North American Oil Sands: History of Development, Prospects for the Future
Congressional research reportJan 17, 2008
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Prepared for Members and Committees of Congress
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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 46% 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 sands reserves, has ranked second behind Saudi Arabia in oil reserves.
Canadian crude oil exports were about 1.82 million barrels per day (mbd) in 2006, of which 1.8
mbd or 99% went to the United States. Canadian crude oil accounts for about 18% of U.S. net
imports and about 12% 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% inorganic 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 2.8 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
has recently been modified to increase revenue to the Alberta government. 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.
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Introduction ..................................................................................................................................... 1
World Oil Sands Reserves and Resources....................................................................................... 2
What Are Oil Sands?................................................................................................................. 2
U.S. Oil Sand Resources ........................................................................................................... 3
Canadian Oil Sand Resources ................................................................................................... 3
History of Development .................................................................................................................. 5
Role of Industry and Government............................................................................................. 5
U.S. Oil Sands..................................................................................................................... 5
Canadian Oil Sands............................................................................................................. 6
Oil Sands Production Process ................................................................................................... 8
Extraction Process............................................................................................................... 9
Production Technology ......................................................................................................11
Upgrading ......................................................................................................................... 13
Cost of Development and Production ............................................................................... 15
Tax and Royalty on Oil Sands .......................................................................................... 16
U.S. Markets............................................................................................................................ 18
Pipelines............................................................................................................................ 18
Environmental and Social Issues................................................................................................... 19
Issues for Congress........................................................................................................................ 21
Prospects for the Future................................................................................................................. 22
Acronyms and Abbreviations ........................................................................................................ 25
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Figure 1. Tar (Oil) Sand Deposits of the United States ................................................................... 3
Figure 2. Oil Sands Areas in Alberta, Canada ................................................................................. 4
Figure 3. Major Mining Process Steps ............................................................................................ 9
Figure 4. In-SITU Recovery...........................................................................................................11
Figure 5. Upgrading to SCO.......................................................................................................... 13
Figure 6. Oil Sands Processing Chain ........................................................................................... 14
Figure 7. Major Canadian and U.S. (Lower 48) Crude Oil Pipelines and Markets....................... 19
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Table 1. Canada’s Bitumen Resources ............................................................................................ 4
Table 2. Leading Oil Sands Producers........................................................................................... 10
Table 3. Estimated Operating and Supply Cost by Recovery Type............................................... 16
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Appendix A. Estimated World Oil Resources ............................................................................... 23
Appendix B. Regional Distribution of Estimated Technically Recoverable Heavy Oil and
Natural Bitumen ......................................................................................................................... 24
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Author Contact Information .......................................................................................................... 25
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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 46% 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 1.82 million barrels
per day in 2006, of which 1.8 mbd or 99% went to the United States. Canadian crude oil accounts
for about 18% of U.S. net imports and about 12% 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 1.2 (mbd) to 2.8 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.
Challenges such as higher energy costs, infrastructure requirements, and the environment, may
slow the growth of the industry. For example, high capital and energy input costs have made
some projects less economically viable despite recent high oil prices. Canada ratified the Kyoto
Protocol in 2002, which bound Canada to reducing its greenhouse gas (GHG) emissions
significantly by 2012 but according to the government of Canada they will not meet their Kyoto
air emission goals by 2012. The Pembina Institute reports that the oil sands industry accounts for
the largest share of GHG emissions growth in Canada.3
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
1
DOE, EIA, International Energy Outlook, 2006, p. 29.
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.
2
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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.
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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.
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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% inorganic 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
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.
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API and a 3.3% sulfur content and for the SCO (light oil) are 36 API and a 0.015% sulfur
content.9
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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).
Figure 1. Tar (Oil) Sand Deposits of the United States
Source: Major Tar Sand and Heavy Oil Deposits of the United States
2.
, Interstate Oil Compact Commission, 1984, p.
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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
9
Canada’s Oil Sands, May 2004, p. 10.
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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 surfacemineable. 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 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
. Oil Sands Areas in Alberta, Canada
Figure 2
Source:
National Energy Board, Alberta, Canada.
Table 1. Canada’s Bitumen Resources
Billion
Barrels
Ultimate
Volume in
Place
Initial
Volume
in Place
Athabasca
138.0
113.0
Athabasca
N/A
1,188.0
Ultimate
Initial
Recoverable Established
Volume
Reserves
Mineable
Cumulative
Production
Remaining
Established
Reserves
69.0
35.0
2.5
32.7
N/A
N/A
N/A
N/A
In Situ
10
Canada’s Oil Sands, May 2004, p. 4.
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.
11
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Billion
Barrels
Ultimate
Volume in
Place
Initial
Volume
in Place
Ultimate
Recoverable
Volume
Initial
Established
Reserves
Cumulative
Production
Remaining
Established
Reserves
Cold Lake
Peace
River
Subtotal
N/A
N/A
201.0
129.0
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
2,378.0
1,518.0
245.0
142.8
1.26
141.5
2,516.0
1,631.0
314.0
177.8
3.76
174.2
Total
Source:
Alberta Energy Utility Board.
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
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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.
14
Canadian Oil Sands, May 2004, p. 25.
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.
15
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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 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
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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 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
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.
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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. Suncor29 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 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
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.
30
A Billion Barrels for Canada, The Syncrude Story, pp. 44-45.
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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), 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
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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.
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, 2001-02. 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.
ȱȱȱ
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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.
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).
¡ȱȱ
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
39
40
Oil Sands Technology Roadmap, p. 20.
Oil Sands Industry Update, AED, June 2006, p. 7.
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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)
Project Owner
Type of
Project
2002
2003
2006
1st Quarter
Planned
Production
Targets
Suncor
Syncrude
Athabasca Oil Sands
(Shell, Chevron, and
Marathon Oil)a
Imperial Oil
CNRL
Petro Canada
Mining
Mining
206,000
230,000
217,000
212,000
264,400
205,000
410,000
560,00
Mining
N/A
130,000
77,400
525,000
In-situ
In-situ
In-situ
112,000
N/A
4,500
130,000
35,000
16,000
180,000
500,000
100,000
EnCana
In-situ
N/A
5,300
150,000
122,000
21,000
(2005)
36,000
250,000
, Alberta Economic Development, 2004 and 2006.
Marathon Oil Corp. acquired Western Oil Sands, Inc. on October 18, 2007.
Source: Oil Sands Industry Update
a.
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.
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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:
Oil 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
ŚŜȱ
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 upgrading, while Syncrude uses both coking and hydrocracking and Shell uses
hydrocracking. (For the complete oil sands processing chain, see Figure 6.)
45
46
Canada’s Oil Sands, June 2006.
Overview of Canada’s Oil Sands, TD Securities, January 2004, p. 19.
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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.
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.
47
NEB, June 2006, pp. 20-21.
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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. The NEB in its Energy Market
Assessment estimated that between US$30-$35 per barrel oil is required to achieve a 10% ROI.49
Operating costs 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 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
48
49
COS, 2004, p. 9.
COS, 2006, p. 5.
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for lowering natural gas use and costs.50 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)
Cold Production - Wabasca, Seal
Cold Heavy Oil Production and Sand (CHOPS) - Cold Lake
Cyclic Stream Stimulation (CSS)
Steam Assisted Gravity Drainage (SAGD)
Mining/Extraction
Integrated Mining/Upgrading
Crude
Operating
Supply
Type
Cost
Cost
Bitumen
Bitumen
Bitumen
Bitumen
Bitumen
SCO
6-9
8-10
10-14
10-14
9-12
18-22
14-18
16-19
20-24
18-22
18-20
36-40
, National Energy Board, Canada, June 2006.
Note: Supply costs for the first five technologies do not include the coat of upgrading bitumen to SCO.
Source: Canada’s Oil Sands, Opportunities and Challenges to 2015
¡ȱȱ¢¢ȱȱȱȱ
In 1997 the Alberta government implemented a “Generic Oil Sands Royalty Regime”51 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.52 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.
50
COS, 2004, p. 18.
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.
51
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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 2007/2008.53 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.”54 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.55 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 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.56
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.57 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).58 The
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
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.
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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.
The federal government of Canada, however, provided some balance by reducing the general
federal corporate income tax rate from 22.1% to 15% beginning in 2012.59
ǯǯȱȱ
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%,
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.
ȱ
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.
59
Canadian Department of Finance, Economic Statement, October 30, 2007.
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.
60
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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. Most of the new projects are
scheduled to come online between 2008 and 2012. In addition, a couple of U.S. pipelines
reversed their flow of crude oil (from south to north) to now carry Canadian heavy crude,
originating from oil sands, to Cushing Oklahoma and Southeast Texas. 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
ȱȱȱ ȱ
The Federal Government of Canada classified the oil sands industry as a large industrial air
pollution emitter (i.e., emitting over 8,000 tons CO2/year) and expects it to produce half of
Canada’s growth in greenhouse gas (GHG) emissions63 (about 8% total GHG emissions) by 2010.
The oil sands industry has reduced its “emission intensity” by 29% between 1995-2004 while
production was rising. CO2 emissions have declined from 0.14 tons/bbl to about 0.08 tons/bbl or
about 88 megatons since 1990.64 Alberta’s GHG goals of 238 megatons of CO2 in 2010, and 218
megatons CO2 in 2020 are not expected to be met.65 Reducing air emissions is one of the most
serious challenges facing the oil sands industry. However, according to the Pembina Institute, a
62
“Oil Sands Producers Facing Pipeline Capacity Constraints,” The Energy Daily, August 7, 2007.
Greenhouse gas emissions include carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons,
and sulfur hexafluoride.
64
COS, 2004, p. 62.
65
Ibid., p. 63.
63
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sustainable energy advocate, greenhouse gas emissions intensity (CO2/barrel) from oil sands is
three times as high as that from conventional oil production.66 The industry believes if it can
reduce energy use it can reduce its emissions. As emissions per barrel of oil from oil sands
decline overall, the Canadian government projects that total GHG emissions will continue to rise
through 2020, 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 2-3 barrels
of water are used from the Athabasca river for each barrel of bitumen produced; but when
recycled produced water is included, 0.5 barrels of “make-up” water is required, according to the
Alberta Department of Energy. 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.68 Concerns, however, 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.
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
66
Oil Sands Fever, by Dan Woynillowicz, et al., The Pembina Institute, November 2005.
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
Ibid., p. 69.
67
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(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 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.
ȱȱȱ
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.
72
For more on byproducts, see Canada’s Oil Sands, p. 70.
Ibid., p. 71.
74
Ibid.
75
Oil Sands Industry Update, AED, June 2006, p. 29.
76
Section 369 of Energy Policy Act of 2005.
73
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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.
ȱȱȱȱ
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 5% 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.
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ȱȱȱDZȱ ¢ȱȱǰȱȱȱȱȱ
ȱ
¡ȱǯ ȱȱȱȱ
(in billions of barrels)
Region and Country
Proved
Reserve
Reserves
Growth
Undiscovered
Total
OECD
United States
Canada78
Mexico
Japan United States
Australia/ New Zealand
OECD Europe
22.4
76.0
83.0
180.4
178.8
12.9
0.1
1.5
15.1
12.5
25.6
0.1
2.7
20.0
32.6
45.8
0.3
5.9
35.9
223.8
84.3
0.5
10.1
71.0
106.2
32.3
19.6
3.8
14.6
252.5
73.5
90.8
730.2
395.6
334.6
115.3
55.6
14.6
6.8
23.9
269.2
124.7
125.3
938.9
400.5
538.4
281.5
107.0
52.5
16.4
48.8
1,265.1
300.8
319.5
2,961.6
1,697.8
1,263.9
Non-OECD
Russia
Other Non-OECD Europe/Eurasia
China
India
Other Non-OECD Asia
Middle East
Africa
Central and South America
Total
OPEC
Non-OPEC
60.0
19.1
18.3
5.8
10.3
743.4
102.6
103.4
1,292.5
901.7
390.9
Oil & Gas Journal, vol. 103, no. 47 (December 19, 2005), p. 4647. Reserve Growth Total and Undiscovered, 1995-2025; U.S. Geological Survey, World Petroleum Assessment
2000, website http://pubs.usgs.gov/dds/dds-060/. Estimates of Regional Reserve Growth: Energy Information
Administration, International Energy Outlook 2006, DOE/EIA-0484(2006) (Washington, DC, June 2006), p. 29.
Sources: Proved Reserves as of January 1, 2006:
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.
ȱȱȱ
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ȱ
¡ȱǯ ȱȱȱȱ
¢ȱȱ ¢ȱȱȱȱ
ȱ
(in billions of barrels)
Region
Heavy Oil
Recovery
Technically
Factora
Recoverable
North America
South America
(Venezuela)
W. Hemisphere
Africa
Europe
Middle East
Asia
Russia
E. Hemisphere
World
Natural Bitumen (oil sands)
Recovery
Technically
Factora
Recoverable
0.19
0.13
35.3
265.7
0.32
0.09
530.9
0.1
0.13
0.18
0.15
0.12
0.14
0.13
0.13
301.0
7.2
4.9
78.2
29.6
13.4
133.3
434.3
0.32
0.10
0.14
0.10
0.16
0.13
0.13
531.0
43.0
0.2
0.0
42.8
33.7b
119.7
650.7
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.
Source:
79
In-place oil is a continuous ore body that has maintained its original characteristics.
ȱȱȱ
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ȱ
¢ȱȱȱ
AEUB
API
ARC
ARCO
CCA
CONRAD
COS
CSS
EIA
GCOS
GHG
IEA
mbd
NEB
OPEC
PADD
R&D
ROI
SAGD
SCO
SIRCA
USGS
VAPEX
Alberta Energy and Utility Board
American Petroleum Institute
Alberta Research Council
Atlantic Richfield Company
Capital Cost Allowance
Canadian Oil Sands Network for Research and Development
Canadian Oil Sands
Cyclic Steam Stimulator
Energy Information Administration
Great Canadian Oil Sands Company
greenhouse gases
International Energy Agency
million barrels per day
National Energy Board
Organization of Petroleum Exporting Countries
Petroleum Administration for Defense District
research and development
return on investment
steam-assisted gravity drainage
synthetic crude oil
Scientific and Industrial Research Council of Alberta
United States Geological Survey
Vapor Extraction Process
ȱȱ ȱ
(name redacted)
Analyst in Energy Policy
/redacted/@crs.loc.gov, 7-....
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