian Oil Sands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Oil Sands Production Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Extraction Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Production Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Upgrading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Cost of Development and Production . . . . . . . . . . . . . . . . . . . . . . . . . 16
Tax and Royalty on Oil Sands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
U.S. Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Issues for Congress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Appendix A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Appendix B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Acronyms and Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
List of Figures
Figure 1. Tar (Oil) Sand Deposits of the United States . . . . . . . . . . . . . . . . . . . . 4
Figure 2. Oil Sands Areas in Alberta, Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Figure 3. Major Mining Process Steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Figure 4. In-SITU Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Figure 5. Upgrading to SCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Figure 6. Oil Sands Processing Chain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Figure 7. Major Canadian and U.S. (Lower 48) Crude Oil Pipelines and
Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
List of Tables
Table 1. Canada’s Bitumen Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Table 2. Leading Oil Sands Producers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Table 3. Estimated Operating and Supply Cost by Recovery Type . . . . . . . . . . 17
Table A1. Estimated World Oil Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Table B1. Regional Distribution of Estimated Technically Recoverable
Heavy Oil and Natural Bitumen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
North American Oil Sands: History of
Development, Prospects for the Future
Introduction
Current world oil reserves are estimated at 1.292 trillion barrels. The Middle
East accounts for 58% of world oil reserves, and the Organization of Petroleum
Exporting Countries (OPEC) accounts for 70%. The Middle East also leads in
reserve growth and undiscovered potential, according to the Energy Information
Administration (EIA).1
The United States’ total oil reserves are estimated at 22.7 billion barrels, a scant
1.8% of the world’s total (see Appendix A). U.S. crude oil production is expected to
fall from 5.4 million barrels per day (mbd) in 2004 to 4.6 mbd in 2030, while demand
edges up at just over 1% annually. Net imports of petroleum are estimated by the
EIA to increase from 12.1 mbd (58% of U.S. consumption) to 17.2 mbd (62% of U.S.
consumption) over the same time period.2
When it comes to future reliable oil supplies, Canadian oil sands will likely
account for a larger share of U.S. oil imports. Oil sands account for about 42% of
Canada’s total oil production, and oil sand production is increasing as conventional
oil production declines. Since 2004, when a substantial portion of Canada’s oil sands
were deemed economic, Canada has been ranked second behind Saudi Arabia in oil
reserves. Canadian crude oil exports were about 1.64 million barrels per day in 2004,
of which 1.62 mbd or 99% went to the United States. Canadian crude oil accounts
for about 13% of U.S. net imports and about 8% of all U.S. crude oil supply.
An infrastructure to produce oil, upgrade, refine, and transport it from Canadian
oil sand reserves to the United States is already in place. Oil sands production is
expected to rise from its current level of 1.1 (mbd) to 3.0 mbd by 2015. However,
infrastructure expansions and skilled labor are necessary to significantly increase the
flow of oil from Canada. For example, many refineries are optimized to refine only
specific types of crude oil and may not process bitumen from oil sands. One issue
likely to be contentious is the regulatory permitting of any new refinery capacity
because of environmental concerns such as water pollution and emissions of
greenhouse gases.
Environmental challenges may also slow the growth of the industry. Canada
ratified the Kyoto Protocol in 2002, which bound Canada to reducing its greenhouse
1 DOE, EIA, International Energy Outlook, 2006, p. 29.
2 U.S. Department of Energy, EIA, Annual Energy Outlook, 2006.
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gas (GHG) emissions significantly by 2012. At the same time, the Pembina Institute
reports that the oil sands industry accounts for the largest share of GHG emissions
growth in Canada.3 In addition, high capital and energy input costs have made some
projects less economically viable despite recent high oil prices.
Major U.S. oil companies (Sunoco, Exxon/Mobil, Conoco Phillips, and
Chevron) continue to make significant financial commitments to develop Canada’s
oil sand resources. Taken together, these companies have already committed several
billion dollars for oil sands, with some projects already operating, and others still in
the planning stages. Many of these same firms, with the U.S. government, did a
considerable amount of exploration and development on “tar sands” in the United
States, conducting several pilot projects. These U.S. pilot projects did not prove to
be commercially viable for oil production and have since been abandoned. Because
of the disappointing results in the United States and the expansive reserves in
Canada, the technical expertise and financial resources for oil sands development has
shifted almost exclusively to Canada and are likely to stay in Canada for the
foreseeable future. However, with current oil prices above $60 per barrel and the
possibility of sustained high prices, some oil sand experts want to re-evaluate the
commercial prospects of U.S. oil sands, particularly in Utah.
This CRS report examines the oil sands resource base in the world, the history
of oil sands development in the United States and Canada, oil sand production,
technology, development, and production costs, and the environmental and social
impacts. The role of government — including direct financial support, and tax and
royalty incentives — is also assessed.
World Oil Sands Reserves and Resources4
Over 80% of the earth’s technically recoverable natural bitumen (oil sands) lies
in North America, according to the U.S. Geological Survey (USGS) (see Appendix
B). Canadian oil sands account for about 14% of world oil reserves and about 11%
of the world’s technically recoverable oil resources.
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.
CRS-3
What Are Oil Sands?
Oil sands (also called tar sands) are mixtures of organic matter, quartz sand,
bitumen, and water that can either be mined or extracted in-situ5 using thermal
recovery techniques. Typically, oil sands contain about 75% organic matter, 10%
bitumen, 10% silt and clay, and 5% water.6 Bitumen is a heavy crude that does not
flow naturally because of its low API7 (less than 10 degrees) and high sulfur content.
The bitumen has high density, high viscosity, and high metal concentration. There
is also a high carbon-to-hydrogen molecule count (i.e. oil sands are low in hydrogen).
This thick, black, tar-like substance must be upgraded with an injection of hydrogen
or by the removal of some of the carbon before it can be processed.
Oil sand products are sold in two forms: (1) as a raw bitumen that must be
blended with a diluent8 (becoming a bit-blend) for transport and (2) as a synthetic
crude oil (SCO) after being upgraded to constitute a light crude. The diluent used for
blending is less viscous and often a by-product of natural gas, e.g., a natural gas
condensate. The specifications for the bit blend (heavy oil) are 21.5 API and a 3.3%
sulfur content and for the SCO (light oil) are 36 API and a 0.015% sulfur content.9
U.S. Oil Sand Resources
The USGS, in collaboration with the U.S. Bureau of Mines, concluded in a
1984 study that 53.7 billion barrels (21.6 billion measured plus 32.1 billion
speculative) of oil sands could be identified in the United States. An estimated 11
billion barrels of those oil sands could be recoverable. Thirty-three major deposits
each contain an estimated 100 million barrels or more. Fifteen percent were
considered mineable and 85% would require in-situ production. Some of the largest
measured U.S. oil sand deposits exist in Utah and Texas. There are smaller deposits
located in Kentucky, Alabama, and California. Most of the deposits are scattered
throughout the various states listed above. As of the 1980s, none of these deposits
were economically recoverable for oil supply. They are still not classified as reserves
(see Figure 1).
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.
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Figure 1. Tar (Oil) Sand Deposits of the United States
Source: Major Tar Sand and Heavy Oil Deposits of the United States, Interstate Oil Compact
Commission, 1984, p. 2.
Canadian Oil Sand Resources
Canadian oil sand resources are located almost entirely in the province of
Alberta. The Alberta Energy and Utility Board (AEUB) estimates that there are 1.6
trillion barrels of oil sands in place, of which 11% are recoverable (175 billion
barrels) under current economic conditions (see Table 1). Mineable reserves at the
surface account for 35 billion barrels (20%) and in-situ reserves at 141 billion barrels
(80%). The AEUB estimates that the ultimate amount to be discovered (ultimate
volume-in place) is 2.5 trillion barrels: about 2.4 trillion in-situ and 140 billion
surface-mineable. Of this ultimate discovered amount, about 314 billion barrels are
expected to be recovered (175 billion barrels in reserves now and another 143 billion
barrels anticipated. See Table 1).10 However, EIA estimates only 45.1 billion barrels
(reserve growth and undiscovered potential) to be added to Canada’s reserve base by
2025.11
Oil sands occur primarily in three areas of Alberta: Peace River, Athabasca, and
Cold Lake (see Figure 2 below). Current production is 1.1 million barrels per day
10 Canada’s Oil Sands, May 2004, p. 4
11 DOE, EIA, International Energy Outlook, 2006, p. 29
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and is expected to reach 2.0 mbd by 2010 and 3.0 mbd by 2015.12 According to the
International Energy Agency (IEA), Canada’s oil sands production could exceed 5.0
mbd by 2033 but would require at least $90 billion in investment.13
Figure 2. Oil Sands Areas in Alberta, Canada
Source: National Energy Board, Alberta, Canada.
Table 1. Canada’s Bitumen Resources
Ultimate
Initial
Ultimate
Initial
Remaining
Billion
Cumulative
Volume in
Volume
Recoverable
Established
Established
Barrels
Production
Place
in Place
Volume
Reserves
Reserves
Mineable
Athabasca
138.0
113.0
69.0
35.0
2.5
32.7
In Situ
Athabasca
N/A
1,188.0
N/A
N/A
N/A
N/A
Cold Lake
N/A
201.0
N/A
N/A
N/A
N/A
Peace
N/A
129.0
N/A
N/A
N/A
N/A
River
Subtotal
2,378.0
1,518.0
245.0
142.8
1.26
141.5
Total
2,516.0
1,631.0
314.0
177.8
3.76
174.2
Source: Alberta Energy Utility Board.
12 Canada’s Oil Sands, NEB, June 2006.
13 World Energy Investment Outlook, 2003 Insights, International Energy Agency (IEA),
2003.
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As a result of recent high oil prices, 44 new oil sands projects are planned for
Alberta between 2004 and 2012, 26 in-situ and 18 surface-mining.14 If all projects
were to go forward, an estimated C$60 billion would be required for construction.
Several of the projects are expansions of current operations. The National Energy
Board (NEB) projects as much as C$81.6 billion being spent between 2006 and
2016.15 Eighty-two percent of the projected investment — expected to peak in 2008
— is directed towards the Fort McMurray/Woods Buffalo Region of Alberta. A
total of C$29 billion was spent on oil sands development between 1996 and 2004.16
History of Development
Role of Industry and Government
U.S. Oil Sands. Interest in U.S. oil sand deposits dates back to the 1930s.
Throughout the 1960s and 1970s, 52 pilot projects involving mining and in-situ
techniques were supported by the U.S. government in collaboration with major oil
companies such as Conoco, Phillips Petroleum, Gulf Oil, Mobil, Exxon, Chevron,
and Shell. Several steam-assisted technologies were being explored for in-situ
production. These sources have had little economic potential as oil supply. The
Energy Policy Act of 2005 (P.L. 109-58), however, established a public lands leasing
program for oil sands and oil shale17 R&D.
Based on the Canadian experience with oil sands production, it was established
that commercial success in mining oil sands is a function of the ratio of overburden
to oil sand thickness.18 This ratio should not exceed one. In other words, the
thickness of the overlying rock should not be greater than the thickness of the sand
deposit. It was estimated by the USGS that only about 15% of the U.S. resource base
has a ratio of one or less.
Major development obstacles to the U.S. oil sands resource base include remote
and difficult topography, scattered deposits, and the lack of water for in-situ
production (steam recovery and hot water separation) or undeveloped technology to
extract oil from U.S. “hydrocarbon-wetted” deposits.19 The Canadian technology
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
(continued...)
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may not be suited for many U.S. deposits. In Texas, deposits were considered by
Conoco Oil to be too viscous to produce in-situ. A Bureau of Mines experiment with
oil sands production in Kentucky proved to be commercially infeasible. In Utah,
there were attempts at commercial production over the past three decades by several
oil companies but projects were considered uneconomic and abandoned. As of 2004,
some oil sands were being quarried on Utah state lands for asphalt used in road
construction, and a small amount of production is taking place in California.20 “Since
the 1980s there has been little production for road material and no government
funding of oil sands R&D,” according to an official at the Department of the
Interior.21
A 2006 conference on oil sands held at the University of Utah indicated renewed
interest in U.S. oil sands but reiterated the development challenges mentioned above.
Speakers also pointed out new technologies on the horizon that are being tested in
Utah.22 Conference organizers concurred that long-term research and development
funding and huge capital development costs would be needed to demonstrate any
commercial potential of U.S. oil sand deposits. A recent report23 on U.S.
unconventional fuels (an interagency and multistate collaboration) makes a number
of general recommendations (for the development of oil sands and other
unconventional fuels), which include economic incentives, establishing a regulatory
framework, technology R&D, and an infrastructure plan. A recommendation specific
to oil sands calls for closer U.S. collaboration with the government of Alberta to
better understand Canadian oil sands development over the last 100 years. The
report’s task force estimates that based on a “measured” or “accelerated”
development pace scenario,24 U.S. oil sand production could reach 340,000-352,000
barrels per day by 2025.25
Canadian Oil Sands. Canada began producing its oil sands in 1967 after
decades of research and development that began in the early 1900s. Wells were
drilled between 1906 and 1917 in anticipation of finding major conventional oil
19 (...continued)
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.
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deposits. The area around Fort McMurray, Alberta, was mapped for bituminous sand
exposures in 1913 by Canada’s Federal Department of Mines. By 1919, the Scientific
and Industrial Research Council of Alberta (SIRCA), predecessor to the Alberta
Research Council (ARC),26 became interested in oil sands development. One of its
newly recruited scientists, Dr. Karl Clark, began his pioneering work on a hot-water
flotation process for separating the bitumen from the sand. In this separation process,
the mined oil sand is mixed with water and a sodium hydroxide base and rotated27 in
a horizontal drum at 80 degrees centigrade. Dr. Clark’s efforts led to a pilot plant in
1923 and a patented process by 1929. He continued to improve the process through
several experimental extraction facilities through the 1940s.
The technical feasibility was demonstrated in 1949 and 1950 at a facility in
Bitumont, Alberta, located on the Athabasca River near Fort McMurray. The
technology being tested was largely adopted by the early producers of oil sands —
Great Canadian Oil Sands (GCOS), Ltd., and Syncrude. Sunoco established GCOS,
Ltd., in 1952 and then invested $250 million in its oil sands project. Another major
player in the oil sands business in Canada was Cities Services, based in Louisiana.
Cities Services purchased a controlling interest in the Bitumont plant in 1958, then
in 1964, along with Imperial Oil, Atlantic Richfield (ARCO), and Royalite Oil,
formed the Syncrude consortium.28
The ARC continued its involvement with oil sands R&D throughout the 1950s
and 1960s. Several pilot projects were established during that period. Suncor 29 began
construction of the first commercial oil sands production/separation facility in 1964
and began production in 1967, using the hot water extraction method developed and
tested by ARC. In 1967, Suncor began to produce oil sands at a rate of 12,000
barrels per day.
Just a year later, in 1968, the government of Alberta deferred an application by
Syncrude Canada for a $200 million, 80,000 barrel oil sands facility. Eventually, in
1978, the Energy Resources Conservation Board of Alberta approved Syncrude’s
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 R&D (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.
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proposal to build a $1 billion plant that would produce up to 129,000 barrels per day.
However, ARCO, which represented 30% of the project, pulled out of the consortium
as costs of the plant climbed toward $2 billion. At that point (1978) the federal and
provincial governments joined in. The federal government purchased a 15% share,
Alberta a 10% share, and Ontario 5%, making up the 30% deficit. At the time, the
Canadian government was promoting the goal of energy self-sufficiency, and the
Alberta government agreed to a 50/50 profit-sharing arrangement instead of normal
royalties for Syncrude.30
The Alberta Energy Company31 purchased 20% of Syncrude and then sold 10%
of its share to Petrofina Canada, Ltd., and Hudson Bay Oil and Gas, Ltd.32 The
consortium grew from four to nine owners. From 1983 to 1988 Syncrude spent $1.6
billion to boost production to 50 million barrels per year. In 1984, the government
of Alberta agreed to a new royalty structure for oil sands producers coinciding with
Syncrude’s capital expansion plans. In 1985, the Alberta government announced that
existing oil sands operations and new plants would not be taxed on revenues, and the
petroleum gas revenue tax would be phased out. During the same time-frame,
Syncrude’s cash operating costs were just under $18 per barrel with total costs over
$20 per barrel,33 while the market price of oil fluctuated under $20 per barrel.
Because of huge capital requirements, oil sands producers lobbied for continued
royalty relief and thought the government should “defer tax and royalty revenues
until project expansions were completed.”34 In 1994, the National Oil Sands Task
Force (an industry/government group) was created, and the Canadian Oil Sands
Network for R&D (CONRAD) agreed to spend $105 million annually to boost
production and trim costs. Costs continued to fall ($15.39/bbl in 199235 to under $14/
bbl in 199436) as Syncrude ownership continued to change. In 1996, the National Oil
Sands Task Force recommended a package of royalty and tax terms to ensure
consistent and equal treatment of projects, because oil sand projects previously were
treated on a project-by-project basis. The implementation of favorable royalty
treatment is discussed below.
The ARC has had a successful partnership with the private sector in oil sands
research and development. As a result of favorable royalty and tax terms and
Alberta’s $700 million R&D investment in oil sands extraction (from 1976-2001),
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.
CRS-10
the private sector has invested billions of dollars of development capital in oil sand
projects.37 Syncrude has said that “partnering with ARC gave us the ability to
explore a potentially valuable technology.”38
Oil Sands Production Process
Oil sands production measured only 1.3% of total world crude oil production
in 2005. By 2025 it may reach 4.1% of total world production. But more importantly,
it may mean U.S. access to extensive North American oil reserves and increased
energy security.
Oil sands are either surface-mined or produced in-situ. Mining works best for
deposits with overburden less than 75 meters thick. Mining requires a hydraulic or
electric shovel that loads the sand into 400-ton trucks, which carry the material to a
crusher to be mixed into a slurry. Using pumps and pipelines, the slurry is “hydro
transported” to an extraction facility to extract bitumen (see Figure 3). This process
recovers about 90% of the bitumen.39
Figure 3. Major Mining Process Steps
Source: Oil Sands Technology Roadmap, Alberta Chamber of Resources, January 2004, p. 21.
37 The Alberta Energy Research Institute: Strategic Research Plan, 2003.
38 ARC, Guide to the ARC, 2001-02. The ARC’s more recent focus on developing in-situ
technologies is beginning to shift back to surface mining R&D. 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 R&D 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.
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In 2005, mining accounted for about 52% of Alberta’s oil sand production
(572,000 b/d); in-situ accounted for about 48% (528,000 b/d), one-third of which was
produced using the Cold Production method in which oil sands are light enough to
flow without heat. The in-situ approach, which was put into commercial production
in 1985,40 is estimated to grow to 926,000 barrels per day by 2012. Currently, the
largest production projects are in the Fort McMurray area operated by Syncrude and
Suncor (see Table 4 for leading producers of oil sands).
Extraction Process. The extraction process separates the bitumen from oil
sands using warm water (75 degrees Fahrenheit) and chemicals. Extracting the oil
from the sand after it is slurried consists of two main steps. First is the separation of
bitumen in a primary separation vessel. Second, the material is sent to the froth tank
for diluted froth treatment to recover the bitumen and reject the residual water and
solids. The bitumen is treated either with a naphtha solvent or a paraffinic solvent to
cause the solids to easily settle. The newer paraffinic treatment results in a cleaner
product.41 This cleaner bitumen is pipeline quality and more easily blended with
refinery feedstock. After processing, the oil is sold as raw bitumen or upgraded and
sold as SCO.
Table 2. Leading Oil Sands Producers
(barrels per day)
Planned
Project
Type of
2006
2002
2003
Production
Owner
Project
1st Quarter
Targets
Suncor
Mining
206,000
217,000
264,400
410,000
Syncrude
Mining
230,000
212,000
205,000
560,00
Athabasca Oil
Sands
Mining
N/A
130,000
77,400
525,000
(Shell,
Chevron, and
Western Oil)
Imperial Oil
In-situ
112,000
130,000
150,000
180,000
CNRL
In-situ
N/A
35,000
122,000
500,000
Petro Canada
In-situ
4,500
16,000
21,000
100,000
(2005)
EnCana
In-situ
N/A
5,300
36,000
250,000
Source: Oil Sands Industry Update, Alberta Economic Development, 2004 and 2006.
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.
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Figure 4. In-SITU Recovery
Source: Oil Sands Technology Roadmap, p. 28.
Production Technology. For in-situ thermal recovery, wells are drilled, then
steam is injected to heat the bitumen so it flows like conventional oil. In-situ
production involves using various techniques.
One technique is the Cyclic Steam Stimulator (CSS), also known as “huff and
puff.” CSS is the most widely used in-situ technology. In this process, steam is
added to the oil sands via vertical wells, and the liquefied bitumen is pumped to the
surface using the same well.
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But a relatively new technology — steam-assisted gravity drainage (SAGD) —
has demonstrated that its operations can recover as much as 70% of the bitumen in-
place. Using SAGD, steam is added to the oil sands using a horizontal well, then the
liquefied bitumen is pumped simultaneously using another horizontal well located
below the steam injection well (see Figure 4). The SAGD process has a recovery
advantage over the CSS process, which only recovers 25%-30% of the natural
bitumen. Also, the lower steam to oil ratio (the measurement of the volume of steam
required to extract the bitumen) of SAGD results in a more efficient process that uses
less natural gas.42 SAGD operations are limited to thick, clean sand reservoirs, but
it is reported by the industry that most of the new in-situ projects will use SAGD
technology.43 A number of enhanced SAGD methods are being tested by the Alberta
Research Council. They could lead to increased recovery rates, greater efficiency, and
reduced water requirements.
The emerging Vapor Extraction Process (VAPEX) technology operates similarly
to SAGD. But instead of steam, ethane, butane, or propane is injected into the
reservoir to mobilize the hydrocarbons towards the production well. This process
eliminates the cost of steam generators and natural gas. This method requires no
water and processing or recycling and is 25% lower in capital costs than the SAGD
process. Operating costs are half that of the SAGD process.44
A fourth technique is cold production, suitable for oil sands lighter than those
recovered using thermal assisted methods or mining. This process involves the co-
production of sand with the bitumen and allows the oil sands to flow to the well bore
without heat. Imperial Oil uses this process at its Cold Lake site. Oil sand produced
using in-situ techniques is sold as natural bitumen blended with a diluent for pipeline
transport.
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.
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Figure 5. Upgrading to SCO
Source: Oi l Sands Technology Roadmap, p. 41.
The overall result of technology R&D has been to reduce operating costs from
over $20/barrel in the early 1970s to $8-12/barrel in 2000. While technology
improvements helped reduce some costs since 2000, total costs have risen
significantly as discussed below, because of rising capital and energy costs.45
Upgrading.46 Upgrading the bitumen uses the process of coking for carbon
removal or hydro-cracking for hydrogen addition (see Figure 5). Coking is a
common carbon removal technique that “cracks” the bitumen using heat and
catalysts, producing light oils, natural gas, and coke (a solid carbon byproduct). The
coking process is highly aromatic and produces a low quality product. The product
must be converted in a refinery to a lighter gas and distillate. Hydrocracking also
cracks the oil into light oils but produces no coke byproduct. Hydrocracking requires
natural gas for conversion to hydrogen. Hydrocracking, used often in Canada, better
handles the aromatics. The resulting SCO has zero residues which help keep its
market value high, equivalent to light crude.
Partial upgrading raises the API of the bitumen to 20-25 degrees for pipeline
quality crude. A full upgrade would raise the API to between 30-43 degrees — closer
to conventional crude. An integrated mining operation includes mining and
upgrading. Many of the mining operations have an on-site upgrading facility,
including those of Suncor and Syncrude. Suncor uses the coking process for
45 Canada’s Oil Sands, June 2006.
46 Overview of Canada’s Oil Sands, TD Securities, January 2004, p. 19.
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upgrading, while Syncrude uses both coking and hydrocracking and Shell uses
hydrocracking. (For the complete oil sands processing chain, see Figure 6.)
A major trend among both mining and in situ producers is to integrate the
upgrading with the refinery to cut costs; e.g., linking SAGD production with current
refinery capabilities. Long-term processing success of oil sands will depend on how
well this integration takes place and how well the industry addresses the following
issues:
! cost overruns,
! cost effective upgrading, reducing highly aromatic, high-sulfur SCO,
and
! dependence on and price of natural gas for hydrogen production
(originally used because of its low price but now considered by some
to be too expensive).
The wide heavy-oil/light-oil price differential has been an incentive to increase
upgrading. The price for heavy crude was as low as $12 per barrel in early 2006 and
its market is limited by refineries that can process it and by its end use as asphalt. In
its June 2006 report, the NEB describes numerous proposals for building upgraders.47
Figure 6. Oil Sands Processing Chain
Source: Overview of Canada’s Oil Sands, TD Securities, p. 15.
47 NEB, June 2006, pp. 20-21.
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Cost overruns for the integrated mining projects or expansions, sometimes as
much as 50% or more of the original estimates, have been a huge problem for the
industry. The main reasons cited by the COS report are poor management, lack of
skilled workers, project size, and engineering issues.
Cost of Development and Production. Operating and total supply costs
have come down significantly since the 1970s. Early supply costs were near C$35
per barrel (in 1970s dollars). Reductions came as a result of two major innovations
in the production process. First, power shovels and energy efficient trucks replaced
draglines and bucketwheel reclaimers, and second, hydrotransport replaced conveyor
belts to transport oil sands to the processing plant.48
Operating costs include removal of overburden, mining and hydro transport,
primary extraction, treatment, and tailings removal. The recovery rate, overburden
volumes, cost of energy, transport distances, and infrastructure maintenance all have
an impact on operating costs.
Supply costs (total costs) include the operating costs, capital costs, taxes and
royalties, plus a 10% return on investment (ROI). When compared to conventional
new oil production starts, an oil sands project may have operating costs over 30%
higher than the world average for conventional new starts. However, its nearly
nonexistent royalty and tax charge makes the total cost per barrel of energy
significantly less than the conventional oil project (see Figure 7).49 The NEB in its
Energy Market Assessment estimated that between US$30-$35 per barrel oil is
required to achieve a 10% ROI.50
Operating costs for for mining bitumen were estimated at around C$9-$12 per
barrel (C$2005) — an increase of up to C$4 per barrel since the 2004 NEB estimates.
Supply cost of an integrated mining/upgrading operation is between C$36 and $40/
barrel for SCO — a dramatic increase over the C$22-$28 estimate made in 2004.
These supply costs for an integrated mining/upgrading operation were expected to
decline with improvements in technologies (see Table 3). However, natural gas
prices rose 88% and capital costs rose 45% over the past two years.
Operating costs for SAGD in-situ production in 2005 were about C$10-$14 per
barrel of bitumin, up from C$7.40 per barrel in 2004. Recovery rates are lower than
with mining, at 40%-70%, and the price of energy needed for production is a much
larger factor. The SAGD operations are typically phased-in over time, thus are less
risky, make less of a “footprint” on the landscape than a mining operation, and
require a smaller workforce. SAGD supply cost for Athabasca oil sand rose from
between C$11-$17/barrel (bitumen) to C$18-$22/barrel; using the CSS recovery
technique, supply costs are estimated higher at between C$20-$24/barrel, an increase
from C$13-$19/barrel. Cost increases/decreases for in-situ operations are largely
dependent on the quality of the reservoir and natural gas prices, but as SAGD and
48 COS, 2004, p. 9.
49 Overview of Canada’s Oil Sands, p. 50.
50 COS, 2006, p. 5.
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other new technologies (e.g. VAPEX) become more efficient, industry is expecting
some cost declines. SAGD (in-situ) supply costs are less sensitive to capital costs
than mining projects because the capital investment is far less.
Natural gas is a major input and cost for mining, upgrading, and in situ recovery:
Mining requires natural gas to generate heat for the hot water extraction process,
upgraders need it for heat and steam, and in situ producers use natural gas to produce
steam which is injected underground to induce the flow of bitumen. Natural gas
accounts for 15% of the operating costs in mining operations compared to 60% of
operating costs in SAGD in-situ production. The major cost for thermal in-situ
projects (SAGD, CSS) is for the natural gas that powers the steam-producing
generators. For SAGD projects, 1 thousand cubic feet is needed per barrel of
bitumen. Reducing the steam-to-oil ratio (SOR) — the quantity of steam needed per
barrel of oil produced — is critical for lowering natural gas use and costs.51 SAGD
has a lower SOR than CSS projects but cannot be used for all oil sand in-situ
production. However, most new in-situ projects will use SAGD.
Canadian oil sand producers continue to evaluate energy options that could
reduce or replace the need for natural gas. Those options include, among other things,
the use of gasification technology, cogeneration, coal, and nuclear power.
Table 3. Estimated Operating and Supply Cost
by Recovery Type
(C$2005 Per Barrel at the Plant Gate)
Crude
Operating
Supply
Type
Cost
Cost
Cold Production - Wabasca, Seal
Bitumen
6-9
14-18
Cold Heavy Oil Production and Sand
(CHOPS) - Cold Lake
Bitumen
8-10
16-19
Cyclic Stream Stimulation (CSS)
Bitumen
10-14
20-24
Steam Assisted Gravity Drainage (SAGD)
Bitumen
10-14
18-22
Mining/Extraction
Bitumen
9-12
18-20
Integrated Mining/Upgrading
SCO
18-22
36-40
Source: Canada’s Oil Sands, Opportunities and Challenges to 2015, National Energy Board,
Canada, June 2006.
Note: Supply costs for the first five technologies do not include the coat of upgrading bitumen to
SCO.
51 COS, 2004, p. 18.
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Tax and Royalty on Oil Sands. In 1997 the Alberta government
implemented a “Generic Oil Sands Royalty Regime”52 specific to oil sands for all
new investments or expansions of current projects. Since then, oil sand producers
have had to pay a 1% minimum royalty based on gross revenue until all capital costs
including a rate of return are recovered. After that, the royalty is either 25% of net
project revenues or 1% of the gross revenues, whichever is greater.53 The 1% pre-
payout royalty rate is in stark contrast to conventional world royalties. Net project
revenues (essentially net profits before tax) include revenues after project cash costs,
such as operating costs, capital, and R&D are deducted. Royalty payments may be
based on the value of bitumen or SCO if the project includes an upgrader. Currently,
51% of oil sand projects (or 75% of production volume) under the Generic Royalty
regime are paying the 25% royalty rate. Two major oil sands producers, Suncor and
Syncrude (accounting for 49% of bitumen production) have “Crown Agreements” in
place with the province that have allowed the firms to pay royalties based on the
value of synthetic crude oil (SCO) production with the option to switch to paying
royalties on the value of bitumen beginning as early as 2009. Royalties paid on
bitumen, which is valued much lower than SCO, would result in less revenue for the
government. The agreements expire in 2016.
Royalty revenues from oil sands fluctuated widely between 1997 and 2005. For
example, royalties from oil sands were less than $100 million in 1999, then rose to
$700 million in 2000/2001, but fell in 2002/2003 to about $200 million as production
continued to rise. Royalties from oil sands rose dramatically in 2005/2006 to $1
billion, and the Government of Alberta forecasts royalties of $2.5 billion in
2006/2007 and $1.8 billion in 2007/2008.54 Oil price fluctuations are the primary
cause for such swings in royalty revenues.
The Albertan provincial government established a Royalty Review Panel in
February 2007 to examine whether Alberta was receiving its fair share of royalty
revenues from the energy sector and to make recommendations if changes are
needed. In its September 2007 report, the panel concluded that “Albertans do not
receive their fair share from energy development.”55 When the oil sands industry was
ranked against other heavy oil and offshore producers such as Norway, Venezuela,
Angola, United Kingdom, and the U.S. Gulf of Mexico, Alberta received the smallest
government share.56 This is, however, a difficult comparison to make because it is
not among oil sand producers only and the fiscal regimes of the various producing
52 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.
53 Oil and Gas Fiscal Regime, Alberta Resource Development of Western Canadian
Provinces and Territories, p. 39, 1999.
54 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.
55 Our Fair Share, Report of the Alberta Royalty Review Panel, September 18, 2007, p. 7.
56 Ibid., p. 27.
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countries is dynamic. However, based on a general analysis by T.D. Securities,
typically, on average, world royalty rates could add as much as 45% to operating
costs while the 1% rate may add only 3% to operating costs.57
The Panel recommended keeping the “pre-payout, post-payout” framework
intact (see footnote 52), which would retain the 1% pre-payout royalty rate, but in the
post-payout phase, firms would be required to pay a higher net revenue royalty rate
of 33% plus continue to pay the 1% base royalty.
On October 25, 2007, the Alberta Government announced and published its
response to the Royalty Review Panel’s report.58 It retained the “pre-payout,” “post-
payout” royalty framework but concluded that a sliding-scale rate structure would
best achieve increasing the government’s share of revenues from oil sands
production. The pre-payout base rate would start at 1%, then increase for every
dollar above US$55 per barrel (using the West Texas Intermediate or WTI price)
reaching a maximum increase of 9% when prices are at or above $120 per barrel. In
the post-payout phase, the net revenue rate will start at 25%, then rise for every dollar
oil in priced above US$55 per barrel, reaching a maximum of 40% of net revenues
when oil is $120 per barrel or higher. The new rate structure will take effect in 2009.
The Government of Alberta has initiated negotiations with Suncor and Syncrude in
an attempt to include them under the new oil sands royalty framework by 2009.
Oil sand firms pay federal and provincial income taxes and some differences
exist in the tax treatment of the oil sands and conventional oil industries. Since the
Provincial 1996 Income Tax Act, both mineable and in-situ oil sand deposits are
classified as a mineral resource for Capital Cost Allowance (CCA) purposes which
means mineral deposits receive higher cost deductions than conventional oil and gas
operations (i.e. acquisition costs and intangible drilling costs).59 The provincial
government of Alberta has agreed to the 2007 federal budget proposal to eliminate
the CCA deduction for oil sands. The Royalty Review Panel also supported this
change in its report.
U.S. Markets
Oil sand producers continue to look to the United States for the majority of their
exports. Seventy-five percent of Canadian nonconventional oil exported to the United
States is delivered to the Petroleum Administration for Defense District (PADD)60
II in the Midwest. This region is well positioned to receive larger volumes of
nonconventional oil from Canada because of its refinery capabilities. Several U.S.-
based refinery expansions have been announced that would come online between
2007-2015. If Canada were to reach its optimistic forecasted oil sands output level
of 5 mbd in 2030, and maintained its export level to the United States at around 90%,
57 Overview of Canada’s Oil Sands, T.D. Securities, January 2004, p. 7.
58 The New Royalty Framework, October 25, 2007.
59 Oil and Gas Taxation in Canada, January 2000, PriceWaterhouseCoopers.
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.
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it would be exporting about 4.5 mbd to the United States. This would mean that
imports from Canada would reach nearly 30% of all U.S. crude oil imports. U.S.
refinery capacity is forecast to increase from 16.9 mbd in 2004 to nearly 19.3 mbd
in 2030,61 a 2.4 mbd increase — significant but perhaps not enough to accommodate
larger volumes of oil from Canada, even if refinery expansions would have the
technology to process heavier oil blends. Canada is pursuing additional refinery
capacity for its heavier oil.
Pipelines. Oil sands are currently moved by two major pipelines (the
Athabasca and the Corridor, not shown in Figure 7) as diluted bitumen to processing
facilities in Edmonton. After reaching refineries in Edmonton, the synthetic crude or
bitumen is moved by one of several pipelines to the United States (see Figure 7). The
Athabasca pipeline has capacity of 570,000 barrels per day (b/d) while the Corridor
has capacity of less than 200,000 b/d. Current pipeline capacity has nearly reached
its limit. However, there are plans to increase Corridor’s capacity to 610,000 b/d by
2010.
Figure 7. Major Canadian and U.S. (Lower 48) Crude Oil Pipelines
and Markets
Source: Canada’s Oil Sands, Opportunities and Challenges to 2015: An Update, June 2006.
A number of new pipeline projects have been proposed or initiated that would
increase the flow of oil from Canada to the United State’s PADDs II, III, and V,
including Enbridge’s (Athabasca’s owner) new Gateway project which would move
61 DOE/EIA, Annual Energy Outlook 2006 with Projections to 2030, February 2006.
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oil from the Athabasca region to British Columbia to supply California and the Asian
markets. Most of these projects are scheduled to come online between 2008 and
2012. Pipeline capacity could be a constraint to growth in the near term but the NEB
predicts some excess pipeline capacity by 2009. An estimated $31.7 billion has been
invested in pipeline projects for oil sands in western Canada.62
Environmental and Social Issues
The Federal Government of Canada classified the oil sands industry as a large
industrial air pollution emitter (i.e., emitting over 8,000 tons CO /year) and expects
2
it to produce half of Canada’s total greenhouse gas (GHG) emissions63 by 2010.
Since 1990 the oil sands industry has reduced its “emission intensity” by 26% while
production was rising. CO emissions have declined from 0.14 tons/bbl to about 0.08
2
tons/bbl or about 88 megatons since 1990.64 Alberta’s GHG goals are 238 megatons
of CO in 2010, and 218 megatons CO in 2020.65 Reducing air emissions is one of
2
2
the most serious challenges facing the oil sands industry. However, according to the
Pembina Institute, a sustainable energy advocate, greenhouse gas emissions intensity
(CO /barrel) from oil sands is three times as high as that from conventional oil
2
production.66 The industry believes if it can reduce energy use it can reduce its
emissions. The Pembina Institute estimates that as emissions per barrel of oil from
oil sands decline overall, total GHG emissions will more than double from 2002-
2015, attributing much of the increase to increased oil sands production.67
Water supply and waste water disposal are among the most serious concerns
because of heavy use of water to extract bitumen from the sands. For an oil sands
mining operation, about 2-5 barrels of water are removed from the Athabasca river
for each barrel of bitumen produced. Oil sands projects currently divert 150 million
cubic meters of water annually from the Athabasca River but are approved to use up
to 350 million cubic meters — twice the volume of water required to supply the city
of Calgary, a population of over 300,000.68 Less than 10% of the water removed from
the river returns to the river. Concerns arise over the inadequate flow of the river to
maintain a healthy ecosystem and meet future needs of the oil sands industry.
Additionally, mining operations impact freshwater aquifers by drawing down water
to prevent pit flooding.
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, perfluorocarbons, and sulfur hexafluoride.
64 COS, 2004, p. 62.
65 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.
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The freshwater used for in-situ operations is needed to generate steam, separate
bitumen from the sand, hydrotransport the bitumen slurry, and upgrade the bitumen
to a light crude. For SAGD operations, 90-95% of all the water used is recycled.
Since some water is lost in the treatment process, additional freshwater is needed.
To minimize the use of new freshwater supplies, SAGD operators use saline water
from deeper underground aquifers. The use of saline water, however, generates huge
volumes of solid waste which has posed serious disposal problems.
Wastewater tailings (a bitumen, sand, silt, and fine clay particles slurry) also
known as “fluid fine tailings” are disposed in large ponds until the residue is used to
fill mined-out pits. Seepage from the disposal ponds can result from erosion,
breaching, and foundation creep.69 The principal environmental threat is the
migration of tails to a groundwater system and leaks that might contaminate the soil
and surface water.70 The tailings are expected to reach 1 billion cubic meters by 2020.
Impounding the tailings will continue to be an issue even after efforts are made to use
alternative extraction technology that minimizes the amount of tails. Tailings
management criteria were established by the Alberta Energy and Utilities
Board/Canadian Environmental Assessment Agency in June 2005. Ongoing
extensive research by the Canadian Oil Sands Network for Research and
Development (CONRAD) is focused on the consolidation of wastewater tailings,
detoxifying tailings water ponds, and reprocessing tailings. Some R&D progress is
being made in the areas of the cleanup and reclamation of tailings using
bioremediation and electrocoagulation.71
The National Research Council of Canada (NRC) is conducting research to treat
wastewater tailings and recover their byproduct residual bitumen, heavy metals, and
amorphous solids (fertilizers). A pilot project is underway to clean and sort tailings,
and recover metals such as aluminum and titanium.72
Surface disturbance is another major issue. The oil sands industry practice
leaves land in its disturbed state and left to revegetate naturally. Operators, however,
are responsible over the long term to restore the land to its previous potential.73
Under an Alberta Energy Utility Board directive (AEUB), Alberta’s Upstream Oil
and Gas Reclamation and Remediation Program has expanded industry liability for
reclaiming sites. The directive requires a “site-specific liability assessment” that
would estimate the costs to abandon or reclaim a site.74
The government of Alberta’s Department of the Environment established a
“Regional Sustainable Development Strategy” whose purpose is, among other things,
to “ensure” implementation of management strategies that address regional
69 Canada’s Oil Sands (water conservation initiatives), pp. 66-68.
70 Canada’s Oil Sands, p. 68.
71 Ibid., p. 69.
72 For more on byproducts, see Canada’s Oil Sands, p. 70.
73 Ibid., p. 71.
74 Ibid.
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cumulative environmental impacts.75 The oil sands industry is regulated under the
Environmental Protection and Enhancement Act, Water Act, and Public Lands Act.
Oil sands development proposals are reviewed by AEUB, Alberta Environment, and
the Alberta Sustainable Resource Development at the provincial level. Review at the
federal level may also occur.
Issues for Congress
The Energy Policy Act of 2005 (P.L. 109-58) describes U.S. oil sands (along
with oil shale and other unconventional fuels) as a strategically important domestic
resource “that should be developed to reduce the growing dependence of the United
States on politically and economically unstable sources of foreign oil imports.”76 The
provision also requires that a leasing program for oil sands R&D be established.
Given U.S. oil sands’ strategic importance, but limited commercial success as
discussed above, what level of federal investment is appropriate to reach U.S. energy
policy goals? While an estimated 11 billion barrels of U.S. oil sands may be
significant if it were economic, it represents a small share of the potentially
recoverable resource base of unconventional fuels (e.g., 800 billion barrels of
potentially recoverable oil from oil shale and another 20 billion barrels of recoverable
heavy oil). Where is the best return on the R&D dollar invested for increased
domestic energy supply and what are the long-term prospects for commercial
application of unconventional fuels technology? Another important consideration to
look at is where the oil industry is investing its capital and R&D for oil sands
projects.
In light of the environmental and social problems associated with oil sands
development, e.g., water requirements, toxic tailings, carbon dioxide emissions, and
skilled labor shortages, and given the fact that Canada has 175 billion barrels of
reserves and a total of over 300 billion barrels of potentially recoverable oil sands (an
attractive investment under current conditions demonstrated by the billions of dollars
already committed to Canadian development), the smaller U.S. oil sands base may
not be a very attractive investment in the near-term.
U.S. refinery and pipeline expansions are needed to accommodate Canadian oil
sands developments. Those expansions will have environmental impacts, but the
new infrastructure could strengthen the flow of oil from Canadian oil sands. This
expanded capacity will likely lead to even greater investment in Canada.
Whether U.S. oil sands are developed, Congress will continue to be faced with
regulatory matters. Oil imports from oil sands are likely to increase from Canada and
the permitting of new or expanded oil refineries will continue to be an issue because
of the need to balance concerns over the environment on one hand and energy
security on the other.
75 Oil Sands Industry Update, AED, June 2006, p. 29.
76 Section 369 of Energy Policy Act of 2005.
CRS-24
Prospects for the Future
Because capital requirements for oil sands development has been enormous and
risky, government involvement was seen as being essential in Canada, particularly
during sustained periods of low oil prices. This private sector/government partnership
in R&D, equity ownership, and public policy initiatives over the last 100 years has
opened the way for the current expansion of the oil sands industry in Alberta.
Ongoing R&D efforts by the public and private sectors, sustained high oil
prices, and favorable tax and royalty treatment are likely to continue to attract the
increasing capital expenditures needed for growth in Canada’s oil sands industry.
Planned pipeline and refinery expansions and new upgrading capacity are underway
to accommodate the increased volumes of oil sands production in Canada. U.S.
markets will continue to be a major growth area for oil production from Canadian oil
sands. Currently, about 3% of the total oil refined in the United States is from
Canada’s oil sands.
Even though prospects for Canadian oil sands appear favorable, factors such as
water availability, waste water disposal, air emissions, high natural gas costs,
insufficient skilled labor, and infrastructure demands may slow the pace of
expansion.
Prospects for commercial development of U.S. oil sands are uncertain at best
because of the huge capital investment required and the relatively small and
fragmented resource base. The Task Force on Strategic Unconventional Fuels
reported that oil sands comprise only about 0.6% of U.S. solid and liquid fuel
resources, while oil shale accounts for nearly 25% of the total resource base.77
77 Development of America’s Strategic Unconventional Fuels Resources, September 2006,
p. 5.
CRS-25
Appendix A
Table A1. Estimated World Oil Resources
(in billions of barrels)
Proved
Reserve
Region and Country
Undiscovered
Total
Reserves
Growth
OECD
United States
22.4
76.0
83.0
180.4
Canada78
178.8
12.5
32.6
223.8
Mexico
12.9
25.6
45.8
84.3
Japan United States
0.1
0.1
0.3
0.5
Australia/ New Zealand
1.5
2.7
5.9
10.1
OECD Europe
15.1
20.0
35.9
71.0
Non-OECD
Russia
60.0
106.2
115.3
281.5
Other Non-OECD
19.1
32.3
55.6
107.0
Europe/Eurasia
China
18.3
19.6
14.6
52.5
India
5.8
3.8
6.8
16.4
Other Non-OECD Asia
10.3
14.6
23.9
48.8
Middle East
743.4
252.5
269.2
1,265.1
Africa
102.6
73.5
124.7
300.8
Central and South America
103.4
90.8
125.3
319.5
Total
1,292.5
730.2
938.9
2,961.6
OPEC
901.7
395.6
400.5
1,697.8
Non-OPEC
390.9
334.6
538.4
1,263.9
Sources: Proved Reserves as of January 1, 2006: Oil & Gas Journal, vol. 103, no. 47 (December 19,
2005), p. 46-47. Reserve Growth Total and Undiscovered, 1995-2025; U.S. Geological Survey, World
Petroleum Assessment 2000, website [http://greenwood.cr.usgs.gov/WorldEnergy/DDS-60]].
Estimates of Regional Reserve Growth: Energy Information Administration, International Energy
Outlook 2006, DOE/EIA-0484(2006) (Washington, DC, June 2006), p. 29.
Note: Resources Include crude oil (including lease condensates) and natural gas plant liquids.
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.
CRS-26
Appendix B
Table B1. Regional Distribution of Estimated Technically
Recoverable Heavy Oil and Natural Bitumen
(in billions of barrels)
Natural Bitumen
Heavy Oil
(oil sands)
Region
Recovery
Technically
Recovery
Technically
Factor a
Recoverable
Factor a
Recoverable
North America
0.19
35.3
0.32
530.9
South America
0.13
265.7
0.09
0.1
(Venezuela)
W. Hemisphere
0.13
301.0
0.32
531.0
Africa
0.18
7.2
0.10
43.0
Europe
0.15
4.9
0.14
0.2
Middle East
0.12
78.2
0.10
0.0
Asia
0.14
29.6
0.16
42.8
Russia
0.13
13.4
0.13
33.7 b
E. Hemisphere
0.13
133.3
0.13
119.7
World
434.3
650.7
Source: U.S. Department of the Interior. U.S. Geological Survey Fact Sheet, FS 070-03 August 2003.
Note: Heavy oil and natural bitumen are resources in known accumulations.
a. Recovery factors were based on published estimates of technically recoverable and in-place79 oil
or bitumen by accumulation. Where unavailable, recovery factors of 10% and 5% of heavy oil
or bitumen in-place were assumed for sandstone and carbonate accumulations, respectively.
b. In addition, 212.4 billion barrels of natural bitumen in-place is located in Russia but is either in
small deposits or in remote areas in eastern Siberia.
79 In-place oil is a continuous ore body that has maintained its original characteristics.
CRS-27
Acronyms and Abbreviations
AEUB
Alberta Energy and Utility Board
API
American Petroleum Institute
ARC
Alberta Research Council
ARCO
Atlantic Richfield Company
CCA
Capital Cost Allowance
CONRAD
Canadian Oil Sands Network for Research and Development
COS
Canadian Oil Sands
CSS
Cyclic Steam Stimulator
EIA
Energy Information Administration
GCOS
Great Canadian Oil Sands Company
GHG
greenhouse gases
IEA
International Energy Agency
mbd
million barrels per day
NEB
National Energy Board
OPEC
Organization of Petroleum Exporting Countries
PADD
Petroleum Administration for Defense District
R&D
research and development
ROI
return on investment
SAGD
steam-assisted gravity drainage
SCO
synthetic crude oil
SIRCA
Scientific and Industrial Research Council of Alberta
USGS
United States Geological Survey
VAPEX
Vapor Extraction Process
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