User manual | oil

National Energy
Board
Office national
de l’énergie
Canada’s Oil Sands:
oiloil
A Supply and Market Outlook
to 2015
oiloil
An ENERGY MARKET ASSESSMENT • October 2000
National Energy
Board
Office national
de l’énergie
Canada’s Oil Sands:
oiloil
A Supply and Market Outlook
to 2015
oiloil
An ENERGY MARKET ASSESSMENT • October 2000
© Her Majesty the Queen in Right of Canada as
represented by the National Energy Board 2000
© Sa Majesté la Reine du chef du Canada representée par
l’Office national de l’énergie 2000
Cat. No. NE23-89/2000E
ISBN 0-662-29467-X
Nº de cat. NE23-89/2000F
ISBN 0-662-85138-2
This report is published separately in both official
languages.
Ce rapport est publié séparément dans les deux
langues officielles.
Copies are available on request from:
Publications Office
National Energy Board
444 Seventh Avenue S.W.
Calgary, Alberta
T2P 0X8
Fax: (403) 292-5503
Phone: (403) 299-3562
1-800-899-1265
Internet: www.neb.gc.ca
Exemplaires disponibles sur demande auprès du:
Bureau des publications
Office national de l’énergie
444, Septième Avenue S.-O.
Calgary (Alberta)
T2P 0X8
Télécopieur: (403) 292-5503
Téléphone: (403) 299-3562
1-800-899-1265
Internet: www.neb.gc.ca
For pick-up at the NEB office:
Library
Ground Floor
En personne, au bureau de l’Office:
Bibliothèque
Rez-de-chaussée
Printed in Canada
Imprimé au Canada
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List of Figures
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List of Tables
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List of Acronyms
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Foreword
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Executive Summary
viii
Chapter 1: Introduction
Chapter 2: Oil Sands Resources
2.1
2.2
2.3
2.4
2.5
2.6
2.7
Introduction
Bitumen Resources
Oil Genesis, Migration and Biodegradation
Oil Sands and Bitumen Characteristics
Reservoir Characteristics
Geology of the Alberta Oil Sands Regions
2.6.1 Stratigraphy
2.6.2 Structure
2.6.3 Reservoir Descriptions
Conclusion
Chapter 3: Oil Sands Pioneers
3.1
3.2
3.3
3.4
3.5
3.6
Introduction
Early Days
Sidney C. Ells
Dr. Karl A. Clark
Early Projects
3.5.1 Bitumount
3.5.2 Abasand
3.5.3 Blair Report
3.5.4 First Commercial Mining Projects
3.5.5 First Commercial In Situ Projects
Conclusion
Chapter 4: A Review of Oil Sands Technology
4.1
4.2
Introduction
Integrated Mining/Upgrading Plants
4.2.1 Mining
4.2.2 Extraction
NATIONAL ENERGY BOARD
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4.3
4.4
4.5
4.6
4.2.3 Tailings Disposal
4.2.4 Upgrading
In Situ Recovery
4.3.1 Cyclic Steam Stimulation
4.3.2 Pressure Cycle Steam Drive
4.3.3 Steam-Assisted Gravity Drainage
Primary Bitumen Recovery
4.4.1 Cold Lake
4.4.2 Wabasca
Science and Technology
4.5.1 Mining and Extraction
4.5.2 Upgrading
4.5.3 In Situ
4.5.4 Primary Production
Conclusion
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Chapter 5: Supply Costs
5.1
5.2
5.3
5.4
5.5
5.6
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Introduction
Methodology
Oil Sands Mining Projects
5.3.1 Supply Costs - Oil Sands Mining
5.3.2 Supply Cost Projections - Mining
In Situ Projects
5.4.1 Supply Costs - In Situ
5.4.2 Supply Cost Projections - In Situ
Oil Sands Fiscal Regime
5.5.1 New Royalty and Taxation Measures
Conclusion
Chapter 6: Crude Oil Supply
6.1
6.2
6.3
6.4
6.5
ii
Introduction
Supply Projections
6.2.1 Methodology
6.2.2 Oil Sands Mining
6.2.3 Price Sensitivities - Oil Sands Mining
6.2.4 Oil Sands In Situ
6.2.5 Price Sensitivities - Oil Sands In Situ
6.2.6 Pentanes Plus Supply
6.2.7 Diluent Requirement
6.2.8 Net Available Supply - Crude Oil and Equivalent
Oil Sands Mining and In Situ Projects
Athabasca Deposit
6.4.1 Oil Sands Mining Projects
6.4.2 Other Mining Projects
6.4.3 In Situ Project
6.4.4 Other Projects
Cold Lake Deposit
6.5.1 In Situ Projects
6.5.2 Other Projects
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AN ENERGY MARKET ASSESSMENT
6.6
6.7
6.8
Peace River Deposit
Synergistic Development
Conclusion
Chapter 7: Pipelines
7.1
7.2
7.3
7.4
7.5
7.6
Introduction
Alberta Hubs
Feeder Pipelines
Trunklines
New Pipelines
Conclusion
Chapter 8: Markets
8.1
8.2
8.3
8.4
8.5
8.6
Introduction
Refining/Upgrading
Markets For Canadian Crude Oil
8.3.1 Western Canada
8.3.2 Eastern Canada
8.3.3 United States
Competition From Foreign Crude Oil Sources
Overall Assessment of Available Markets For Synthetic and Blended Bitumen
Conclusion
Chapter 9: Environment
9.1
9.2
9.3
9.4
Introduction
Regulatory Background
9.2.1 Regulatory Framework
9.2.2 Multi-Stakeholder Initiatives
9.2.3 Policies and Guidelines
Environmental Issues
9.3.1 Land
9.3.2 Water Use and Quality
9.3.3 Air Emissions
9.3.4 Cumulative Environmental Impacts
9.3.5 Socio-Economic Effects
Conclusion
Glossary
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Appendix 1:
EUB Resource Estimation Methodology
102
Appendix 2:
Supply Costs for SAGD
103
Appendix 3:
Economic Indicators, Canada
106
Appendix 4:
Conversion Table
107
NATIONAL ENERGY BOARD
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L I S T
O F
F I G U R E S
A N D
T A B L E S
F IGURES
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2.1
2.2
2.3
2.4
Athabasca, Cold Lake and Peace River Oil Sands Areas
Oil Migration Path
Bitumen Characteristics
Northeastern Alberta Stratigraphic Succession
4
6
7
9
3.1
3.2
3.3
Sidney C. Ells
Dr. Karl A. Clark
Early Projects
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4.1
4.2
4.3
4.4
4.5
4.6
Old versus New Mining Method
Old versus New Extraction and Froth Treatment
Cyclic Steam Stimulation
Underground Test Facility
Steam-Assisted Gravity Drainage
Multilateral Horizontal Well
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5.1
5.2
Athabasca Deposits Supply Cost - SAGD
Cold Lake Deposits Supply Cost - SAGD
38
38
6.1
6.2
6.3a
6.3b
6.4a
6.4b
6.4c
6.5
6.6a
6.6b
6.6c
Supply Projections - Oil Sands Mining
Supply Projections - Oil Sands In Situ
Base Case: Pentanes Plus Supply versus Net Diluent Requirement
$14 & $22 Sensitivity: Pentanes Plus Supply vs. Net Diluent Requirement
Net Available Supply: Base Case
Net Available Supply: $22 Sensitivity
Net Available Supply: $14 Sensitivity
Oil Sands Projects
Daily Natural Gas Requirement Integrated Mining/Upgrading Plants
Daily Natural Gas and Electrical Power Requirements In Situ Projects
Daily Electrical Power Requirement Integrated Mining/Upgrading Plants
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7.1
7.2
Feeder Pipelines
Major Canadian and U.S. Crude Oil Pipelines and Markets
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8.1
8.2
8.3
8.4
8.5
8.6
Gross Synthetic and Blended Bitumen Production
Net Synthetic and Blended Bitumen Production
Western Canada Receipts of Canadian Crude Oil - 1999
Ontario Receipts of Canadian Crude Oil - 1999
PADD I Receipts of Canadian Crude Oil - 1999
PADD II Receipts of Canadian Crude Oil - 1999
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AN ENERGY MARKET ASSESSMENT
8.7
8.8
8.9
PADD III Receipts of Canadian Crude Oil - 1999
PADD IV Receipts of Canadian Crude Oil - 1999
PADD V Receipts of Canadian Crude Oil - 1999
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9.1
Estimated Greenhouse Gas Emissions
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TABLES
2.1
2.2
2.3
2.4
Crude Bitumen Resources
Comparison of World Bitumen Resources
Comparison of Crude Oil Characteristics
Reservoir Characteristics
5.1
Estimated Supply Costs
35
6.1
6.2
6.3
6.4
Oil Sands Mining Projects
Athabasca In Situ Projects
Cold Lake In Situ Projects
Current Cogeneration Facilities
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7.1
Announced Trunkline Capacity Expansions
65
8.1
Canadian Crude Oil Markets - 1999
68
NATIONAL ENERGY BOARD
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v
A CRONYMS
AEC
AENV
BTEX
CAPP
CASA
CCME
CEMA
CFCs
CONRAD
CNRL
CSS
CT
DRU
EIA
EPEA
EUB
GCOS
GHG
IPS
MOU
NEB
NOSTF
OCWE
OSCA
OSLO
PADD
PLA
PM
PSV
RAC
RSDS
SAGD
TOR
TPG
UTF
VAPEX
VDU
VOCs
WBEA
WCSB
WTI
vi
Alberta Energy Company Ltd.
Alberta Environment
Benzene, Toluene, Ethylbenzene, and Xylene
Canadian Association of Petroleum Producers
Clean Air Strategic Alliance
Canadian Council of Ministers of the Environment
Cumulative Effects Management Association
Chlorofluorocarbons
Canadian Oilsands Network for Research and Development
Canadian Natural Resources Ltd.
Cyclic Steam Stimulation
Consolidated or Composite Tailings
Diluent Recovery Unit
Environmental Impact Assessment
Environmental Protection and Enhancement Act
Alberta Energy and Utilities Board
Great Canadian Oil Sands
Greenhouse Gases
Inclined Plate Settlers
Memorandum of Understanding
National Energy Board of Canada
National Oil Sands Task Force
OSLO Cold Water Extraction
Oil Sands Conservation Act
Other Six Lease Owners
Petroleum Administration Defence District
Public Lands Act
Particulate Matter
Primary Separation Vessels
Reclamation Advisory Committee
Regional Sustainable Development Strategy
Steam Assisted Gravity Drainage
Tailings Oil Recovery
Technical Planning Group
Underground Test Facility
Vapour Extraction Process
Vacuum Distillation Unit
Volatile Organic Compounds
Wood Buffalo Environmental Association
Western Canadian Sedimentary Basin
West Texas Intermediate
AN ENERGY MARKET ASSESSMENT
F OREWORD
The National Energy Board (the Board or NEB), as part of its regulatory mandate, is required to
keep under review the outlook for Canadian supply of all energy commodities including electricity,
oil, natural gas and their by-products and the demand for Canadian energy commodities in both the
domestic and export markets.
As a result of the increasing level of integration within energy markets, the Board implemented a
program of Energy Market Assessments (EMA) to provide analyses of the major energy commodities
on either an individual or integrated commodity basis. The EMA program includes what were
previously known as Natural Gas Market Assessment (NGMA) reports, as well as the Canadian Energy
Supply and Demand reports.1
This EMA is the first focussing specifically on crude oil, and is entitled Canada’s Oil Sands: A Supply
and Market Outlook to 2015. The main objective of this report is to review the supply and market for
bitumen and synthetic crude oil derived from Canada’s oil sands, to the year 2015. In addition to the
supply and market, the report also discusses the early history of oil sands development, the role of
science and technology in advancing oil sands development, supply costs, pipeline infrastructure and
environmental issues. The study also examines the impact of oil sands development on the natural
gas and electricity markets in Canada.
For this report the Board conducted a series of informal meetings and conversations with a
representative cross-section of the oil sands industry, including producers, marketers, refiners,
pipeliners, industry associations, research institutions, consultants, government agencies and
environmental protection groups. Several private individuals, now retired, provided valuable
comment and insight.
The NEB greatly appreciates the information and comments provided and would like to thank all
who participated for their time and expertise. This input played an important role in the formulation
of the Board’s views, and combined with the Board’s own analysis provides the basis for the supply
and market outlook provided in this report.
The primary purpose of this report is to provide a projection of the supply and market for bitumen
and synthetic crude oil for the information of the public. It should not be perceived as a
recommendation to the Minister of Natural Resources Canada, nor should it be considered to be an
expression of views on energy policy matters.
1 Canadian Energy Supply and Demand to 2025, published in June 1999, is the most recent report.
NATIONAL ENERGY BOARD
vii
E XECUTIVE S UMMARY
Based on publicly announced development plans covering the period 1996 to 2010, nearly
C$34 billion worth of projects are planned to expand petroleum production from the oil sands, with
about C$7 billion spent to date. These development plans consist of an array of nearly 60 projects
that would increase the production volumes of synthetic crude oil (also known as upgraded) and
bitumen, to a combined level of about 300 000 m3/d1 by 2010, or nearly three times current levels,
assuming all projects proceed as announced. History suggests that oil prices and markets will be
volatile, and it is therefore unlikely that all C$34 billion worth of announced projects will proceed as
planned. The marketplace will dictate the timing and magnitude of incremental production volumes.
This report provides an assessment of the supply situation for synthetic crude oil and bitumen and the
market’s ability to absorb the projected supply, to the year 2015. In order to provide background for
this discussion, sections on oil sands resources, oil sands pioneers, technological innovation, supply
costs, pipeline capacity and environmental impacts of oil sands development are also included.
Clearly, the oil sands are a tremendous Canadian resource. The ultimate volume of crude bitumen in
place is estimated to be some 400 billion cubic metres, with 12 percent or 49 billion cubic metres
estimated to be ultimately recoverable — a volume comparable to the proven conventional oil
reserves of Saudi Arabia.
By the early 1900s, the premise that there was a large pool of "free oil" beneath the oil sands, trapped
by shale formations, was disproved by drilling. While many saw value in the oil sands as a roadpaving material, and a number of paving projects were completed, transporting the oil sands from
such a remote location proved to be uneconomic. As the need for transportation fuels increased,
efforts to realize the oil sands value as a source of transportation fuels accelerated.
Among the oil sands pioneers, two men stood out — Sidney Ells and Karl Clark. Sidney Ells was a
federal civil servant who was in large part responsible for the early exploration and delineation of the
oil sands deposits. He saw the promise in the oil sands, and from 1913 until his retirement in 1954,
he was a tireless champion of its development. Dr. Karl Clark was one of the first employees of the
newly formed Alberta Council of Research, in 1921. His genius and dedicated research led to the
successful development of the hot water bitumen extraction process that provided the basis for the
extraction methodology currently used by the integrated mining plants at Fort McMurray.
The Blair Report, commissioned by the Alberta government and released in 1950, indicated that oil
sands mining and bitumen extraction would be economically feasible. This, plus a more favourable
provincial leasing policy, encouraged industry to pursue oil sands opportunities, both mining and in
situ. This paved the way for commencement of the first integrated oil sands mining/upgrading
operation in 1967, and the first commercial in situ recovery project in 1978.
Science and technology has always played a vital role in the oil sands industry, and research is
ongoing into a wide variety of problem areas. Supply costs for bitumen production from Canada’s oil
sands have been substantially reduced through a process of continuous improvement in all aspects of
1 One cubic metre (m3) of crude bitumen is approximately equal to 6.3 barrels or one metric tonne.
viii
AN ENERGY MARKET ASSESSMENT
operations and more importantly, through the implementation of major technological innovations,
with most of these innovations occurring in the 1990s.
A good deal of credit for the upsurge in oil sands activity in the 1990s belongs to the National Oil Sands
Task Force, whose 1995 report on oil sands strategies led to the adoption of a generic fiscal regime that
provides for stable and predictable royalty and tax treatment for all developers. In addition, its
recommendations led to the establishment of the Canadian Oil Sands Network for Research and
Development, which has very successfully promoted collaborative oil sands research efforts.
For the existing surface-mining operations, supply costs have been reduced by more than one-half in
the last twenty years, with current supply costs in the field estimated to be in the range of
C$15-18 per barrel. The adoption of truck and shovel mining, hydrotransport and low energy
extraction are the major reasons for this cost reduction.
For in situ operations, supply costs have also been reduced through continuous improvement and
innovation, although not to the same extent as in the surface-mining operations. Continuous
improvement in cyclic steam stimulation (CSS) operations, the maturation of horizontal well
technology and the development of the steam assisted gravity drainage (SAGD) recovery technique
are the major features that have facilitated this cost reduction. Current supply costs for CSS are
estimated to be in the C$10-16 per barrel range, while those for SAGD are estimated to be
C$8-14 per barrel. Costs for both methods are highly dependent on the quality of the reservoir.
Both integrated mining projects and thermal in situ projects use substantial amounts of natural gas as
a fuel source in their operations. Thus, the price of natural gas is an important determinant of the
level of profitability for these projects. The cost of condensate for blending of bitumen is also an
important consideration.
In regard to primary recovery, the development of extended-reach and multi-leg horizontal wells
facilitated the economic recovery of bitumen in the Wabasca region. In the Cold Lake region, the
adoption of the progressive cavity pump in vertical well bores reduced the cost of production.
Estimated supply costs for Wabasca are C$7-10 per barrel, compared to C$10-13 per barrel for
Cold Lake.
The supply projections use the economic assumptions contained in the Board’s Canadian Energy
Supply and Demand Report to 2025 (Supply and Demand Report) including a US$18 per barrel price
for benchmark West Texas Intermediate (WTI). The assumption is made that the supply projections
are unconstrained by markets or pipeline capacity. Similar to the Supply and Demand Report, price
sensitivities at US$14 and US$22 were included to gauge the relative response of production to price.
In the Base Case, synthetic crude oil production is projected to increase nearly three-fold compared to
current levels, reaching 158 000 m3/d by 2015. Similarly, bitumen production is projected to increase
by two and one-half times current production by 2015, reaching 104 000 m3/d by 2015. Considering
the declining trend in conventional heavy and conventional light crude oil production in Western
Canada, oil sands production could be over 50 percent of total Canadian crude oil production by 2015.
A shortfall of pentanes plus for purposes of blending bitumen could occur as early as 2005, given the
Base Case supply projections. This problem has the potential to constrain bitumen production, given
that solutions currently available represent a significant added expense for producers.
The net available supply of Canadian crude oil, in the Base Case, rises to 502 000 m3/d in 2008, then
gradually declines to about 490 000 m3/d by 2015. In the $22 Sensitivity, the net available supply
NATIONAL ENERGY BOARD
ix
includes production from the Mackenzie Delta-Beaufort Sea region and reaches a peak of about
606 000 m3/d before declining slightly by the end of the projection period. In the $14 Sensitivity, the
net available supply decreases to 314 000 m3/d by 2015, or about 5 percent below current levels.
An assessment of natural gas requirements and electrical power generation related to oil sands
development indicates that gas requirements would double to nearly 1 bcf/d by 2015, and that about
4.8 TW.h of generating capacity would be available to the Alberta power grid, also by 2015. This
represents about 7 percent of Alberta’s 1999 gas production and about 9 percent of its 1999 power
generation capacity.
Based on the estimated increased production of synthetic crude oil and bitumen over the next
15 years, it is expected that additional trunkline capacity will be added. Proposed expansion plans
have been announced by Express and Enbridge to serve key markets in Ontario, as well as in PADD
II and PADD IV in the U.S. This will increase trunkline capacity by 45 900 m3/d by January 2004, if
all announced pipeline proposals proceed.
An opportunity for Canadian producers to sell their increasing outputs of synthetic crude oil and
blended bitumen is developing in the North American marketplace. Product demands are growing
and more crude oil will have to be processed to satisfy these requirements. As well, conventional
light and conventional heavy crude oil production in both Canada and the U.S. is expected to decline
during the projection period.
The Board’s assessment of available markets for synthetic crude oil indicates that the increased
production will likely be absorbed in the marketplace, although some price discounting relative to
other light crude oils could be required. In the $22 Sensitivity, production of synthetic crude oil is
about 14 percent higher than in the Base Case; the Board believes that these quantities could be
marketed, but the price discount would likely have to widen. Marketing would not be an issue in the
$14 Sensitivity because there would be substantially reduced production of synthetic crude oil.
In the case of blended bitumen, marketability appears to be somewhat less certain than that for
synthetic crude oil, and it is conceivable that temporary supply imbalances could occur. The Board
believes, however, that in these situations there would be a widening of the light/heavy crude oil price
differential, which would provide the incentive to install upgrading facilities and, in turn, eliminate
the supply imbalances. In the $22 Sensitivity, production of blended bitumen would be 30 percent
greater than in the Base Case. In this situation, it is unlikely that the market could absorb these
volumes. Again, marketing would not be an issue in the $14 Sensitivity because of significantly
reduced output of blended bitumen.
The increasing project development currently underway or proposed will bring with it many
challenges for the industry, the public and the regulators. Careful planning is required to ensure that
no irreparable damage is done to the people and the environment, and that natural resources are
developed in a sustainable manner taking into account the needs of the future generations. Although,
in general, technological improvements have reduced environmental impacts on a per unit basis,
cumulative environmental impacts may increase as overall production increases. The many multistakeholder groups established over the last several years will be critical to managing the cumulative
effects of increasing development in the oil sands region. In addition, the Regional Sustainable
Development Strategy and subsequent development of management programs—a new and innovative
approach to managing the cumulative effects of an industry—will need to be closely scrutinized for
their effectiveness.
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AN ENERGY MARKET ASSESSMENT
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I NTRODUCTION
“That this region is stored with a substance of great economic value is beyond all doubt, and when
the hour of development comes, it will, I believe, prove to be one of the wonders of northern
Canada.”
These words, attributed to the chronicler of the Geological Survey of Canada’s (GSC) Liard
expedition of 1889, certainly ring true today, as the oil sands industry is entering an era of
unprecedented growth.
Clearly, the oil sands are a tremendous Canadian resource. The ultimate volume of crude bitumen in
place is estimated to be some 400 billion cubic metres1, with 12 percent or 49 billion cubic metres
estimated to be ultimately recoverablea — a volume comparable to the proven conventional oil
reserves of Saudi Arabia.
Based on publicly announced development plans covering the period 1996-2010, nearly C$34 billion
worth of projects are planned to expand production from the oil sands, with about C$7 billion spent
to date. These development plans are comprised of an array of nearly 60 projects that include:
expansions of existing integrated surface-mining/upgrading plants; new mining and upgrading
facilities; in situ and primary production projects; new pipelines and expansions of existing pipelines;
co-generation plants (electrical power and steam) and other related facilities. The production of
synthetic or upgraded crude oil and bitumen, assuming all projects proceed as announced, will reach a
combined level of about 300 000 m3/d, or nearly three times current levels by 2010.
Reasons for this upsurge in oil sands development include:
• a sharp reduction in operating costs, over the last decade, for integrated surface
mining/upgrading projects — due in large part to the development and adoption of new
technology;
• the development of the steam assisted gravity drainage (SAGD) method for in situ bitumen
recovery;
• advances in horizontal well technology;
• the establishment of a generic fiscal regime that provides for stable and predictable royalty
and tax treatment for all developers;
• a growing North American market opportunity resulting from declining domestic
conventional crude oil production levels in both Canada and the United States combined
with increasing demand; and,
• strong recent crude oil prices and optimism regarding future oil prices.
1 One cubic metre (m3) of crude bitumen is approximately equal to 6.3 barrels or one metric tonne.
NATIONAL ENERGY BOARD
1
The National Oil Sands Task Force deserves a good deal of credit for providing considerable impetus
to the recent pace of development of the oil sands industry. The Task Force was formed in 1993 by
the Alberta Chamber of Resources and included representation from operating companies, research
agencies, suppliers, as well the federal and provincial governments. This group released a major
report in 1995, that set out a vision for oil sands development.b This vision emphasized collaboration
by all stakeholders, investment in science and technology, and environmental protection. The group
also recommended changes to the fiscal regime and regulatory framework, as well as improvements to
market access and transportation systems.
Many of the Task Force recommendations have been acted on, including changes to the fiscal regime
for oil sands. The establishment of the Canadian Oil Sands Network for Research and Development
(CONRAD), to coordinate oil sands research efforts has proven to be very successful.
History suggests that oil prices and markets will be volatile, and it is therefore unlikely that all
C$34 billion worth of announced projects will proceed as planned. The marketplace will dictate the
timing and magnitude of incremental production volumes.
The primary purpose of this report is to provide an assessment of the supply situation for synthetic
crude oil and bitumen and the market’s ability to absorb the projected supply. The impact of the
projected oil sands developments on natural gas and electricity requirements is also examined.
To support the discussion of supply and markets, the report begins with some background
information, including:
• a summary of important events and individuals that shaped the early oil sands history;
• a review of the crude bitumen resource base and the important characteristics of the oil
sands deposits and the bitumen contained therein; and,
• a review of the methods and technologies employed in current oil sands operations, in the
context of a comparison of new versus old to highlight the important innovations, and a
review of current research efforts to highlight the importance of science and technology.
The core of the report provides a review of:
• supply costs for the various types of bitumen recovery and upgrading methods, including a
discussion of the fiscal and royalty regime;
• supply projections to the year 2015, for synthetic crude oil and bitumen;
• the natural gas and electricity requirements directly related to oil sands operations;
• the existing pipeline network, future expansion, and capacity to move the expected
incremental production to market;
• the market potential for the synthetic crude oil and bitumen in the domestic and export
markets; and,
• the environmental impact of oil sands operations, steps being taken to reduce this impact
and the organizations involved.
Supply costs for integrated surface-mining/upgrading projects have decreased from $30 to less than
$13 per barrel (dollars of the day) in the last twenty years, due to continuous improvement in
operations but also as a result of the development of innovative technologies. These innovations
include the switch to truck and shovel operations from the dragline, bucketwheel and conveyor
method, plus the development of the hydrotransport and low energy extraction systems.
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AN ENERGY MARKET ASSESSMENT
The development of the steam assisted gravity drainage (SAGD) recovery method can be considered
a major enabling technology. It has a number of advantages compared to previous steam stimulation
methods that make it applicable to a wider range of bitumen reservoirs. Although not yet
commercially proven on a large scale, industry confidence in this technology is illustrated by the fact
that six commercial SAGD projects are currently planned to be in operation by 2005.
The supply costs for in situ projects have also been reduced through continuous improvement.
Currently, most in situ operations utilize some form of cyclic steam stimulation (CSS) or SAGD
recovery methods that use natural gas to provide heat for generating steam. The supply costs for
these projects are highly dependent on the price of natural gas and the steam to oil ratio (SOR) or the
amount of steam required per unit of production.
An analysis of the effect of higher gas prices on the economics of SAGD was undertaken for this
report. For in situ bitumen the differential between the price of light versus heavy crude oil is also an
important consideration, as is the cost and amount of natural gas condensate required for blending to
meet pipeline specifications.
The supply projections use the the economic assumptions contained in the Board’s Canadian Energy
Supply and Demand Report to 2025 (Supply and Demand Report) including a US$18 (1997, real,
constant) per barrel price for benchmark West Texas Intermediate (WTI) crude oil at Cushing,
Oklahoma. The assumption is made that the supply projections are unconstrained by markets or
pipeline capacity. The projections include currently operating projects plus those project expansions
or new projects already under construction, while other projects are ranked according to their relative
merits. An industry cash-flow model is also used to assess the potential pace of production growth.
Similar to the Supply and Demand Report, price sensitivities at US$14 and US$22 were included to
gauge the relative response of production to price.
The review of pipelines describes current feeder and trunk lines as well as plans for new construction
and expansion.
Due to declining conventional light and conventional heavy production in both Canada and the
United States, and steadily rising demand for crude oil, a significant market opportunity is developing
for synthetic crude oil and blended bitumen from Canada’s oil sands. The review of markets
examines the potential for the rising output of synthetic crude oil and blended bitumen to serve this
market and also provides a discussion of the important factors determining whether the markets can
absorb these volumes.
The discussion of environmental issues sets out the impact of oil sands activities on land, water, and
air quality and also discusses the socio-economic impacts. In addition, it examines the programs and
practices that are used to manage these impacts. As well, it describes various collaborative efforts on
the part of industry, governments, local municipalities, aboriginal groups and environmental
protection groups to improve environmental performance.
References
a) Alberta Energy and Utilities Board, Alberta’s Reserves 1999, Volume 1, Statistical Series
2000-18.
b) National Task Force on Oil Sands Strategies, The Oil Sands: A New Vision for Canada,
Alberta Chamber of Resources, 1995.
NATIONAL ENERGY BOARD
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2.1
Introduction
This chapter presents a brief description of the location, magnitude, geological setting and
characteristics of Canada’s oil sands, including a discussion of crude bitumen characteristics.
2.2
Bitumen Resources
Canada’s resources of crude bitumen occur entirely within the province of Alberta1 and are found in
sand and carbonate sedimentary formations in three regions defined as the Athabasca, Cold Lake and
Peace River Oil Sands Areas (Figure 2.1). These areas cover a minimum of 4.3 million hectares,
729 thousand hectares and 976 thousand hectares respectively. The total area of the three regions is
comparable in size to the province of New Brunswick, or to the countries of Scotland or Belgium.
F I G U R E
2 . 1
Athabasca
Fort
McMurray
Wabasca
Peace River
Cold Lake
Edmonton
0.4
4.3
Calgary
The NEB adopts the crude bitumen
resource estimates published by the
Alberta Energy and Utilities Board
(EUB).a The EUB estimates the
initial volume in place of crude
bitumen to be 259.2 billion cubic
metres,2 based on currently available
data. The EUB further estimates the
ultimate volume in place, a value
representing the volume expected to
ultimately be found by the time all
exploratory and development activity
has ceased, to be 400 billion cubic
metres. Of this volume, 24 billon
cubic metres are categorized as
amenable to surface mining and
376 billion cubic metres available
through in situ recovery or
underground mining methods. The
division between the surface mining
and in situ areas is based on the
thickness of the overburden, with
thicknesses greater than 75 metres
1 Minor oil sands deposits exist on Melville Island in Canada’s Arctic Island Region.
2 One cubic metre (m3) of crude bitumen is approximately equal to 6.3 barrels or one metric tonne.
4
AN ENERGY MARKET ASSESSMENT
considered uneconomic
for surface mining
operations. Of the
ultimate in-place volume,
about 12 percent or
some 49 billion cubic
metres is estimated to be
ultimately recoverable,
including six billion
cubic metres of bitumen
contained in carbonate
deposits that are
considered to be beyond
economic reach at the
present time.
T A B L E
2 . 1
Crude Bitumen Resources (109m3)
Ultimate
Initial
Ultimate
Initial
Volume
Volume
Recoverable
Established
In Place
in Place
Volume
Reserves
24
18
10
Athabasca
n/a
188.7
Cold Lake
n/a
Peace River
n/a
Subtotal
Total
Cumulative
Remaining
Production
Reserves
5.6
0.4
5.2
n/a
n/a
n/a
n/a
31.9
n/a
n/a
n/a
n/a
20.5
n/a
n/a
n/a
n/a
376
241.2
39
22.7
0.1
22.6
400
259. 2
49
28.3
0.5
27.8
Mineable
Athabasca
In Situ
The estimation of the
T A B L E
2 . 2
initial established
Comparison of World Bitumen Resources (109m3)
reserves of crude
bitumen takes into
Country
In Place Bitumen
Recoverable Bitumen
account current
technology as well as
Canada
259.2
28.3
current and anticipated
Former Soviet Union
186.1
60
economic conditions. It
6.8
0.2
Nigeria1
also involves the
application of certain
4.4
<.01
United States2
reduction factors that
8
n/a
Venezuela3
take into consideration
1 Only includes volumes from the Ondo and Ogun States, with mineable portion only as recoverable.
items such as the
2 Estimate only, small mining volumes for road material are considered recoverable at this time.
required bitumen
3 Does not include heavy or extra heavy crude oil. Source U.S. Geological Survey.
saturation and the degree
of ore inaccessibility
(Appendix A-1). Table 2.1 sets out the bitumen resources and reserves, ordered by recovery method,
for each of the three regions.
Canada’s oil sands are estimated to contain ultimate in-place bitumen resources of 400 billion cubic
metres, making it the world’s largest known concentration of bitumen. The current estimate of the
ultimately recoverable volume represents only 12 percent of the ultimate volume of bitumen in place.
There is considerable potential for this percentage to increase as advances are made in recovery
technology. Although, by definition, proven reserves are not directly comparable to ultimate
recoverable resources, it is interesting to note that the proven reserves of Saudi Arabia, all classified as
conventional crude oil, at about 43 billion cubic metres, are roughly comparable to Canada’s
recoverable bitumen resources.
Canada’s oil sands deposits easily rank as the largest of their kind in the world (Table 2.2). The initial
established reserves, estimated to be 28.3 billion cubic metres, would be sufficient to satisfy domestic
demand for nearly 100 years.
NATIONAL ENERGY BOARD
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F I G U R E
2 . 2
Oil Migration Path
2.3
Oil Genesis, Migration And Biodegradation
The age of the source rocks for the oil found in the Alberta oils sands deposits is still a matter of
some uncertainty. The uncertainty centres on whether the source rocks are Mississippian or Jurassic
age, or some combination of the two. This much is clear: light oil was sourced in the deeper portions
of the Western Canada Sedimentary Basin (WCSB) in pre-Cretaceous formations and migrated long
distances to the present location of the deposits (Figure 2.2). The McMurray or equivalent sands
were the primary collectors of the generated oil and provided the main conduit for migration. It is
speculated that the migration path was at least 360 kilometres for the Athabasca Deposit and at least
80 kilometres for the Peace River deposits. These lighter oils were then subjected to biodegradation
transforming them into bitumen.
Biodegradation occurred where microbes, carried in by oxygenated water, acted on the trapped oil.
This microbial action preferentially decomposed the lighter hydrocarbon molecules, leaving the more
complex heavy molecules, heavy minerals and sulphur behind. As a result, the specific gravity and
sulphur content of the crude oil increases. As well, the concentration of heavy minerals such as
vanadium, nickel, magnetite, gold and silver also increases. It has been estimated that prior to
biodegradation, the original volume of oil in the oil sands was two to three times as large as it is
today. The characteristics of the bitumen and the reservoir properties of the oil sands are in large
part a function of the degree of biodegradation that took place.
2.4
Oil Sands And Bitumen Characteristics
The oil sands deposits are composed primarily of quartz sand, silt and clay, water and bitumen, along
with minor amounts of other minerals, including titanium, zirconium, tourmaline and pyrite.
Although there can be considerable variation, a typical composition would be:
• 75 to 80 percent inorganic material, with this inorganic portion composed 90 percent of
quartz sand;
• 3 to 5 percent water; and,
6
AN ENERGY MARKET ASSESSMENT
• 10 to 12 percent bitumen, with bitumen saturation varying between
zero and 18 percent by
weight.
F I G U R E
2 . 3
The oil sands are generally
unconsolidated, and therefore
quite friable and crumble easily in
the hand.
A key aspect of the oil sand
reservoirs is the presence of bound Schematic diagram showing a structural model of Athabasca oil
sand. The water in the oil sand appears in three forms: as
formation water, which surrounds
pendular rings at grain-to-grain contact points, as a ~ 10 nm
the individual sand grains as a
thick film which covers the sand surfaces, and as water
layer (Figure 2.3). The bitumen is retained in fines clusters. The remaining void is occupied by
trapped within the pore space of
bitumen. Courtesy of AOSTRA.b
the rock itself. This is similar to
most conventional oil reservoirs,
and the reservoir rock is said to be “water-wet”, that is, each sand grain is surrounded by an envelope
or film of water about 10 nanometres thick. The presence of the water layer around the grains
enables the bitumen to be recovered more easily since the bonding forces between the bitumen and
water are much weaker than those between the water and the sand grains.
The bitumen contained in the oil sands is characterized by high densities, very high viscosities, high
metal concentrations and a high ratio of carbon to hydrogen molecules in comparison to conventional
crude oils (Table 2.3). With a density range of 970 to 1 015 kilograms per cubic metre (8-14°API),
and a viscosity at room temperature typically greater than 50 000 centipoise, bitumen is a thick, black,
tar-like substance that pours extremely slowly. The average composition of Alberta’s bitumen is
83.2 percent carbon, 10.4 percent hydrogen, 0.94 percent oxygen, 0.36 percent nitrogen and
4.8 percent sulphur, along with trace amounts of heavy metals such as vanadium, nickel and iron.c
All crude oils contain a complex mixture of hydrocarbons
- chains of carbon and hydrogen atoms. Chains of less
than 4 carbon atoms are gaseous in their natural states,
while longer chain lengths exist as liquids or solids.
Average crude oils contain about 84 percent (by weight)
carbon, 14 percent hydrogen, 1 to 3 percent sulphur
and minor amounts of nitrogen, oxygen, metals and
salts. If the crude oil contains hydrogen sulphide or
reactive sulphur compounds, it is termed to be sour.
Crude oils are classified as paraffinic, naphthenic, or
aromatic depending on which of these hydrocarbon
molecular structures is predominate. Crude oils are
defined in terms of the density or specific gravity. Light
oils have a low specific gravity while heavy oils have a
high specific gravity. When the API gravity terminology
is used, the scale is reversed such that the higher the API
gravity, the lighter the oil. Another property used to
classify crude oils is viscosity, which is a measure of the
ability to flow. Low viscosity oils flow freely, while high
viscosity oils resist flow.
NATIONAL ENERGY BOARD
Bitumen is deficient in hydrogen, compared
to typical crude oils which contain
approximately 14 percent hydrogen.
Therefore, to make it an acceptable feedstock
for conventional refineries, it must be
upgraded through the addition of hydrogen or
the rejection of carbon. In order to transport
bitumen to refineries equipped to process it,
bitumen must first be blended with a diluent,
commonly referred to as condensate, to meet
pipeline specifications for density and
viscosity.
2.5 Reservoir Characteristics
Alberta’s oil sand deposits have been grouped
on the basis of geology, geography and
bitumen content and have been defined as
the Peace River, Athabasca and Cold Lake
7
Oil Sands Areas. The
previously defined
Wabasca Area has been
reclassified by the EUB
and is now included as
part of the Athabasca Oil
Sands Area.
T A B L E
2 . 3
Comparison of Crude Oil Characteristics
Crude Oil
Crude
Sample
Type
Cardium
light
Hibernia
light
Density
API Gravity
Viscosity
(kg/m3)
(degrees)
(cp @ 24oC)
Alberta
834
33
~4
Newfoundland
828 - 896
30 - 40
~10
Location
The characteristics of the
Sparky
heavy
Alberta
959
14
2 600 - 8 900
bitumen and the reservoir
Kern River
heavy
California
964
13
2 985
properties of the oil sands
is in large part a function
Athabasca
bitumen
Alberta
970
11.6
17 000 - 265 000
of the degree of
Alberta
1 040
5.6
125 000 - 155 000
Peace River bitumen
biodegradation that took
place. For the Peace
River deposits, the oil migrated the shortest distance and was subjected to only a moderate degree of
biodegradation, while for the Athabasca and the Cold Lake deposits, the migration distance was
considerably farther and therefore these deposits were subjected to a greater degree of
biodegradation. Some of the distinguishing characteristics of the three areas are:
• the Peace River deposits contain bitumen in Mississippian carbonates, as well as in the
Permian and Cretaceous sandstones;
• the Athabasca deposit has the largest areal extent and contains bitumen in the Devonian
carbonates and the Cretaceous sandstones; and,
• the Cold Lake deposits contain bitumen only in the Cretaceous sandstones.
Table 2.4 summarizes some of the more important characteristics for reservoirs within each of the oil
sands formation types.
2.6
Geology Of The Alberta Oil Sands Regions
2.6.1
Stratigraphy
The oil sands regions of northeastern Alberta have the thinnest portion of sedimentary cover in
Alberta. Between Fort McMurray and Lake Athabasca, the sedimentary section is completely eroded
T A B L E
2 . 4
Reservoir Characteristics
8
Bitumen
Percent
API
Saturation
Bitumen
Gravity
(percent)
(percent)
by Weight
(degrees)
14 - 27
25 - 48
52 - 75
3.5 - 8.0
8 - 23
0.5 - 50
25 - 31
14 - 49
51 - 86
6 - 13
6 - 13
0.2 - 10
23 - 37
14 - 55
45 - 86
5 - 15
10 - 12
Net Pay
Porosity
(metres)
(percent)
Carbonate Deposits
26 000 - 1 190 000
5 - 29
McMurray Oil Sands
20 - 4 239 000
20 - 334 000
Grand Rapids Oil Sands
1
Water
Saturation
Area 1
(hectares)
The deposits are divided into stratigraphic zones and pools, each with its own assigned area.
AN ENERGY MARKET ASSESSMENT
and the granitic rocks of the Precambrian Shield are exposed at
the surface. The thickness of sediments increase rapidly to the
west and southwest.
F I G U R E
2 . 4
The lowermost sediments consist of Middle Devonian Elk Point
Group which may reach a thickness of 350 metres. The Elk
Point Group is made up of Ernestina Lake evaporites,
Chinchaga red beds and evaporites, Keg River dolomites and
limestones, and Muskeg evaporites. The Elk Point is capped by
Upper Devonian deposits which may attain a thickness of
720 metres. The Upper Devonian consists of Slave Point/Fort
Vermillion carbonates and marine shales of the Waterways and
Ireton Formations, capped by dolomitic limestones of the
Grosmont Formation. The Waterways and Ireton Formations
are important source rocks for Devonian pools elsewhere in the
province.
The Devonian section is capped by the much younger
Cretaceous section which can attain a thickness of 925 metres in
the region. The lowermost Cretaceous deposits consist of
McMurray Formation sandstones, capped by interbedded sands
and shales of the Clearwater/ Grand Rapids/ Joli Fou/ Pelican
Formations. The youngest Cretaceous section consists of shales
of the La Biche Formation. The Cretaceous section is capped by
variable thicknesses of recent glacial gravels, sands and clay
deposits.
2.6.2
Structure
The Precambrian erosional surface dips to the southwest at a
rate of 4.5 metres per kilometre in this region of Alberta. On
that erosional surface, there is a basement anticlinal feature
trending north-south which extends through the oil sands
region. As well, outside of the northeastern region, there are large structural arches which interrupt
this surface. In addition, there are several basement shear zones which trend in a northeast-southwest
direction. These may be important in the migration process. The Devonian section generally
follows the same regional structural trend as the erosional surface. Salt tectonics within the Devonian
section emphasize the basement anticlinal feature on the east side. This occurred where the salts
were exposed to surface erosion and were removed preferentially. The Devonian section capping the
Elk Point salts have collapsed along the subcrop edge leaving a carbonate breccia deposit.
The Cretaceous section is relatively flat lying in northeastern Alberta. The thickening Devonian
section fills the space between the flat Cretaceous and the deepening Precambrian erosional surface.
Other carbonate reservoirs are added to the section in the more western portions of the region
including the Nisku Formation. Further westward, the Mississippian and Triassic sections are added.
On the eastern side, over the edge of the salt collapse zone, anticlinal traps may develop within the
Cretaceous section. The anticlinal development forms the structural component of the trapping
mechanism that keeps the oil in the McMurray Formation. Locally, natural gas may be trapped in
the upper portions of the McMurray Formation.
NATIONAL ENERGY BOARD
9
2.6.3
Reservoir Descriptions
In the westernmost part of the Athabasca deposits, the Devonian Nisku and Grosmont carbonates
also contain bitumen deposits, but these are too deep for surface mining techniques. The Nisku
consists of thick dolomitized fossiliferous carbonates. The Grosmont consists of a series of
shallowing upwards depositional cycles with good horizontal continuity but less vertical continuity.
Deposits range from deep water types to shallow water tidal deposits.
In the Peace River Oil Sands Deposit, the carbonate reservoirs are found in the Mississippian Shunda
Formation, while sandstone reservoirs are found in the Permian Belloy Formation and the Cretaceous
Bluesky-Gething Formations, which are equivalent in age to the McMurray Formation. These
sandstones occupy the Peace River Channel, which drained to the northwest, and was a tributary to
the Spirit River Channel found further west. The oil sands deposits are at the updip edge of the
Peace system.
The Lower Cretaceous McMurray sandstones are the main host rocks for the bitumen deposits of the
Athabasca oil sands. The McMurray sands are composed of an interbedded sequence of sandstones,
siltstones, mudstone and coals. Overall, grainsize decreases from bottom to top. The McMurray
sands can be sub-divided into three sub-units: a dark mudstone with minor amounts of coal, a clean
sandstone unit, and a sequence of fine sandstone and siltstone. The mudstone unit is found locally at
the Cretaceous-Devonian boundary and may reflect older units eroded before Cretaceous deposition
occurred. The sandstone unit ranges in grain size from very coarse to very fine, and reflects fluvial
deposits of both meandering and braided stream types. The sand/silt unit is characteristic of
deposition at the junction of river and marine deposits where tidal influences are readily apparent.
The rivers associated with both of these sub-units were north flowing as part of the St. Paul Channel
system, which drained eastern Alberta and western Saskatchewan. The upper unit was deposited as
the Boreal Sea transgressed from north to south. The overlying Clearwater Formation consists of a
silty mudstone which acts as a seal to stratigraphically trap the oil within the McMurray Formation.
The overlying Grand Rapids Formation is primarily a siltstone deposit, but does contain a number of
thick channel sand deposits at a variety of stratigraphic levels. The Grand Rapids Formation
deposition is indicative of an oscillating shoreline, marked by alternating sand and shale deposition
corresponding to the northward retreat or southward advance of the Boreal Sea. Further westward in
the Athabasca deposits, these channel deposits contain significant amounts of bitumen.
2.7
Conclusion
The magnitude of Canada’s bitumen resources, contained in the three Alberta Oil Sands Areas, is
immense. Based on current technology, about 12 percent, or 49 billion cubic metres is estimated to
be ultimately recoverable.
The accepted theory for the formation of the oil sands is that oil in Missippian and Jurassic age
sediments to the southeast migrated to the present day oil sands areas. Subsequent biodegradation
transformed the light oil into a black, tar-like material known as bitumen.
Bitumen is heavy, viscous, and hydrogen deficient compared to conventional crude oils, and is
therefore problematic for conventional refineries. It has to be upgraded locally, or transported to
market after blending with a condensate.
10
AN ENERGY MARKET ASSESSMENT
Oil sands deposits deeper than about 75 metres are considered too deep to be surface mined
economically. Therefore, only 20 percent of the ultimately recoverable volume is considered amenable
to surface mining, while the remaining 80 percent will require some form of in situ recovery.
References
a) Alberta Energy and Utilities Board. Alberta’s Reserves 1999, Vol. 1, Statistical Series
2000-18, 2000.
b) Hepler, L.G. and Hsi, C. (Eds). AOSTRA Technical Handbook on Oil Sands, Bitumens and
Heavy Oils. 1989.
c) McRory, Robert. Energy Heritage: Oil Sands and Heavy Oils of Alberta. Alberta Energy and
Natural Resources. Edmonton, 1982.
Selected Background Literature
Alberta Energy and Utilities Board. Crude Bitumen Reserves Atlas, Statistical Series 96-38, 1996.
Alberta Oil Sands Technology and Research Authority. AOSTRA, A 15 Year Portfolio of Achievement.
1989.
Alberta Oil Sands Technology and Research Authority. Preprints of “Oil Sands - Our Petroleum
Future” Conference, April 4- 7, 1993.
BP Amoco. “Statistical Review of World Energy 2000”, 2000.
Canadian Society of Petroleum Geologists. “Geological Highway Map of Alberta”, 2000.
Energy Information Administration. “Country Analysis - Venezuela” [Internet] www.eia.doe.gov,
2000.
Institute of Petroleum. “Oil and Gas - Energy for the World”, The Chemistry of Oil and Gas
[Internet] www.petroleum.co.uk, 1999.
James, D. P. and T. A. Oliver. “The Sedimentology of the McMurray Formation, East Athabasca”, in
The Canadian Institute of Mining and Metallurgy, 1977, Special Edition, The Oil Sands of CanadaVenezuela, 1977.
Leghornlearning. “What is Refining” [Internet] www.leghornlearning.com, 2000.
Meyer, R. (Ed.). Proceedings of the UNITAR International Conference on Heavy Crude and Tar
Sands, Feb. 12-17, 1995, Houston, Texas, 1996.
Mossup, G. and I. Shetsen (compilers). Geological Atlas of the Western Canada Sedimentary Basin.
Canadian Society of Petroleum Geologists and Alberta Research Council , 1994.
Petróleos de Venezuela. “Orinoco Belt” [Internet] www.pdv.com, 2000.
Solublesolutions. “Tutorial on the Phase Behaviour of Asphaltenes and Heavy Oils” [Internet]
www.solublesolutions.com, 2000.
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3.1
Introduction
The early history of the oil sands is replete with accounts of individuals of courage and conviction
who persevered, often in the face of incredible hardship and disappointment, to pursue their vision
for oil sands development. Among these, two men stood out — Sidney Ells and Karl Clark. In this
chapter, some of the more noteworthy people and events are highlighted.
The story of the oil sands pioneers is truly a fascinating one, and readers are encouraged to seek out
some of the accounts of the history of oil sands development.
3.2
Early Days
The first recorded mention of the Athabasca oil sands is attributed to the English explorer Henry
Kelsey. In 1719, while serving as manager of the Hudson’s Bay Company trading post at York
Factory, Kelsey noted in his journal that a Cree aboriginal named Wa-Pa-Su had given him a sample
“of that Gum or pitch that flows out of the Banks of the River.”a
The North West Company fur trader and explorer Peter Pond is considered to be the first European
to reach the Athabasca region, in 1778. His notes contain reference to the oil sands, as do those of
explorer Alexander Mackenzie, who passed through the region in 1789.
Sir John Richardson visited the region in 1819 as part of Sir John Franklin’s quest to find the
“Northwest Passage”, a shorter route to the Pacific Ocean via Canada’s northland, and returned in
1848 when searching for Franklin’s lost third expedition. Richardson had a knowledge of geology,
and provided the first real scientifically based account of the Athabasca oil sands deposits. He
correctly determined that the oil sands were continuous throughout the region and overlie much
older Devonian limestones.
John Macoun was a botanist assigned to a Geological Survey of Canada (GSC) team with the
responsibility for finding routes for railway construction through the Rocky Mountains. On a return
trip from British Columbia he made his way down the Peace and Athabasca Rivers. It was his
detailed account of the oil sands outcroppings and the nature of the bitumen he found there that led
to further investigation by the GSC. Macoun foresaw a time “when man would be busy, with his ready
instrument, steam, raising the untold wealth which lies buried beneath the surface, and converting the present
desolation into a bustling mart of trade”.b
The GSC initially concentrated its exploration south of Fort McMurray near Athabasca Landing.
Their investigations, led by Dr. Robert Bell, Dr. R.G. McConnell and Dr. George M. Dawson, were
based on the premise that there was a large pool of “pure petroleum” or “free oil” beneath the oil
12
AN ENERGY MARKET ASSESSMENT
sands, trapped by the shale formations they knew existed in the region. A well was drilled at
Athabasca Landing, to a depth of nearly 600 metres, but no oil pool was found. The drilling
equipment was moved to Pelican Rapids where a well was drilled in 1896. No oil was found, but the
well resulted in an uncapped gas well that blew gas for twenty years before it was finally capped in
1918.
In the late 1890s, Dr. Christian Hoffman of the GSC experimented with hot water treatment of the
oil sands in his Ottawa laboratory, and was able to separate bitumen from the sand grains.
Alfred Von Hammerstein was a German count who was lured to North America to join the Klondike
Gold Rush. He passed through the Athabasca region on his way to the Yukon and later returned to
settle near Athabasca Landing. He became increasingly interested in the oil sands and undertook to
drill a number of wells just south of Fort McMurray. Von Hammerstein, like the GSC geologists
before him, was looking for a pool of “free oil” that he thought fed the oil sands. He drilled eight
wells in the area without success, but his investigations did further the cause of development of the
region. On his own initiative, he travelled to Ottawa to deliver a report to a Senate Committee of the
federal government. He presented a glowing, if somewhat exaggerated, account of the mineral wealth
of the Athabasca region, including oil sands, coal, salt, copper, limestone and gold. A central theme
of Von Hammerstein’s report was the usefulness of the oil sands bitumen to produce asphalt.
3.3
Sidney C. Ells
F I G U R E
3 . 1
S.C. Ells (Northland Trails by S.C.
Ells, Burns and MacEachern,
Toronto, 1956)
The following statement was made in 1950 by
Max Ball, a long time friend and associate of Ells.
"S.C. Ells may well be called the father of the
Alberta bituminous sand research and development.
He made the first systematic study of the deposits
and the first — and as yet the only —
comprehensive maps of the area in which they lie.
He made the first systematic study of methods for
separating the bitumen from the sands. He first
developed and demonstrated the principal of hot
water separation through pulping the bituminous
sands and recovering the separated bitumen in a
flotation cell. For thirty-five years, in the face of
indifference and skepticism, he has been the courageous and unremitting advocate of the value and
importance of the bituminous sand deposits".c
The federal government’s involvement with the Athabasca oil sands was renewed in 1913. In a letter
to the government in Ottawa, an Alberta MLA, Jean L. Côté, asked about its plans for the
development of the northern Alberta oil potential. In attempting to answer his queries, the federal
Department of Mines realized the lack of detailed information there was on the Athabasca deposits.
The team from the Mines Branch that was formed to conduct further investigation included Dr.
Sidney C. Ells, a young engineer.
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Over the next forty years, Ells was one of the major driving forces leading the efforts to characterise
and develop the oil sands.
Ells’ report at the end of the 1913 field season concluded that there was no pool of “free oil” below
the oil sands, rather, the oil was dispersed throughout a particular sand layer. He also concluded that
the sand held immense quantities of bitumen that could not be recovered by traditional drilling and
pumping methods. Ells, who had some background in evaluating materials for road construction, also
urged that the oil sands bitumen be utilized as a source of asphalt. In addition, he recommended that
techniques be developed to separate the oil from the sand. On his advice, the National Parks Branch
created the Horse River Reserve, setting aside 232 hectares of land just south of Fort McMurray for
the purposes of oil sands research.
Early attempts to demonstrate the possible commercial use of the oil sands as a paving material
included:
• a 60 square metre section of demonstration pavement at Kinnaird Street in Edmonton, that
was laid in 1915 and was in service until the 1950s;
• paving trials on Wellington Street and Parliament Hill in Ottawa, Ontario;
• a Parks Branch plan to use oil sands to pave the streets of Jasper that was completed in
1927;
• a bridge paving project in Medicine Hat in 1935, by D. M. Draper of Fort McMurray; and
• the paving of 22 blocks of sidewalk in Camrose, Alberta.
Although the oil sand performed well in paving applications, as sheet pavement or when mixed with
other aggregates, the high cost of transporting the material from the north made the economics
marginal. As well, developers began to realize that oil sands would have far greater potential value as
a source of transportation fuels, and interest in using oil sands as paving material waned.
The completion of the Northern Alberta Railway line to the Fort McMurray area in 1920s made it
much easier to move people and equipment into the region, and the stories of the potential wealth of
the oil sands attracted many inventors and promoters. Ells believed that the oil sands entrepreneurs
were necessary to develop the resource and on his recommendation the federal government adopted a
policy of supporting private sector investment in the oil sands. He also urged the federal government
to invest. In 1925, the Canadian government initiated a core-drilling program, designed to recover
samples, that would be subsequently shipped to Mines Branch laboratories in Ottawa for further
analysis. In 1926, Ells listed 41 wells drilled in the area, mostly within the Horse River Reserve,
including two by the Alberta government.
Ells was aware that hot water separation techniques had been tried in Europe and in the United
States where deposits of oil sands also occur. In 1913, after visiting several sites in the United States,
he determined that a separation plant located in Carpinteria, California had processed a material
similar to the Athabasca oil sands and held the most promise. In 1915, Ells was invited to conduct his
research on hot water separation at the Mellon Institute of Industrial Research in Pittsburgh,
Pennsylvania. At Mellon, Ells experimented with his separation process by varying temperatures and
pressures and testing the effects of various acids and alkalis. Based on the success of his experiments,
Ells was assured that the hot water separation process could be successfully applied to the Athabasca
oil sands.
At this point in his career he turned his attention once again to the characterisation of the oil sands
deposits and the promotion of oil sands development. In 1930, the provinces were given full control
14
AN ENERGY MARKET ASSESSMENT
over natural resources, but the federal government did retain several leases around Fort McMurray.
Ells continued to promote research and development in the area and his efforts led to renewed
exploratory work by the GSC in the 1940s and early 1950s. After his retirement in 1954, Ells
devoted his time to writing and sketching. He was able to attend the First Oil Sands Symposium in
Edmonton in 1951 and was present at the Great Canadian Oil Sands opening ceremonies in 1967.
Sidney Ells died in Victoria in 1975.
There many a trail winds away to the northward,
Through the swamp and muskeg and bottom land wide,
But the trail that once carried the wealth of the northland,
Was the tracker’s trail by the riverside. — S.C. Ells.
This sketch done by Sidney Ells shows a 50-foot river scow, loaded with
sacks of oil sand, being pulled upstream on the Athabasca River by a team
of “trackers”. This arduous form of labour was a common means of transporting goods south from Fort McMurray to Athabasca Landing, a distance of
280 kilometres, until the railway was completed to the Fort McMurray area
in the 1920s.
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Chronology
1719
1778
Sample of bituminous sands brought to York Factory
by Wa-pa-su, ‘the Swan’, a Cree Aboriginal from the
Athabasca Country.
Peter Pond is the first white man to enter the
Athabasca Country, crossing the Methye Portage to
the Clearwater River, and continuing down the
Athabasca to build a fort at a point some thirty miles
from the mouth of the river. Describes seeing the oil
sands.
1791
Peter Fidler, Surveyor for the Hudson’s Bay Company
(HBC) records seeing the oil sands.
1792
Alexander Mackenzie travels the same route to the
Athabasca country as did Pond, and reports seeing
the oil sands.
1820
John Richardson gives earliest geological interpretation of the oil sands deposits.
1848
On a searching expedition seeking the fate of
Franklin, Richardson adds to his knowledge of the oil
sands.
1870
Henry John Moberly, HBC factor builds a trading
post at the forks of the Clearwater and the
Athabasca, naming it Fort McMurray for the HBC
inspector who sent him to build the post.
1875
John Macoun, Botanist with a Dominion Government
group investigating the West describes the oil sands.
1878
In his annual report, G.M. Dawson, Director of the
GSC makes the first technical reference to the oil
sands.
1882
Dr. Robert Bell of the GSC describes gas bubbles in
river and explains geological sequence.
1883
First attempt at laboratory separation of oil from
sand, in Ottawa by Dr. G.C. Hoffman.
1893
Dr. R. D. McConnell, GSC, makes more detailed
structural observations.
1894
Government well sunk at Athabasca Landing by Dr.
McConnell. Well abandoned in 1895.
1896
Government well sunk at Pelican Rapids, encountered
natural gas flow which blew for 20 years.
1897
Klondike Gold Rush brings many people through the
Athabasca region.
1906
A. Von Hammerstein drills a well on the Athabasca
River.
1907
A. Von Hammerstein describes the Athabasca region
to a senate investigating committee, with emphasis
on the oil sands deposits.
1914
Shift in thinking of oil sands: suggestion that material
found may be as valuable as oil field sought
beneath.
1915
First pavement laid using Athabasca oil sands - in
Edmonton, Alberta.
1917
Dr. F.H. McLearn (GSC) names oil sand strata Fort
McMurray Formation
1918
Northwest Company Ltd. (a subsidiary of Imperial Oil
Co. Ltd.) drilled in Tp 85.
1920
Ottawa stops leasing land in Athabasca region.
1921
The Alcan Oil Company, formed of New York City
Policemen drilled for oil in township 96.
1925
Dominion Government begins to take core samples of
oil sand. Dr. Clark studies area for Alberta.
J.O. Absher forms the Bituminous Sand Extraction
Company and begins in situ experiments.
1926
Railway completed to Fort McMurray.
1927
International Bitumen Company formed by R.C.
Fitzsimmons.
1930
Abasand Oils begins operation under Max Ball’s
direction.
All Canadian natural resources are brought under
provincial jurisdiction. R.C. Fitzsimmons makes first
shipment of commercially saleable bitumen, to
Edmonton.
1943
Oil Sands Limited takes control of Fitzsimmons’ plant
at Bitumount.
1947
Discovery of huge conventional crude oil reservoir at
Leduc, Alberta.
1948
Dr. D.S. Montgomery joins Federal Bureau of Mines.
Begins work on chemical structure of bitumen.
1949
Province of Alberta takes over Bitumount site as Oil
Sands Project.
1951
Province of Alberta holds first Athabasca Oil Sands
Conference.
1953
Sun Oil Company, led by J. Howard Pew, forms
Great Canadian Oil Sands Company to pursue oil
sands development.
1955
Bitumount area taken over by Can-Amera Company.
1958
First plan to separate sands with nuclear explosion
proposed.
1958
New flurry of interest in 1911 gold.
1962
Great Canadian Oil Sands granted first production
permit in oil sands by Alberta government.
1909
Von Hammerstein encounters brine in his well.
Interest in salt mining.
1963
Sun Oil Company decided to back separation plant
for Great Canadian Oil Sands Company.
1911
Gold encountered in drilling.
1967
1913
Ottawa sends Sidney Ells to investigate extent and
use of oil sands.
Great Canadian Oil Sands plant begins production
of crude oil.
1974
Province of Alberta grants second production permit
to Syncrude, a consortium of oil companies.
16
AN ENERGY MARKET ASSESSMENT
3.4
Dr. Karl A. Clark
F I G U R E
3 . 2
The simple term "Oil Sands Scientist" perhaps best
describes Karl Clark. In 1920, President Tory of
the University of Alberta gave him the task "to find
a way of bringing the Athabasca tar sands into
utilization." Through a lifetime of dedication and
disciplined research he was able to fulfill this
commitment. He is widely recognized as the
developer of the hot water bitumen extraction
process which formed the basis of the process
utilized by the two large mining/upgrading plants
in operation at Fort McMurray.
Karl A. Clark, 1918. (CFC)
After receiving his doctorate in Physical Chemistry from the University of Illinois in 1916, Karl
Clark’s first assignment was with the Geological Survey of Canada. Due to a reorganization in his
department, he was transferred to the Road Material Division of the Mines Branch, in Ottawa, where
he was asked to organize and critique the reports of Sidney Ells. Through this work, he developed a
good understanding of the Athabasca oil sands.
During a visit to Manitoba in the summer of 1918, Clark noted that the clay soils of the prairies make
the roads almost impassable in wet weather. Clark thought that the Athabasca tar sands might be
used to waterproof these roads.d
In 1920, he received samples of the oil sands to study and, in the course of his work, developed a
method of separating the oil from the sand using a chemical additive.
At this time, the University of Alberta decided to set up and finance its own facilities to conduct oil
sands research. Clark was recruited to the post of research professor in the newly formed Scientific
and Industrial Research Council of Alberta, which later became the Alberta Research Council.
By the fall of 1922, Clark had concluded that the use of Athabasca oil sands for paving purposes was
not economically viable, and he turned his attention to developing his oil sands separation techniques.
Clark developed a method by which a froth of oil was formed by introducing additional hot water
into the original mixture of oil sands pulp and hot water. The froth, containing the oil, could be
skimmed off the surface, while the sand grains sank to the bottom of the container.
Sydney M. Blair, a young engineer, joined Clark as his assistant in 1922. They set about designing
and building the first oil sands separation plant capable of batch operation. This apparatus, located in
the basement of the University of Alberta’s power plant building, worked very well and led to the
construction of a larger plant located on the outskirts of Edmonton at the Dunvegan Yards. The
Dunvegan plant of 1925 was the first continuous separation plant for oil sands ever built and
operated. Clark and Blair also spent time in the fields surveying and sampling the deposits along the
Athabasca River. In 1926 they released a major report on their work entitled “The Bituminous Sands
of Alberta.”
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In 1929, the Alberta Government and the Alberta Research Council asked Dr. Clark to identify a site
suitable for a mining plant and to build a pilot plant beside a quarry. The Dunvegan plant was
modified, tested, dismantled and shipped by train and barge to a site on the Clearwater River. The
Clearwater plant was in operation throughout the summer of 1930 and produced 60 000 litres of oil.
Clark was pleased with the plant performance and reported that 90 percent of the oil in the sand was
being recovered and that the mineral content of the froth was down to 4.9 percent, both better than
laboratory studies had indicated.e
Dr. D. S. Pasternack, who had just finished his doctorate in organic chemistry at McGill University,
was hired to assist Clark with the problem of dehydrating the wet oil produced by the plant, which
contained entrained water of about 30 percent. The answer they found was to mix the bitumen with
salt in a steam-jacketed mixing and kneading machine, with the temperature precisely controlled.
Using this method, they were able to reduce the total water and mineral content to less than two
percent.f
As a result of the cost cutting made necessary by the Depression, the Research Council of Alberta was
disbanded in 1933, and Dr. Clark’s focus turned more to soil surveys and soil classification.
World War II brought a renewed interest in petroleum resources and the Research Council was
reinstated in 1942.
In 1944, Clark determined that oil sand in its natural state was “water-wet”, that is, each sand particle
is separated from the oil by an envelope of water. He also established that this condition was
necessary for separation of the oil from the sand to occur. In addition, he established that the fine
clays had to be present in the proper concentration to achieve effective separation results.
After 1945, Clark served as advisor to a group building a pilot plant at Bitumount and also advised in
its subsequent operation.
Clark remained at the University of Alberta until his retirement in 1954, but continued on with the
Alberta Research Council until 1963. During this time, his advice was widely sought by researchers
and industry personnel alike. Dr. Karl A. Clark passed away in December 1966.
3.5
Early Projects
3.5.1
Bitumount
Encouraged by a favourable leasing policy on the part of the federal government, many people came
to the Athabasca region to make their fortune in the oil sands.
In 1922, a group of New York City policemen formed the Alcan Oil Company and acquired a lease
north of Fort McMurray on the east side of the Athabasca River. Their plan was to inject hot water
down a well to heat the oil sands from which bitumen would then be extracted. Unfortunately, their
plan failed and they sold their rights to Robert Fitzsimmons in 1923.
Fitzsimmons turned his attention to mining and extraction rather than pursuing down hole recovery.
In the course of his experiments, he constructed a small extraction plant based on hot water
separation. This plant became the first field plant to extract oil from the Athabasca oil sands. At this
site, which came to be known as Bitumount, Fitzsimmons established the International Bitumen
Company in 1927 (Figure 3.3). Over the following years, he continued to perfect his process. In
1938, the plant produced 400 cubic metres of specification asphalt and 320 cubic metres of fuel oil.g
18
AN ENERGY MARKET ASSESSMENT
F I G U R E
3 . 3
Early Projects
F ir
Bitumount
eb a
g River
Fort MacKay
er
Ell
s R iv
Abasand
r
ve
asca R i
a tb
r
Ath
rse R i v e
Ho
n e River
Alberta
Fort McMurray
Clearwater
ngings
Ha
to
r
ive
ay R
K
M ac
a
habas c
At
er
Ri v
Mildred Lake
Fitzsimmons’ operation faced increasing financial difficulties, and he lost control of the plant in 1942.
The Alberta government operated it as an experimental facility for several years before it was shut
down in 1949.
3.5.2
Abasand
Abasand Oils Limited was formed in 1931, by an American named Max Ball, on a lease in the Horse
River Reserve. Abasand had an agreement with the federal and provincial governments to have an
operational plant in place by 1936 that could process 250 tons of oil sands per day.
The plant was completed on schedule and was close to being commercially successful when it was
completely destroyed by fire in 1941. Ball rebuilt the plant but it did not regain the level of success it
had before the fire and he decided to abandon the operation in 1942.
The federal government, concerned about securing adequate supplies of crude oil for the war effort,
had renewed interest in the potential of the Athabasca oil sands. They took over the Abasand plant in
1943, but were never able to achieve any degree of success. In 1945, fire again completely destroyed
the plant, marking the end for Abasand.
In 1947, a huge conventional light crude oil reservoir was discovered at Leduc, Alberta, with the
discovery of other large pools following close behind. This deflected interest away from the oil sands,
but the infrastructure put in place to exploit these conventional resources would later enable oil sands
development.
3.5.3
Blair Report
The Blair report, which was released in 1950, was prepared for the Alberta government by S.M. Blair
and E. Nelson, and indicated that oil sand development would be economically feasible if done on a
scale of 3 200 cubic metres per day or greater. This report, along with an oil sands symposium that
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19
was held in Edmonton in 1951, sparked renewed industry interest. A dozen oil companies pursued
exploration targets of 20 230 hectares each, to be explored over the following three years.
The regulations allowed companies to acquire leases if they found something of interest, but the
leases carried a requirement to begin building a commercial plant within one year of obtaining the
lease. Few companies were willing to take this risk, so the province changed the rules such that a
lease holder was only required to proceed with a commercial plant within one year if instructed to do
so by the government. This change in regulation encouraged many companies to acquire oil sands
leases and helped set the stage for the first commercial projects.
3.5.4
First Commercial Mining Projects
Under the leadership of J. Howard Pew, Sun Oil Company did extensive investigation of their oil
sands leases, beginning in the early 1950s, and undertook to build the first surface mining and
upgrading plant. The Great Canadian Oil Sands (GCOS), now Suncor, operation began in 1967.
The lessons learned from its construction and from solving early operational problems paved the way
for the modern oil sand industry.
The Syncrude project, a consortium of companies that had been actively involved in oil sands
exploration for a number of years, including involvement in the Abasand and Bitumount projects,
proposed the development of a second, larger mining and upgrading plant in the early 1970s.
Concerns about high construction costs and volatile oil prices caused the project sponsors to
reconsider their plans. Financial participation by the federal and provincial governments, and an
exemption from the federal oil price controls then in place, allowed the project to proceed. Syncrude
began producing upgraded crude oil in 1978.
Two other mining proposals put forward in the late 1970s and early 1980s, the Alsands and the Other
Six Leases Owners (OSLO) projects were cancelled because they were deemed to be uneconomic.
3.5.5
First Commercial In Situ Projects
Although there were many early attempts at in situ recovery, among the most colorful and persistent
of its proponents was J. O. Absher. In spite of personal injury and financial hardship, Absher pursued
his ideas for more than a decade in the 1920s and 1930s. He drilled wells and set up apparatus to
inject steam downhole and pump out the heated bitumen. Although he was able to produce very
small quantities of bitumen, his plans lacked the technical sophistication to be successful.
The first large-scale in situ project was developed by Imperial Oil Limited at Cold Lake, which
started operation in 1978. The Shell Canada Limited project at Peace River began commercial
operations in the early 1980s. Both projects involve a form of steam injection that heats the bitumen
downhole and enables it to flow and be pumped to the surface.
3.6
Conclusion
The early days of oil sands exploration and development are replete with stories of men of courage
and dedication who endured hardship and disappointment to follow their vision.
The first holes were drilled in search of “free oil” thought to feed the oil sands, but this idea was soon
disproven. Although many saw value in the oil sands as a road-paving material, transporting the oil
sand from such a remote location was not economically feasible. As the need for transportation fuels
increased, efforts to realize the oil sands value as a petroleum resource accelerated.
20
AN ENERGY MARKET ASSESSMENT
Sidney Ells was a federal civil servant who is largely responsible for the early exploration and
delineation of the oil sands deposits. He saw the promise in the oil sands and was a tireless champion
of its development.
Dr. Karl Clark represented the provincial government through the Alberta Research Council, and his
genius and dedicated work led to the perfection of the hot water extraction process that provides the
basis for the extraction process used by the integrated mining plants at Fort McMurray.
The Blair Report, released in 1950, indicated that the oil sands mining and bitumen extraction would be
economically feasible. This, plus a more favourable provincial leasing policy, encouraged industry to
pursue oil sands opportunities. This paved the way for commencement of the first integrated oil sands
mining/upgrading operation in 1967, by GCOS, and a subsequent plant operated by Syncrude, which
started in 1978. By the same token, industry was also encouraged to pursue in situ research and
development activities. In the 1960s and 1970s, there were many pilot projects, testing various recovery
methods. The first commercial in situ recovery project was started by Imperial Oil at Cold Lake in 1978.
References
a) Fitzgerald, J.J. Black Gold with Grit. Gray’s Publishing Ltd., 1978.
b) Ibid.
c) Ibid.
d) Sheppard, Mary Clark. Oil Sands Scientist - The Letters of Karl A. Clark 1920-1949, The
University of Alberta Press, 1989.
e) Ibid.
f) Ibid.
g) Alberta Natural Resources. Oil Sands and Heavy Oils of Alberta, 1982.
Selected Background Literature
Comfort, Darlene J. and Peter G.Duffy. The Abasand Fiasco, Friesen Printers, 1980.
Ignatieff, A. A Canadian Research Heritage - An Historical Account of 75 Years of Federal Government
Research and Development in Minerals, Metals and Fuels at the Mines Branch, Minister of Supply and
Services Canada, 1981.
Pratt, Larry. The Tar Sands-Syncrude and the Politics of Oil, Hurtig Publishers, Edmonton, 1976.
Picture Credits
Ignatieff, A. A Canadian Research Heritage - An Historical Account of 75 Years of Federal Government
Research and Development in Minerals, Metals and Fuels at the Mines Branch, Minister of Supply and
Services Canada, 1981, page 37. Originally from Northland Trails by S.C. Ells, Burns and
MacEachern, Toronto, 1956.
Ells, S.C. Athabasca Trails, Canadian Geotechnical Journal, June 1939.
Sheppard, Mary Clark. Oil Sands Scientist - The Letters of Karl A. Clark 1920-1949. The University of
Alberta Press, 1989, page 9. Originally from Clark Family Collection.
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21
C
H
A
A REVIEW
4.1
P
T
E
R
F
O
U
R
OF
OIL SANDS TECHNOLOGY
Introduction
The evolution of the Canadian oil sands industry from the first primitive attempts at bitumen
extraction to today’s dynamic, large-scale, commercially successful operations is a story of remarkable
achievement. Through scientific research and technological innovation, a dynamic industry with a
wide-ranging support infrastructure has been created that has made Canada the world leader in oil
sands development. This success story is due in large part to the vision of the individuals and
organizations that steered the research efforts and technological development, and the many
dedicated scientists, engineers, technologists, inventors and tradespeople that carried it out.
This chapter presents a brief description of the methods or processes used in the integrated
mining/upgrading operations, in the in situ operations and in primary bitumen production. The
major technological innovations are identified. Many of the advances in the technology and processes
employed were as a result of continuous improvement and were incremental in nature; however, there
were some important "step-changes" that occurred as well. Most of these step-changes involved
important innovations that were put into practice in the 1990s. It is convenient to describe the
changing technology in terms of "old" versus "new".
In addition, a brief discussion of the current areas of research is provided to highlight the important
role of science and technology in advancing the oil sands industry.
4.2
Integrated Mining/Upgrading Plants
4.2.1
Mining
Before the oil sands can be mined, the water-laden muskeg that overlies much of the area must be
drained, and the layers of muskeg, surface vegetation and tree cover removed. Any suitable soil materials
are selectively excavated and used in the ongoing reclamation program. The overburden beneath the
muskeg consists of a mixture of rock, clay and barren sand and is removed by trucks and shovels and
placed in previously mined-out areas. The removal of the overburden exposes the deposit of oil sands.
The oil sands are typically 40 to 60 metres thick and sit on top of relatively flat limestone beds.
The initial mining system that was developed for the GCOS operation was patterned after methods
being used in other parts of the world. Two giant bucketwheel excavators were imported from
Germany. Especially designed for this project, these machines stood 30 metres high, had a 10 metre
diameter bucketwheel attached to a 64 metre long boom and were able to dig out 91 000 tonnes of oil
sands daily.1 The bucketwheels discharged their load on to conveyor belts which transported the oil
1 One cubic metre (m3) of crude bitumen is approximately equal to 6.3 barrels or one metric tonne.
22
AN ENERGY MARKET ASSESSMENT
sands material to a dump pocket
near the extraction and upgrading
facilities. The series of conveyor
belts were typically a kilometre or
more in total length. The
Syncrude operation, which
commenced in 1978, was based on
the same system, except huge
draglines were used to remove
material from the mine face and
place it in windrows from which
bucketwheel reclaimers loaded it
on to conveyor belts. Over the
years, continuous improvement in
the mining processes took place,
including the development of
larger capacity bucketwheels,
draglines, trucks and power
shovels.
F I G U R E
4 . 1
The massive, complex equipment was difficult and costly to redeploy in the mine (Figure 4.1). In
addition, it was vulnerable to interruption of service, especially during cold winter months, due to the
potential bottlenecks and many moving parts.
The use of large mining trucks and power shovels in the mining operations became more prevalent as
their capacity increased. By the early 1990s, Syncrude was moving about one-third of its ore via this
method, and Suncor converted to truck and shovel in 1993. The truck and shovel method is
considerably more flexible and less prone to interruption of service. Today, the oil sands ore is
commonly moved to the dump pits by trucks capable of hauling 360 tons that are loaded by power
shovels with 58 cubic yard capacity buckets.
As well, the dump pocket has been modified to include a feeder/crusher system in which the oil sands
are fed through a double roll crusher.
In the 1980s, the Other Six Lease Owners (OSLO) consortium patented the OSLO Cold Water
Extraction process that included the transporting of a water/oilsands slurry via pipeline to an
extraction plant. Based on this system, Syncrude developed a hydrotransport process in the early
1990s that provides a much cheaper and more flexible method to transport oil sands compared to the
old system of long conveyors.
The first step in this process features an important new innovation, the cyclofeeder, a massive vessel
nearly 35 metres tall. In the cyclofeeder, the oil sands are crushed and mixed with hot water to form
a slurry which is then fed at high speeds into a pipeline and transported to an extraction plant, which
could be many kilometres away. The benefits of this system include:
• the break down of large lumps of oil sands in the ore and some separation of bitumen from
oil sands as the slurry moves through the pipeline;
• much more flexibility, because pipelines can follow circuitous routing and be placed on
uneven terrain; and,
• low energy extraction — because of separation during hydrotransport, operating temperatures can be reduced to 50°C, or less.
NATIONAL ENERGY BOARD
23
A recent innovation by Syncrude,
called "Natural Froth Lubricity",
uses water in the froth to create a
lubricating sleeve, thereby allowing
the pipelining of froth without
adding diluent.
F I G U R E
4 . 2
The hydrotransport system has
been adopted by Suncor, and is
planned for the Athabasca Oil
Sands Project being constructed by
Shell Canada Ltd. (Shell) and
partners. Compared to the old
conveyor method, this system
allows mining to be carried out at
much greater distances from the
extraction plant. It is expected that
by 2005 all of mined oil sands in
Alberta will be transported using
hydrotransport technology.
The efficiencies gained in mining
operations by converting to truck
and shovel, and the development of
the hydrotransport system are the principal reason operating costs have been reduced by about
50 percent in the last decade. Operating costs are currently in the $11 to $14 per barrel range, with a
target of $10 or less before 2005.
4.2.2
Extraction
The bitumen extraction processes initially used by GCOS and Syncrude were based on the Hot
Water Extraction Method perfected by Dr. Karl Clark at the Alberta Research Council (Figure 4.2).
Oil sand ore is moved from the base mine dump pocket by conveyor and enters large rotating
tumblers where the ore is slurried by steam, hot water (85°C) and caustic soda to condition it for
bitumen separation. The aerated slurry from the tumblers discharges onto vibrating screens where
large materials such as rocks and lumps of clay are rejected. The slurry is diluted in pump boxes and
pumped to the Primary Separation Vessels (PSV), where bitumen rises to the surface as a froth and is
skimmed off, while the sand settles to the bottom. The froth is moved to a flotation unit in which
air-bitumen bubbles rise to the surface. Froth treatment is required to minimize the amount of water
and solids going to the upgrader, so at this point naphtha is added as a diluent and the mixture enters
a high speed centrifuge to complete the cleaning or separation. The diluted bitumen is moved to the
upgrading unit while the sand and other material that settles during the separation process are
removed as "tailings slurry".
New innovations include (Figure 4.2):
• the addition of the Tailings Oil Recovery (TOR) vessels — a technology developed by
Syncrude, these deep cone vessels recover most of the remaining bitumen that was
discharged from the PSV as part of the tailings in the old method;
• a secondary flotation unit to receive froth from the TOR;
24
AN ENERGY MARKET ASSESSMENT
• inclined plate settlers (IPS), developed by Suncor, and disc centrifuges, designed to provide
more complete separation; and,
• a Diluent Recovery Unit (DRU), developed by Syncrude to recover naphtha from all froth
treatment tailings.
Today’s extraction processes are able to extract about 91 percent of the bitumen contained in the oil
sands, compared to about 84 percent in 1975. The energy savings derived from the low energy
extraction process also contribute significantly to lowering operating costs.
The Athabasca Oil Sands Project, planned by Shell and partners for startup in early 2002, includes a
major innovative feature. The "multi-stage counter-current decantation" process provides partial
upgrading in the field. In this process the extracted bitumen is blended with a paraffinic solvent
which promotes the precipitation of asphaltenes, and thereby removes most of the carbon-laden or
coke-producing components in the mixture. This fits with the project’s plans, in that the associated
Scotford Upgrader at Shell’s refinery is based on hydrogen-addition technology and, therefore, will
not require a coking unit.
4.2.3
Tailings Disposal
The tailings produced as a result of the extraction process consist of a mixture of water, sand and fine
clay particles. The traditional method to deal with tailings has been to pump them into large holding
ponds with reclamation to occur after the tailings slurry solidifies. However, the microscopic sized
clay particles could stay in suspension for hundreds of years before settling out.
Suncor, in association with the Consolidated Tailings Consortium, has developed a new technology
called consolidated tailings (CT) which uses gypsum, produced as a by-product from its flue gas
desulphurization unit, to greatly accelerate the transformation of tailings into solid material. Other
mining operations have adopted the same technology. With CT, reclamation of the tailings ponds is
expected to take 10 years or less. Further discussion of tailings can be found in Chapter 9,
Section 3.1.
4.2.4
Upgrading
During the upgrading process the bitumen is converted from a viscous, tar-like oil that is deficient in
hydrogen and high in sulphur and heavy metals, to a high quality "synthetic" or "upgraded" crude oil
that has density and viscosity characteristics similar to conventional light sweet crude oil, but with a
very low sulphur content (0.1- 0.2 percent). This upgrading is achieved through a process of coking,
desulphurization and hydrogen addition.
The first step in upgrading is recovery of naphtha, which is removed and recycled back to the
extraction plant. The bitumen is then heated in furnaces and sent to a vacuum unit where some of
the product is removed. The remaining bitumen is forwarded to cokers where high temperatures in
the coker’s reactors cause the long bitumen molecules to thermally crack. Most of the bitumen
vapourizes into gases, but the heavy bottom carbon-rich material forms coke. Suncor uses a delayedcoking technology while Syncrude uses a somewhat different process called fluid-coking. Coke is
used as a fuel source for the coker burners as well as for other heat requirements. The excess coke is
stockpiled or sold for use in ammonia plants or other industrial applications.
The remaining hydrocarbon vapours are sent to fractionators where they are separated into naphtha,
kerosene and gas oil. Within the hydrotreater units the hydrocarbon vapours react with hydrogen at
high pressure and high temperatures in the presence of a catalyst. This process is used to stabilize the
NATIONAL ENERGY BOARD
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product stream as well as to remove sulphur and nitrogen. The product streams of naphtha and gas
oils from the hydrotreaters are blended to make a high grade crude oil. The sulphur is converted to
elemental sulphur and stored on site or shipped to market, while the nitrogen is removed as ammonia
and generally used as a fuel in the utilities plant. Fuel gas, produced as a by-product of the refining
process, is sweetened and then sent to amine units for hydrogen sulphide removal. The resulting
sweet gas is used throughout the plant as an energy source.
Major new innovations in upgrading include:
• the LC-Finer hydroprocessor, which breaks down bitumen through hydrogen addition
over an ebullated catalyst bed to produce a cracked light gas oil; and,
• the installation of a vacuum distillation unit (VDU) to remove volatile material from the
bitumen before it enters the cokers, thus eliminating the cokers as a process bottleneck.
4.3
In Situ Recovery
For oil sands reservoirs too deep to support economic surface-mining operations, some form of in
situ recovery is required to recover the bitumen. The EUB attributes about 80 percent of the total
bitumen ultimately recoverable from Alberta’s oil sands, or some 39 billion cubic metres, to in situ
recovery methods. This represents a target with huge potential.
In general, the heavy, viscous nature of the bitumen (8-10° API, 10 000 - 300 000cp) within the subsurface deposits means that it will not flow under virgin temperature and pressure conditions. Thus,
thermal energy must be applied to heat the bitumen sufficiently to allow it to flow to a well bore and
be produced. Alternatively, dilution with a solvent can also induce the bitumen to flow. As an
exception to this general rule, there are reservoirs in the Wabasca area and in the southern part of the
Cold Lake area where the oil is sufficiently fluid to allow primary or "cold" production.
From the early 1900s there have been many attempts at in situ recovery, but most were primitive in
design and only very small amounts of bitumen were produced. It was not until the 1950s that
improved technology allowed in situ development to move forward.
A wide variety of recovery methods have been tested, either alone or in combination with other
methods. These include stimulation by various means, such as: steam injection; in situ combustion;
the application of ultrasound, microwave, and electromagnetic energy; and, the injection of water,
polymers, alkalines and solvents. As an indication of the activity level, the EUB lists 340 projects,
beginning in 1959, for which some type of experimental recovery test was approved.a Today, there
are some 22 active in situ bitumen projects situated in all three oil sands areas, consisting of
11 commercial projects and 11 experimental projects, with most of these employing some form of
steam stimulation.
4.3.1
Cyclic Steam Stimulation
The cyclic steam stimulation (CSS) system was developed by Imperial Oil Ltd. at Cold Lake.
Exploratory drilling between 1958 and 1962 led to the establishment of the Ethel pilot project in
1964. Several recovery schemes were tested including cyclic steam injection and in situ combustion.
By 1975, through the operation of the Ethel pilot and a new pilot, called May, Imperial had
demonstrated the technical feasibility of CSS at Cold Lake.b A third pilot plant at Lemming provided
the basis for moving to commercialization with CSS technology in 1985.
26
AN ENERGY MARKET ASSESSMENT
Innovations at the time included recycling of
produced water and the pad drilling concept —
drilling 20 wells from one pad became the standard.
The CSS or "huff and puff" system (Figure 4.3) is
based on producing steam in large boilers and
injecting it down the well bore into the target
formation at a temperature of about 300ºC and
pressures averaging 11 000 kilopascals. This level of
pressure is sufficient to fracture the formation rock
creating a path for fluid flow. For each individual
well, periods of steaming are followed by periods of
soaking and then by periods of production. When
production rates decline, another cycle of steam
injection begins. Cycle times are typically six to
eighteen months. It is expected recovery factors of
about 20 to 25 percent will be achieved with CSS.
F I G U R E
4 . 3
Cyclic Steam Stimulation
Courtesy of Imperial Oil Ltd.
At the end of 1999, Imperial was operating about
3 000 wells at Cold Lake, with production of nearly 21 000 m3/d. Although CSS has proven to be
very successful for Imperial at Cold Lake, it has not been widely applied elsewhere.
4.3.2
Pressure Cycle Steam Drive
In the 1960s, Shell began experimental work on its Peace River leases with three small pilot projects.
A 1973-1974 test achieved high steam injection rates without fracturing, and with excellent production
response.c In partnership with the Alberta Oilsands Technical Research Authority (AOSTRA) in 1979
the pressure cycle steam drive system was developed. This process takes advantage of a basal water
zone, which underlies the oil sands in this area, to heat the oil sands deposit from below. Once a hot
communication path is established between wells, continuous steam injection is begun, with the
injection and production rates controlled to alternately pressure up and blow down the reservoir.d
Shell proceeded to commercial operation with the Peace River Expansion Project in 1986. Although a
technical success, in the 1990s this project evolved into a combination of SAGD development and
multilateral wells employing steam injection.
4.3.3
Steam-Assisted Gravity Drainage
Dr. Roger Butler, now with the University of Calgary, first envisaged the SAGD process and developed
the theoretical basis for it during the late 1970s and early 1980s. He was interested in developing a
system that utilized continuous heating and production, rather than the discontinuous CSS process.
Dr. Butler, after determining that vertical wells production rates were too low to make SAGD
economically viable, conceptualized SAGD that used horizontally oriented wells. He subsequently
developed theoretical predictive equations to support this idea. The SAGD test was conducted at Cold
Lake in 1978, and Imperial drilled the first horizontal well for this purpose. Steam was injected from a
vertical well directly above the horizontal producer. Results of this first test were marginal.
SAGD was the first process tested by AOSTRA at its Underground Test Facility (UTF) near Fort
McMurray, in 1983 (Figure 4.4). This facility has a system of vertical access shafts and horizontal
tunnels that allows the placing of pairs of horizontal wells within the oil sands deposit at a depth of
about 200 metres. Each well pair consists of a producer situated near the base of the oil sands and an
injector about five metres directly above the producer. Steam is injected through the upper well and
NATIONAL ENERGY BOARD
27
heats the oil sands and bitumen. Provided
there is sufficient permeability, the
mobilized bitumen and condensed steam
drains by gravity to the producing well,
and is subsequently pumped to the
surface. The depletion zone, or steam
chamber, is enlarged as the bitumen is
removed. Since steam is injected at below
fracture pressure, it is contained within
the steam chamber, thereby enhancing the
heating efficiency of this method.
Encouraged by the 60 percent recovery
factor achieved in the first phase of the
project, subsequent phases were carried
out to conduct further research.
F I G U R E
4 . 4
Underground Test Facility
Courtesy of AOSTRA.
Horizontal drilling technology developed rapidly in the late 1980s and early 1990s. For SAGD, the
orientation and the separation distance between the injector well and the producer well has to be
precisely controlled, and this capability was available by the mid-1990s. Beginning in 1996, several
well pairs were drilled from the surface at the UTF site, and the performance of these wells was
comparable to those that had been drilled from the tunnels.
An additional vital contribution made by AOSTRA was the development of a computer simulation
program to optimize the design and operation of SAGD in horizontal wells. Techniques to control
sand production and to prevent steam from entering the producing well bore were also developed as
part of the UTF project.
The UTF project indicated that SAGD was technologically and economically feasible. Today’s SAGD
operations are built on this model (Figure 4.5). The ability to cost-effectively drill long-reach
horizontal wells, typically hundreds of metres in length, and to precisely control the positioning of these
wells relative to each other and to the boundaries of the target formation, is a major enabling
technological achievement that has allowed the development of SAGD technology. The UTF project is
now known as the Dover Project and is operated by Northstar Energy Ltd.
SAGD technology offers some potential advantages over CSS. These include lower steam-oil ratios
which reduce operating costs,
and the use of lower pressures
F I G U R E
4 . 5
which allow exploitation of
Steam-Assisted Gravity Drainage (SAGD)
shallower reservoirs.
Although not yet proven to be
commercially viable on a large
scale, industry’s confidence in
the process is demonstrated by
the fact that there are
currently six commercial
SAGD projects planned to
start-up before 2005 (see
Chapter 6, Section 6.4.3 and
6.5.1).
28
AN ENERGY MARKET ASSESSMENT
4.4
Primary Bitumen
Recovery
F I G U R E
4 . 6
Multilateral Horizontal Well
There are reservoirs in the Wabasca
area and in the southern part of the
Cold Lake area where primary or
"cold" production is possible; that is,
no external energy is applied to the
reservoir to induce the bitumen to flow
to the well bore. The bitumen in these
areas has undergone a lesser degree of
biodegradation in comparison to the
other areas, and is therefore lighter and
less viscous and flows more readily.
4.4.1
Cold Lake
Within the Cold Lake areas amenable
to primary production, most projects
use vertical wells. Before about 1990,
the sand that was produced along with
the bitumen was problematic, causing
extreme wear on pumping components and reducing production rates and overall productivity. The
wide-scale adoption of the progressive cavity pump in the early 1990s was a significant innovation.
This type of pump was much better suited to handling sand; in fact, operators found that producing
sand along with the oil, especially early in a well’s life, was conducive to higher production rates. It
was determined that a system of preferential fluid flow paths, or "wormholes" formed and expanded
as the sand was produced. This resulted in significantly higher production rates, lower operating
costs and improved economics. Recovery factors range from three to ten percent.
4.4.2
Wabasca
In the Wabasca area, early attempts at production using vertical wells yielded low production rates. It
was not until the advent of horizontal well technology in the 1990s that interest in the area
heightened. The reservoirs are relatively thin (five metres) and consolidated, with no significant sand
production problems, and better suited to primary production by means of horizontal wells. The
horizontal well technology has advanced to the stage that very long single leg and even "multi-leg" or
"multilateral" producing wells can be drilled and successfully operated (Figure 4.6). As an example,
wells with up to seven legs and with a total length of 15 kilometres are being drilled from a single
well bore. Recovery factors are expected to be in the range of seven to ten percent.
4.5
Science and Technology
Although research and development efforts related to oil sands are concentrated in Alberta, they are
being carried out in virtually every province in Canada, and in many parts of the world, encompassing
a wide array of scientific disciplines and technologies. The broad objectives of the ongoing research
are to lower unit production costs, expand the size of the recoverable reserves volume, and, at the
same time, improve environmental performance and product quality.
NATIONAL ENERGY BOARD
29
The discussion in this section will be limited to a brief description of the major current research
efforts, in each of three broad areas: mining and extraction; upgrading; and, in situ recovery. Some
specific examples of major new technological developments are also provided.
4.5.1
Mining and Extraction
The sand component of the oil sands is very abrasive and causes excessive wear on mining and
extraction equipment. Although many improvements have been made to date, as noted above,
research into reducing wear through the development of improved materials and processes is still
important.
The present trend to increasingly larger mining trucks and power shovels is expected to continue.
Trucks capable of hauling loads of 500 tons are expected within this decade. Associated areas of
research and development include the design of tires as well as engine and drive train components.
The development of a system to remove ore at the mine face with a high pressure water jet and
transporting an oil sands slurry by pipeline is an attractive idea, provided that sufficient quantities can
be moved in this fashion to make it economic.
Mobile mine-site extraction technology is expected to be a key breakthrough of the future. Mobile
extraction operations located near the mine face would allow the direct return of waste sand back to
the mine. This form of technology could potentially reduce capital costs and allow operations on a
smaller scale.
Research continues into the new CT system of tailings disposal, as well as a new method termed
"paste" technology.
4.5.2
Upgrading
The current technologies used in the integrated mining plant upgraders are very energy intensive and
depend on hydrogen as a source for hydroprocessing. The broad objectives of upgrading research is
to lower unit production costs while, at the same time, improving environmental performance and
product quality. Ongoing research includes the study of:
• methods to improve energy efficiency;
• methods to reduce harmful emissions;
• the emissions characteristics of transportation fuels made from upgraded crude oils;
• improvements to existing delayed coking and fluid coking technology;
• fine solids/catalyst interaction during hydrotreating; and,
• fluidized bed systems.
Some specific examples are provided below to illustrate the variety of technological innovations being
pursued:
• Aquaconversion™, an upgrading process which utilizes certain additives that when
processed in a visbreaker in the presence of heavy oil and steam, result in the transfer of
hydrogen from the steam into the oile — this process was developed in Venezuela, and is
being tested in that country’s Orinoco field; and,
30
AN ENERGY MARKET ASSESSMENT
• the BioARC (Biocatalytic Aromatic Ring Cleavage) project which is being conducted by a
group at the Centre for Oil Sands Research and Development, using designed strains of
bacteria to provide controlled degradation of petroleum feedstock to reduce the need for
hydrogen addition.f
Processes that provide partial upgrading can benefit large scale upgrading operations, but they also
have application for in situ projects. One of the major problems facing bitumen producers is the need
to dilute the bitumen with condensate in order to meet pipeline specifications for density and
viscosity. Partial upgrading to meet these specifications, that could be done on a relatively small scale
and close to the production facilities or within the reservoir, is an attractive proposition. In this
regard, two novel methods are:
• the (HC)3 or high conversion/hydrocracking/homogenous catalyst process,g developed by
the Alberta Research Council, and adapted to partially upgrade bitumen; and,
• a process developed at the University of Waterloo for the treatment of heavy oil emulsions
that provides both dewatering and upgrading in a single reactor, using hydrogen generated
from water in the emulsion.h
4.5.3
In Situ
The vapour extraction process (VAPEX) is similar to SAGD in that gravity drainage is the drive
mechanism and a pair of horizontal wells are used for injection and production. Instead of steam,
VAPEX involves injecting solvent, which diffuses into the bitumen and results in significant viscosity
reduction. Compared to SAGD, VAPEX has the advantage of:
• lower injection pressure and temperature;
• much greater energy efficiency;
• no emulsion to deal with;
• no formation damage from clay swelling; and,
• partial upgrading within the reservoir, resulting from the precipitation of asphaltenes from
the bitumen.
4.5.4
Primary Production
Regarding primary production, areas of research include:
• the characteristics of wormhole formation and the associated fluid flow processes;i
• improvement in horizontal well design, drilling, and operation; and,
• improvement in lifting systems.
4.6
Conclusion
The initial mining operations at both Suncor and Syncrude were based on a system of large draglines,
bucketwheels and conveyors belts to mine the oil sands and move it to extraction facilities. This
system proved to be relatively inflexible and costly to maintain. Although a process of continuous
improvement served to improve the project economics, major innovations in the 1990s, namely truck
and shovel mining, hydrotransport, and low energy extraction, greatly reduced operating costs.
NATIONAL ENERGY BOARD
31
Although many in situ recovery methods were pilot tested in the 1960s and 1970s, only the steam
stimulation techniques in high quality reservoirs proved to be technically and economically successful.
Imperial’s Cold Lake CSS project is the best example of this.
Research and testing conducted at the UTF project, in combination with significant advances in
horizontal well technology, led to the development of the SAGD bitumen recovery method.
Although not commercially tested on a large scale, this new technology shows great promise. The
application of SAGD is expected to greatly increase the volume of resources deemed to be
economically recoverable.
Science and technology has always played a vital role in the oil sands industry, and research is ongoing into a wide variety of problem areas. The main objectives of the research is to lower costs
while improving product quality and environmental performance.
References
a) Fitzgerald, J.J. Black Gold with Grit, Gray’s Publishing Ltd., 1978.
b) Williams, K. "Technology Evolution and Commercial Development at Imperial’s Cold
Lake Production Project." 16th World Petroleum Congress. Calgary, Canada: June 11-15,
2000. Forum 17.
c) Alberta Oil Sands Technology and Research Authority. AOSTRA Technical Handbook on Oil
Sands, Bitumens and Heavy Oils. Edmonton, 1989.
d) Ibid
e) Marzin, R. et al "Resid Conversion through the Aquaconversion™ Technology — An
Economical and Environmental Solution." 7th UNITAR International Conference on
Heavy Crude and Tar Sands. Bejing, China: 1998.
f) Canadian Oil Sands Network for Research and Development. CONRAD Connections.
Calgary: Spring 2000.
g) Lott, Roger, Ted Cyr and Roger Bailey. "(HC)3 Process - A Slurry Hydrocracking
Technology Designed to Convert Bottoms and Heavy Oils." 7th UNITAR International
Conference on Heavy Crude and Tar Sands. Bejing, China: 1998.
h) Moll, J. and F. Ng. "A Novel Process For Upgrading Heavy Oil/Bitumen Emulsions Via
In Situ Hydrogen." 16th World Petroleum Congress. Calgary, Canada: June 11-15, 2000.
Forum No. 6
i) Yarlong Wang, Computer Modelling Group, and Jian-Yang Yuan, Alberta Research
Council. "Cold Production and Wormhole Propagation in Poorly Consolidated
Reservoirs." 7th UNITAR International Conference on Heavy Crude and Tar Sands.
Bejing, China, 1998. Paper No. 1998.041.
Selected Background Literature
de Bruijn, Theo. "Process for Partial Upgrading". Presentation at Canadian Heavy Oil Association.
Calgary, Canada: October 4, 2000.
Fisher, Larry and Louise Gill. "Supply Costs and Economic Potential for the Steam Assisted Gravity
Drainage Process". CERI, Study No. 91, September 1999.
32
AN ENERGY MARKET ASSESSMENT
Komery, Douglas and Ted Cyr. "Cooperative R&D Strategy by Industry and Government for
Successful Development of Alberta Energy Resources." 7th UNITAR International Conference on
Heavy Crude and Tar Sands. Bejing, China, 1998. Paper No. 1998.184.
Lanier, Douglas. "Heavy Oil - A Major Energy Source for the 21st Century." 7th UNITAR
International Conference on Heavy Crude and Tar Sands. Bejing, China: 1998.
Nasr, T., I. Isaacs, and W. Good. "Synergies of New Technologies - The Steam Assisted Gravity
Drainage (SAGD)." 16th World Petroleum Congress. Calgary, Canada, June 11-15, 2000. Forum
No. 17.
National Oil Sands Task Force. Canada’s Oil Sands Industry: Yesterday, Today and Tomorrow.
Edmonton: Alberta Chamber of Resources, 1995.
Parker, Richard, Theo de Bruijn and Len Flint. "Heavy Oil Recovery and Upgrading - Where to
Draw the Line?" 16th World Petroleum Congress. Calgary, Canada: June 11-15, 2000. Forum No. 6
Poster 3.
Petroleum Communication Foundation. Canada’s Oil Sands and Heavy Oil - Developing the World’s
Largest Petroleum Resource. Calgary, Canada: 2000.
Polikar, Marcel, Ted Cyr and Keith Sadler. "Alberta Oil Sands: The Advance of Technology, 1978-98
and Beyond." 7th UNITAR International Conference on Heavy Crude and Tar Sands. Bejing, China,
1998.
Singhal, A. et al. "Screening of Reservoirs For Exploitation by Application of Steam Assisted Gravity
Drainage/Vapex Processes." 1996 International Conference on Horizontal Well Technology.
Calgary, Canada: November 19-20, 1996. Paper No. SPE 37144.
Yildirim, Erdal. "Oil Sands Development in Canada." 7th UNITAR International Conference on
Heavy Crude and Tar Sands. Bejing, China: 1998. Paper No. 1998.227.
NATIONAL ENERGY BOARD
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C
H
A
P
T
E
R
F
I
V
E
S UPPLY C OSTS
5.1
Introduction
This chapter presents a discussion of supply costs for both oil sands mining and in situ projects, including
primary bitumen production. A brief description of the new fiscal regime for oil sands is also included.
In this report, “oil sands mining” generally refers to integrated surface-mining and upgrading
operations, but also includes stand-alone surface-mining projects. “Oil sands in situ” refers to all in
situ operations, including primary bitumen recovery operations.
5.2
Methodology
As in previous Board reports, supply costs are expressed as full cycle, which includes all costs
associated with exploration, development and production. They include capital costs, operating costs,
taxes and royalties and a 10 percent real rate of return to the producer. Accordingly, they include all
those environmental costs that have been internalized through the implementation of mitigation
methods, such as those discussed in Chapter 9, or capitalized as a production cost. They do not
include any costs to society associated with environmental impacts which have not been mitigated.
The exploration costs associated with the oil sands are minimal because the location and extent of the
oil sands deposits have been well defined by past exploratory efforts. Although drilling and seismic
surveying are being done, this is largely geared toward reservoir development. The Board’s estimates
of supply costs are based on discussions with industry, consideration of the announced development
plans for mining and in situ projects, research of the trade literature and the Board’s own analysis.
Supply costs are quoted in 1997 Canadian dollars per barrel unless otherwise noted. These costs do
not include transportation to market.
The economic assumptions used in this report are the same as those contained in the Board’s Supply
and Demand report, including a world crude oil price of US$18 per barrel for WTI. While crude oil
prices are expected to be volatile, US$18 is still considered by oil market analysts to be a reasonable
assumption for the longer term.
Supply costs are stated as a range, reflecting the variance in reservoir quality, depth, project size and
operating parameters for the projects being developed.
5.3
Oil Sands Mining Projects
5.3.1
Supply Costs - Oil Sands Mining
The first two large-scale commercial mining projects, Great Canadian Oil Sands Company (now
Suncor), which began operations in 1967, and Syncrude, which commenced in 1978, suffered from
34
AN ENERGY MARKET ASSESSMENT
start-up problems, and it took several years for reasonably smooth production operations to be
established. Early supply costs are estimated to have been $35 per barrel or above (dollars of the
day). In reaction to high supply costs, sustained periods of low oil prices, and overall uncertain crude
oil prices, oil sands mining developers concentrated on cost reduction to improve the economics of
oil sands production. As a result, operating costs have trended downward. Between the early 1980s
and the late 1990s, operating costs have been reduced from $30 per barrel to less than $13 per barrel.a
Capital cost requirements were also reduced such that current total supply cost estimates are in the
range of $15 to $18 per barrel for an integrated oil sands mining and upgrading operation.
Substantial reductions in supply costs were achieved through continuous process improvement;
however during the 1990s there were two major innovations which resulted in large reductions in
operating costs. First, there was a move towards replacing the draglines and bucketwheel reclaimers
with mining trucks and power shovels. This equipment offered increased flexibility, lower
maintenance and improved energy efficiency. Second, the introduction of the hydrotransport system
to replace the conveyor belts to transport oil sands to the processing plant was a major innovation,
again resulting in increased flexibility and energy efficiency. Several other changes were also
important and cumulatively have had a significant effect on operating costs although they did not
result in a step reduction. These changes included improved tailings management, the switch to
cyclofeeders from breakers and the low temperature extraction process.
5.3.2
Supply Cost Projections - Mining
Industry analysts anticipate that continuing improvements in technology and operating methods may
bring operating costs (dollars of the day) for integrated mining/upgrading plants down to $10 per
barrel as early as 2004, with further improvement to the $8 to $9 per barrel level by 2015.
A major cost component for upgrading bitumen is the price of natural gas which is used to generate
electricity and steam, and is also a source of hydrogen used in the upgrading process. It is estimated
that an increase in the natural gas price of $1.00/GJ increases operating costs by about $1.00 per
barrel. Under a high natural
gas price scenario the
T A B L E
5 . 1
reductions in operating cost
will be more difficult to
Estimated Supply Costs - $(1997) per barrel
achieve. By the same token,
there is some degree of
Oil Sands - In Situ
Operating Cost
Supply Cost
linkage between oil and gas
Primary Recovery - Wabasca
3 to 6
7 to 10
prices; that is, if oil prices
Primary Recovery - Cold Lake
6 to 9
10 to 13
moderate there would be some
downward pressure on gas
Cyclic Steam Stimulation
6 to 10
10 to 16
prices as well.
Steam Assisted Gravity Drainage
Table 5.1 outlines the
operating costs and total
supply costs (everything in) for
the production of bitumen and
upgraded crude oil for the
various recovery methods.1
5 to 9
8 to 14
Integrated Mining/Upgrading
10 to 12
15 to 18
Stand-Alone Upgraders
10 to 12
18 to 22
Mining - No Upgrading
5 to 8
10 to 13
Oil Sands - Mining
1 The Base Case assumes an oil price of US$18 per barrel (WTI) at Cushing, Oklahoma, a natural gas price of
$2.75 per gigajoule and a light/heavy differential at Hardisty, Alberta of C$5 per barrel, all 1997 dollars, constant,
real.
NATIONAL ENERGY BOARD
35
5.4
In Situ Projects
5.4.1
Supply Costs - In Situ
In situ production has not achieved step reductions in supply costs similar to those for the mining
operations. However, there have been important innovations and improvements that have reduced
costs. Among these are significant advances in horizontal well technology in the last decade that have
led to:
• reduced drilling costs;
• the ability to drill and complete extended-reach and multi-leg wells, thereby greatly
increasing the volume of reservoir contacted per well; and,
• the ability to accurately guide the drill bit while drilling, which was an enabling technology
for the SAGD recovery method.
The development of SAGD is also a major innovation. It is expected to have lower costs, in general,
than CSS, because high steam pressures are not required, and because of the efficiencies achieved
through using horizontal wells.
Other innovations include:
• improved steam and heat management in CSS operations, by varying the time and steam
volume during each cycle;
• better reservoir management;
• improved well work-overs;
• reduced rig time to drill and complete new wells;
• computer simulation and new seismic survey techniques for analysing and forecasting
reservoir performance;
• combined-cycle cogeneration plants to obtain high thermal efficiency in steam generation;
• control and measurement of steam flow in distribution piping; and,
• more efficient separation and treatment of produced oil and water.
These and other innovations and technologies have significantly lowered both operating and capital
costs. In situ producers can further lower supply costs per barrel by taking advantage of economies of
scale.
Bitumen typically requires that about 33 to 40 percent of diluent be added (25 to 30 percent of blend)
to meet pipeline specifications for density and viscosity. The availability and cost of natural gas
condensate or other diluents to blend the bitumen can also affect the feasibility of in situ bitumen
projects.
In certain areas of the Cold Lake and Wabasca deposits, bitumen can be recovered by primary or
“cold production” means. In the Cold Lake region, this type of production typically employs vertical
well bores coupled with progressive cavity pumps that are well suited to handling sand. Primary
production in the Wabasca area typically employs horizontal wells, both single-leg and multi-leg, with
horizontal sections as long as 2 000 metres. Supply costs are in the range of $10 to $13 per barrel for
primary production in Cold Lake while the Wabasca area has slightly lower costs, in the $7 to $10
per barrel range.
36
AN ENERGY MARKET ASSESSMENT
5.4.2
Supply Cost Projections - In Situ
The first attempts at in situ recovery of bitumen from oil sands occurred in the Athabasca region in
the 1920s and 1930s, but met with little success. In the 1960s and 1970s, a series of exploration and
research efforts led to a wide variety of pilot projects. Most of the projects did not pass the test of
technical and economic feasibility.
Currently, about 67 percent of in situ bitumen production is derived from thermal projects involving
some form of steam stimulation. The remaining 33 percent is from primary production projects.
For the steam stimulation projects, the cost of the fuel used to produce the steam can account for
50 percent or more of the total operating cost. The operating costs of producing in situ bitumen
have considerable variation, ranging from about $3 to $10 per barrel. These operating costs are very
dependent on the recovery method, recovery rate, peak production level and the steam/oil ratio for
thermal projects. Considering that natural gas consumption is by far the largest cost component of in
situ production, any changes in gas prices or any improvements in thermal efficiency in steam
generation will have a significant impact on operating costs. Estimates of supply costs for in situ
production are shown in Table 5.1.
Although the SAGD recovery method has not yet been commercially proven in bitumen reservoirs,
the success of the UTF pilot project and the successful application of SAGD in several conventional
heavy oil reservoirs has given industry confidence in this technology. There are currently six
publically announced commercial scale SAGD projects scheduled to begin operation before 2005. In
order to assess the potential for SAGD development, the Board conducted an analysis of supply costs
for SAGD. A range of supply cost estimates for SAGD production were developed by considering
the effect of variations in the natural gas price, project size and reservoir quality. Reservoirs of four
different qualities were considered, consisting of a higher and lower quality reservoir in the Athabasca
area and a higher and lower quality reservoir in the Cold Lake area (Figures 5.1 and 5.2).
A further description of the methodology and assumptions used in this analysis are contained in
Appendix A-2.
The supply costs vary widely depending on the scenario chosen, with costs ranging from $22.50 per
barrel, for the combination of a low quality Cold Lake deposit, a $5.00/GJ natural gas price and a
3 000 m3/d plant size — to $6.00 per barrel for the combination of a high quality Athabasca deposit, a
$2.00/GJ natural gas price and a 16 000 m3/d plant size. While the supply cost is sensitive to the
natural gas price and economies of scale, the quality of the reservoir is the most critical factor. Given a
natural gas price of $3.00/GJ and a plant size of 8 000 to 10 000 m3/d, the better projects would have a
supply cost in the order of $10 to $12 per barrel in the Cold Lake area and $8 to $10 per barrel in the
Athabasca area. This compares with the supply cost for conventional heavy crude oil of $9 to $10 per
barrel, before consideration of relative transportation costs. A price of US$18 for WTI, after
considering transportation charges, exchange rates, blending costs, and a $5.00 light/heavy differential,
translates to a realization of about $11.00 per barrel in the field for SAGD derived bitumen.
NATIONAL ENERGY BOARD
37
F I G U R E
5 . 1
Athabasca Deposits Supply Cost - SAGD
C$/barrel
25
20
15
10
5
0
3000
4000
5000
6000
7000
8000
9000
10000 12000 14000 16000
Plant Size (m3/d)
F I G U R E
Low quality - C$5/GJ
High quality - C$5/GJ
Low quality - C$4/GJ
High quality - C$4/GJ
Low quality - C$3/GJ
High quality - C$3/GJ
Low quality - C$2/GJ
High quality - C$2/GJ
5 . 2
Cold Lake Deposits Supply Cost - SAGD
C$/barrel
25
20
15
10
5
0
3000
4000
5000
6000
7000
8000
9000
10000 12000 14000 16000
Plant Size (m3/d)
38
Low Quality - C$5/GJ
High Quality - C$5/GJ
Low Quality - C$4/GJ
High Quality - C$4/GJ
Low Quality - C$3/GJ
High Quality - C$3/GJ
Low Quality - C$2/GJ
High Quality - C$2/GJ
AN ENERGY MARKET ASSESSMENT
5.5
Oil Sands Fiscal Regime
On September 24, 1997, the Alberta Government completed the enactment of a generic royalty
regime that will ultimately replace the custom tailored Crown Agreements. The locations affected by
the regime include the Athabasca, Peace River and Cold Lake Oil Sands Areas.
The main purpose of the new regime is to provide common rules that apply equally to all oil sands
developers. Prior to the generic oil sands royalty system, each project’s royalty terms were negotiated
on a project-by-project basis. This process was possible due to the limited number of projects that
were commercially active in Alberta. These project-specific arrangements in the oil sands industry
resulted in an overall inharmonious royalty system. The developers agreed that Alberta’s ad hoc oil
sands royalty system led to uncertainty about the terms that would apply to their future investments.
Investors considering oil sands development did not have a transparent royalty structure on which to
evaluate investment plans. As well, existing oil sands companies were not certain about the future
royalty structure for new investments or expansions. As a result, there was a need to construct a
formal royalty structure for the oil sands industry that would place all projects on a level playing
field.b
The evolution of the new royalty regime commenced in the spring of 1995 when the National Task
Force on Oil Sands Strategies released a comprehensive report that outlined a detailed list of
recommendations for the oil sands industry. The Task Force was formed by the Alberta Chamber of
Resources in 1993. This committee consisted mainly of representatives from the oil sands industry
and supporting industries, as well as representatives from both the provincial and federal
governments. The Task Force proposed a generic oil sands royalty system based on a specified
percentage of net project revenue after all costs are recovered. The proposal reflected the type of
royalty system already in place through various individual oil sands Crown Agreements (i.e.,
Syncrude, Suncor and Imperial Oil’s Cold Lake Project). These Agreements provided a foundation
for the Task Force’s recommendations and for the Alberta Government’s new generic royalty system.
The Task Force recommendations were designed to:
• accelerate the development of the oil sands while ensuring a fair return to Albertans — the
resource owners;
• facilitate development of the oil sands by private sector companies who can expect to make
a reasonable profit from the venture — governments will not directly participate through
grants, loans or loan guarantees;
• ensure that oil sands development is competitive with other petroleum development
opportunities around the world; and,
• create a standard set of royalty and taxation terms for new projects to create a clear,
consistent and stable system.c
5.5.1
New Royalty and Taxation Measures
Alberta used many of the recommendations of the Task Force in developing the standardized oil
sands royalty system. The basic elements of the new system are:
• minimum one percent royalty payable on all production;
• 25 percent royalty payable on net project revenues after the developer has recovered all
project costs, including research and development costs, and a return allowance;
NATIONAL ENERGY BOARD
39
• return allowance set at the Government of Canada Long-Term Bond Rate; and,
• all project costs including capital, operating, and research and development are 100 percent
deductible in the year incurred.
The new generic royalty regime is administered by Alberta Resource Development under the Mines
and Minerals Act. It is designed to support the major investment needed to develop the oil sands
resource. The regime will apply to new investment in developing Alberta’s oil sands and expansions
of existing projects. An important feature of the royalty agreement is that Alberta is sharing risk with
the developer. Only when the developer’s cumulative project revenues exceed cumulative project
costs, including a return on investment equal to the Canada Long-Term Bond Rate, does Alberta
receive a significant royalty.
This royalty regime was chosen over production-based royalties due to the high cost, long lead time
and the associated high-risk nature of oil sands investment. Production-based royalties, such as those
used for conventional oil and gas, are less sensitive to project profitability. Since the oil sands have
higher barriers to development than other types of petroleum (higher capital and operating costs, less
valuable product, higher technology risk, etc.), the additional burden of a significant productionbased royalty was determined to be inappropriate.
The federal government, a member of the Task Force, agreed to modify the rules regarding taxation of
oil sands production. The 1996 Federal budget provided generic tax treatment for all oil sands projects.
The tax treatment previously applied only to oil sands mining projects was extended to include in situ
projects. In addition, tax incentives previously available only for new projects and major expansions
were extended to include other investments, such as environmental and efficiency improvement projects.
5.6
Conclusion
Supply costs for bitumen production from Canada’s oil sands have been substantially reduced through a
process of continuous improvement in all aspects of operations and more importantly, through the
implementation of major technological innovations, with most of these innovations occurring in the 1990s.
For the existing surface-mining operations, supply costs have been reduced by more than one-half in
the last twenty years, with current supply costs in the field estimated to be in the range of $15-$18
per barrel. The adoption of truck and shovel mining, hydrotransport and low energy extraction are
the major reasons for this cost reduction.
For in situ operations, supply costs have also been reduced through continuous improvement and
innovation, although not to the same extent as in the surface-mining operations. Continuous
improvement in CSS operations, the maturation of horizontal well technology and the development
of the SAGD recovery technique are the major features that have facilitated this cost reduction.
Current supply costs for CSS are estimated to be in the $10-$16 per barrel range, while those for
SAGD are estimated to be $8-$14 per barrel. Costs for both methods are highly dependent on the
quality of the reservoir.
Both integrated mining projects and thermal in situ projects use substantial amounts of natural gas as
a fuel source in their operations. Thus, the price of natural gas is an important determinant of the
level of profitability for these projects. The cost of condensate for blending of bitumen is also an
important consideration.
40
AN ENERGY MARKET ASSESSMENT
In regard to primary recovery, the development of extended-reach and multi-leg horizontal wells
facilitated the economic recovery of bitumen in the Wabasca region. In the Cold Lake region, the
adoption of the progressive cavity pump in vertical well bores reduced the cost of production. Estimated
supply costs for Wabasca are $7-$10 per barrel, compared to $10-$13 per barrel for Cold Lake.
The new royalty and fiscal regime is considered to be a positive and enabling feature, in that investors
and developers are ensured of equal and predictable royalty and taxation treatment for all oil sands
projects.
References
a) Petroleum Communication Foundation. Canada’s Oil Sands and Heavy Oil. April 2000.
b) Masson, R. and B. Remillard. “Alberta’s New Oil Sands Royalty System.” Alberta
Department of Energy, May 1996.
c) Mitchell, R. et al. “Alberta Oil Sands: Update on the Generic Royalty Regime,” Alberta
Department of Energy, May 1998.
Selected Background Literature
Fisher, Larry and Louise Gill. "Supply Costs and Economic Potential for the Steam Assisted Gravity
Drainage Process". CERI, Study No. 91, September 1999.
Walker, I.C. “Marketing Challenges for Canadian Bitumen” 7th UNITAR International Conference
on Heavy Oil and Tar Sands, Beijing, China, 1998.
NATIONAL ENERGY BOARD
41
C
H
A
P
T
E
R
S
I
X
C RUDE O IL S UPPLY
6.1
Introduction
This chapter focuses on the projections of oil supply derived from Canada’s oil sands, divided into
two categories reflecting the method of recovery. “Oil sands mining” includes all production derived
from surface mining operations while “oil sands in situ” includes all production derived from in situ
operations, including primary recovery projects. Supply projections are also expressed in terms of net
available crude oil supply, a term which refers to the volumes of crude oil available to the market after
upgrading and blending are taken into account. In addition, brief descriptions of the more important
active projects as well as currently planned projects are provided.
6.2
Supply Projections
6.2.1
Methodology
The Board’s oil sands supply projections are based on discussions with industry combined with the
Board’s analysis and expertise. The development plans for mining, in situ and primary recovery
projects are considered, as are plans for upgrading and pipeline expansion projects. In addition, a
cash flow model, combined with supply cost analysis, is used to gauge the pace of development
activity. The starting point for the development of the supply projections is the consideration of the
current trends in activity and the momentum that has resulted from the relatively high crude oil
prices experienced since late 1999.
The economic assumptions used in the supply projections are primarily those contained in the
Board’s Supply and Demand Report, including a US$18 per barrel price forecast for WTI. A
summary of the economic assumptions are provided in Appendix A-3. The supply projections for
conventional light crude oil, pentanes plus and conventional heavy crude oil are from Case 1 of the
Supply and Demand Report, except that conventional heavy crude oil has been modified upwards
reflecting higher than expected actual production.
In addition to the Base Case projections, which are based on a US$18 per barrel oil price, sensitivities
at US$14 per barrel ($14 Sensitivity) and US$22 per barrel ($22 Sensitivity) were run to test the
effect of price on supply.1
1 In the $14 and $22 Sensitivity, a WTI price of US$14 and US$22 (1997, real, constant) is assumed; other
econometric assumptions remain the same as in the Base Case.
42
AN ENERGY MARKET ASSESSMENT
6.2.2
Oil Sands Mining
Oil sands mining production generally refers to synthetic crude oil or upgraded crude oil from
integrated oil sands mining projects, but also includes production that is mining derived and marketed
as a blended bitumen.
In 1999, crude oil derived from oil sands mining averaged over 51 500 m3/d1 or approximately
15 percent of the total Canadian crude oil production. By 2015, oil sands mining derived production
is projected to reach 158 000 m3/d (Figure 6.1).
The supply projection in the Base Case includes the expansion plans of the Syncrude and Suncor
operations, as well as the announced development plans of the Athabasca Oil Sands Project by Shell
and partners. Although the supply projection includes additional new projects, they are not
specifically identified, as the scheduling and size of the proposed projects will no doubt change with
changing economic conditions, and not all announced projects are likely to proceed. In addition to
assessing the merits of individual projects, the results of an industry cash flow modela are used to
predict the pace at which development might proceed. The various expansion and development plans
are discussed in Section 6.4.1.
6.2.3
Price Sensitivities - Oil Sands Mining
In the $22 Sensitivity, the Syncrude, Suncor and Athabasca projects proceed as scheduled. As well, an
additional 22 000 m3/d of production is brought on by 2010, allocated to undefined projects that
could include new large scale projects as well as additional expansions of existing projects. Production
reaches over 180 000 m3/d in 2015, which is about 14 percent higher than in the Base Case.
In the $14 Sensitivity, the actual price track used does not decline to US$14 from current prices until
2002. The economics at this price discourage any new development. In this sensitivity, the
Syncrude, Suncor and Athabasca projects are assumed to be operating; however, new projects and
F I G U R E
6 . 1
Supply Projections - Oil Sands Mining
Thousand m3/d
200
160
120
80
40
0
1995
1997
1999
2001
$18 Base Case
2003
2005
2007
$14 Sensitivity
2009
2011
2013
2015
$22 Sensitivity
1 One cubic metre (m3) of crude bitumen is approximately equal to 6.3 barrels or one metric tonne.
NATIONAL ENERGY BOARD
43
most expansion plans have been postponed indefinitely. The projected production rate in 2015 is
approximately 112 000 m3/d, which is 29 percent lower than in the Base Case.
6.2.4
Oil Sands In Situ
Oil sands in situ production generally refers to bitumen derived from in situ oil sands projects that is
blended with condensate and moved to market as a blended bitumen, but may include some bitumen
volumes that are fed into integrated mining/upgrading plants. The term “bitumen” is commonly
used when referring to in situ production.
Similar to the development of the supply projections for mining projects, individual projects are
assessed on their merits and given a relative ranking. In addition, the results of an industry cash flow
model are used to assess the pace at which development might proceed. As a result, not all
announced projects are specifically included in the supply projections, and the implementation of
some projects is delayed. The early part of the projection period is more heavily influenced by
projects that are currently being developed or are near commencement, while the cash flow model
results have more weight in defining the longer term outlook.
Since the in situ projects are largely thermal projects that are based on steam stimulation, the price of
natural gas is an important consideration, as is the cost and availability of diluent for blending and the
differential between light and heavy crude oil.
Bitumen production averaged over 42 000 m3/d in 1999 (Figure 6.2). Thermal projects operated by
Imperial and Canadian Natural Resources Ltd. (CNRL) in the Cold Lake/Primrose area account for
most of the bitumen production to date, but there has also been significant production from the
Lindbergh and Peace River areas. Primary production from the Cold Lake and Wabasca region is an
important component of in situ production, accounting for 14 000 m3/d or 33 percent of total
bitumen production. Some expansion of primary production from the Wabasca area is anticipated;
however, the response is limited by the quality and quantity of the remaining resource base. Primary
production in the Cold Lake area is expected to expand moderately, in accordance with the economics
of this type of production.
F I G U R E
6 . 2
Supply Projections - Oil Sands In Situ
Thousand m3/d
200
160
120
80
40
0
1995
1997
1999
2001
$18 Base Case
44
2003
2005
2007
$14 Sensitivity
2009
2011
2013
2015
$22 Sensitivity
AN ENERGY MARKET ASSESSMENT
There are currently over 40 new bitumen projects or expansion phases proposed. In the Base Case
supply projections, bitumen production is expected to increase to 103 000 m3/d by 2015 (Figure 6.2).1
6.2.5
Price Sensitivities - Oil Sands In Situ
In the $22 Sensitivity, the production of bitumen increases significantly, reaching 131 000 m3/d by
2015. This is 30 percent higher than in the Base Case.
In the $14 Sensitivity, the netbacks to the producer are not sufficient to encourage any additional
development; in fact, after 2001 the projected supply decreases by about one percent per year. By
2015 bitumen production in the $14 Sensitivity is about 44 000 m3/d or less than half of the
production in the Base Case.
6.2.6
Pentanes Plus Supply
Although some pentanes plus is derived from field condensate, the bulk of the supply is derived from
the processing of natural gas. The projection of pentanes plus supply is therefore directly tied to the
natural gas supply projections. It is included in this report because pentanes plus are used primarily
as a diluent to blend with heavy crude oil and bitumen to reduce density and viscosity in order to
meet pipeline specifications.
The supply projections for pentanes plus are taken directly from the Supply and Demand Report, but
modified to reflect actual production. In the Base Case, the supply of pentanes plus is projected to
gradually increase from the current level of about 27 400 m3/d in 1999 to about 35 000 m3/d by 2015
(Figure 6.3a). These volumes do not include production from the East Coast of Canada.
In the $22 Sensitivity pentanes plus supply increases to about 36 000 m3/d by 2015 (Figure 6.3b). In
the $14 Sensitivity, supply increases slightly to over 29 000 m3/d in 2001, and then gradually declines
to under 24 000 m3/d by 2015.
6.2.7
Diluent Requirement
The largest use of pentanes plus is for diluent in the blending of heavy crude oil and bitumen to facilitate
its transportation to market by pipeline. Typically, raw bitumen requires approximately 40 percent of
diluent to be added, while conventional heavy crude oil requires about seven percent. In 1997 there was
a relative shortage of pentanes plus for use as diluent, and several steps were taken to alleviate the
situation. A new viscosity standard was implemented on the Enbridge Pipeline Inc. system in early 1999,
which reduced the diluent requirement by about 10 percent. As well, a condensate price equalization
program was developed to encourage the inclusion of light crude oil streams into the diluent pool.
Two important determinants of the demand for diluent are the pace of development of bitumen
projects and the amount of local upgrading installed. In the supply projections, most oil sands mining
developments are assumed to include upgrading capacity, hence they require no net diluent.
However, some mining and most in situ bitumen projects are assumed to include only partial or no
upgrading and will therefore require significant additional diluent. The assumption is made that the
Lloydminster Bi-Provincial Upgrader capacity is increased to 28 400 m3/d by 2007.
It is estimated that about 4 000 m3/d of pentanes plus is not currently available for use as a diluent.
This amount includes the volumes that are used in miscible flood oil recovery projects, as refinery
1 The Base Case assumes an oil price of US$18 (1997) per barrel (WTI), a natural gas price of C$2.75 per gigajoule
and a light/heavy differential of C$5 per barrel, all constant, real.
NATIONAL ENERGY BOARD
45
feedstock, or batched directly into light crude oil streams. It is assumed that these volumes would be
available for use as diluent within the projection period.
Figures 6.3a and 6.3b illustrate the balance between pentanes plus supply and net diluent requirement
for the Base Case and the $14 and $22 Sensitivities. In the Base Case, a potential shortfall for
pentanes plus first occurs in 2005, and reaches almost 5 000 m3/d by 2015. Between 2005 and 2008
the short fall is less than 500 m3/d.
In the $22 Sensitivity, the net diluent requirement is about 11 000 m3/d greater than in the Base Case
by 2015. The potential shortfall first occurs in 2004, and reaches almost 15 000 m3/d by 2015. In the
$14 Sensitivity, the net diluent requirement is about 24 000 m3/d less than in the Base Case by 2015.
As a result, there is no potential shortfall for pentanes plus during the projection period.
F I G U R E
6 . 3 A
Base Case - Pentanes Plus Supply vs. Net Diluent Requirement
Thousand m3/d
60
50
40
30
20
10
0
1995
1997
1999
2001
2003
2005
2007
Pentanes Plus Supply
F I G U R E
2009
2011
2013
2015
Net Diluent Required
6 . 3 B
$14 and $22 Sensitivity - Pentanes Plus Supply vs. Net Diluent Requirement
Thousand m3/d
60
50
40
30
20
10
0
1995
46
1997
1999
2001
2003
2005
2007
2009
2011
2013
$14Pentanes Plus Supply
$22 Pentanes Plus Supply
$14 Net Diluent Required
$22 Net Diluent Required
2015
AN ENERGY MARKET ASSESSMENT
The potential shortfall of diluent in the Base Case and the $22 Sensitivity could be alleviated by
adding local upgrading capacity, which could include partial upgrading or small scale field upgrading,
if these latter technologies prove viable. Alternatively, some of the shortfall could be offset by using
heated pipelines or by using other types of diluent, such as light crude oil, synthetic crude oil or
naphtha, but these alternatives are not economically attractive. The potential shortage of pentanes
plus for use as diluent poses a significant potential problem for the industry. The potential solutions
all entail additional costs that could constrain heavy oil or oil sands development.
6.2.8
Net Available Supply - Crude Oil and Equivalent
“Net available supply” refers to the volumes of crude oil available to the market after taking upgrading
and blending into account. Thus, the net available Canadian crude oil supply represents the total of
WCSB conventional light crude, East Coast crude, synthetic crude oil, pentanes plus, blended heavy
crude and blended bitumen, after local feedstock and diluent requirements have been met. It is assumed
that some light or synthetic crude oil will be used as diluent. The projections of available supply take into
account the diluent requirements for blending heavy oil and bitumen, recycled volumes of diluent,
product losses during upgrading and volumes of pentanes plus not available to the downstream market.
In 1999, WCSB conventional light crude oil made up about 34 percent, East Coast 5 percent,
blended heavy oil 21 percent, pentanes plus 2 percent, synthetic crude oil 21 percent and blended
bitumen almost 17 percent of the total net available supply of crude oil.
In the Base Case (Figure 6.4a), net available supply increases from 327 900 m3/d in 1999 to a peak of
502 000 m3/d in 2008, then gradually declines to about 490 000 m3/d by 2015. By 2015, mainly due
to natural decline, the share of WCSB conventional light and conventional heavy blend decreases to
15 percent and 5 percent, respectively, of the net available supply. Conversely, synthetic and blended
bitumen production increases to about 38 percent and 28 percent, respectively, and East Coast
production increases to 14 percent of total net available supply.
In the $22 Sensitivity (Figure 6.4b), the net available supply increases to almost 606 000 m3/d in 2012
and then decreases slightly to 603 000 m3/d by 2015. At the end of the projection period synthetic
F I G U R E
6 . 4 A
Net Available Supply - Base Case
Thousand m3/d
600
500
400
300
200
100
0
1995
1997
1999
2001
2003
2005
2007
2009
2011
2013
Conventional Light
Pentanes Plus
Blended Bitumen
Synthetic
Heavy Blend
East Coast
NATIONAL ENERGY BOARD
2015
47
crude oil makes up about 35 percent and blended bitumen about 30 percent of the total Canadian net
available supply. WCSB conventional light represents only 13 percent and blended heavy oil only
6 percent by 2015. Similar to the 1999 Supply and Demand Report, the $22 Sensitivity includes
production from the MacKenzie Delta-Beaufort Sea region starting in 2010, and reaching
25 000 m3/d by 2012.
In the $14 Sensitivity (Figure 6.4c), the net available supply of crude oil decreases to about
314 000 m3/d by 2015. Of this amount, synthetic crude oil encompasses about 45 percent and
blended bitumen about 19 percent of the total net available supply by 2015. The amount of net
conventional heavy blend available approaches zero by 2015 as most of the heavy blend is used locally
as upgrader feedstock.
F I G U R E
6 . 4 B
Net Available Supply - $22 Sensitivity
Thousand m3/d
600
500
400
300
200
100
0
1995
1997
1999
2001
2003
2005
2007
2009
2011
2013
Conventional Light
Pentanes Plus
Blended Bitumen
Synthetic
Heavy Blend
East Coast
F I G U R E
2015
6 . 4 C
Net Available Supply - $14 Sensitivity
Thousand m3/d
400
300
200
100
0
1995
48
1997
1999
2001
2003
2005
2007
2009
2011
2013
Conventional Light
Pentanes Plus
Blended Bitumen
Synthetic
Heavy Blend
East Coast
2015
AN ENERGY MARKET ASSESSMENT
6.3
Oil Sands Mining And In Situ Projects
In this section the major oil sands mining and in situ bitumen projects are briefly described. In most
cases the production time table and some distinguishing characteristics will be featured. The
information provided below is time sensitive as some project details may be subject to change and
projects may be added or deleted.
6.4
Athabasca Deposit
6.4.1
Oil Sands Mining Projects
T A B L E
6 . 1
Oil Sands Mining Projects
Project
Suncor Energy Oil Sands
Estimated Cost
$600 million
Fixed Plant Expansion and Steepbank Mine - completed in
1999; expanded to 16 800 m3/d.
Project Millennium
Syncrude Canada Ltd.
Description
$190 million
Phase 1 - expand to 20 600 m3/d in 2001.
$2.0 billion
Phase 2 - expand to 35 000 m3/d in 2002.
$470 million
Stage 1: North Mine and Debottleneck 1 - construction from
1996-1999; expanded to 35 400 m3/d.
Syncrude 21
$1.0 billion
Stage 2: Aurora Train 1 and Debottleneck 2 - construction
phase 1998-2001; expansion to 40 800 m3/d.
$3.0 billion
Stage 3: Aurora Train 2 and Upgrading Expansion 1 construction from 2000-2004; expansion to 56 500 m3/d.
$2.3 billion
Stage 4: Aurora Train 3 and Upgrading Expansion 2 construction from 2004-2008; expansion to 73 800 m3/d.
Shell / Chevron / Western
$1.8 billion
Muskeg River Mine will produce 24 600 m3/d of bitumen
starting in late 2002.
$1.7 billion
Scotford Upgrader will be constructed next to Shell’s existing
Athabasca Oil Sands
Scotford Refinery.
TrueNorth / UTS Energy
$1.1 billion
Fort Hills project would produce approximately 15 000 m3/d of
bitumen from the initial mine by 2005.
$1.7 billion
Includes mining and extraction facilities for about 20 600 m3/d
of bitumen.
$1.4 billion
New upgrader facilities (location unknown).
Fort Hills
ExxonMobil Corporation
Kearl Oil Sands
Millennium
In 1999, Suncor’s synthetic crude oil production averaged 16 600 m3/d. Project Millennium is
expected to cost $2.2 billion and increase production to 35 000 m3/d by 2002. Suncor has adopted a
staged approach to managing expansion. The first phase is designed to improve processes and
increase plant capacity by the year 2001. The second phase, the biggest phase of growth to date,
includes further development of the Steepbank Mine, expansion of the extraction and upgrading
plants, and increased requirements for steam, water and electricity.
NATIONAL ENERGY BOARD
49
F I G U R E
6 . 5
Oil Sands Projects
Athabasca
17
16
18 19
20
26
23
22
21
24
25
Fort McMurray
15
Peace River
12
11
10
9
13
Oil Sands Area
Oil Sands Deposits
14
Oil Sands Projects
1- CNRL — Wolf Lake
2- OPTI — Cold Lake
3- Imperial — Cold Lake
4- Murphy — Lindbergh
5- CNRL — Lindbergh
6- Pan Canadian — Lindbergh
7- Pan Canadian — Elk Point
8- Husky Oil — Frog Lake
9- CNRL — Brintnell
10- Pan Canadian — Pelican Lake
11- JCOS — Hangingstone
12- Gulf — Surmount
13- Pan Canadian — Christina Lake
14- AEC — Foster Creek
15- Shell — Peace River
16- CNRL — Mic Mac
17- Koch — Fort Hills
18- Syncrude — Aurora North
19- MobilExxon — Kearl Lake
20- Shell — Muskeg
21- Petro Canada — MacKay River
22- Syncrude — Mildred Lake
23- Syncrude — Aurora
24- Suncor
25- Suncor — Millennium
26- Suncor — Firebag
1
2
3
Cold Lake
4
5
8
6
7
Alberta
Syncrude 21
Syncrude is Canada’s largest single source of crude oil and the world’s largest oil sands producer. The
Syncrude Project is a joint venture operated by Syncrude Canada Ltd. and owned by AEC Oil Sands
L.P., AEC Oil Sands Limited Partnership, Athabasca Oil Sands Investments Inc., Canadian
Occidental Petroleum Ltd., Canadian Oil Sands Investments Inc., Gulf Canada Resources Ltd.,
Imperial Oil Resources, Mocal Energy Ltd., Murphy Oil Company Ltd. and Petro-Canada.
50
AN ENERGY MARKET ASSESSMENT
Syncrude 21 project will be designed and constructed from 1998 to 2007 and represents more than a
$6 billion investment. Once this four-staged expansion is complete production will be more than
double the 1999 output of 35 400 m3/d, reaching approximately 73 800 m3/d in 2008.
Athabasca Oil Sands
This project is a joint venture, with Shell retaining a 60 percent interest and Chevron Canada
Resources Limited and Western Oil Sands Inc. each holding a 20 percent interest. The mine will be
constructed about 70 kilometres north of Fort McMurray. The Scotford Upgrader will be
constructed next to Shell’s existing Scotford Refinery near Edmonton. The upgrader will use
hydrogen addition technology to process the bitumen from the Muskeg River Mine. Shell will also
invest approximately $400 million to modify its existing Scotford Refinery to utilize the new synthetic
crude produced by the Scotford Upgrader.
As well, several companies will construct new facilities to serve the needs of the Athabasca Oil Sands
Project under long term agreements. The Corridor Pipeline will transport the diluted bitumen from
the mine to the upgrader (see Chapter 7.5). ATCO Power will build a 170 megawatt cogeneration
facility to provide steam and electricity to meet the requirements of the mine, as well as additional
electricity to the Alberta grid. ATCO Pipelines will build a pipeline to transport natural gas to the
cogeneration facility.
Fort Hills
The Fort Hills Project is owned by TrueNorth Energy L.P. with a 78 percent share and UTS Energy
holding the remaining 22 percent. The company estimates there are approximately 317 million cubic
metres of mineable bitumen, providing reserves for 60 years of operation. A feasibility study will be
completed by the end of 2000, with a commitment to a “go-no-go” decision on the development by
early 2002 pending regulatory approval. A full scale upgrading facility is not planned at the Fort Hills
site. TrueNorth may also pursue SAGD opportunities on the lease in areas where the overburden is
too thick for mining.
Kearl Oil Sands
Kearl Oil Sands is an oil sands mining project proposed by ExxonMobil Corporation (ExxonMobil)
on its Athabasca oil sands lease, located about 70 kilometres north of Fort McMurray. ExxonMobil
believes the lease contains a high quality ore body with over 238 million cubic metres of recoverable
bitumen in place. The project is currently on hold as ExxonMobil considers its options.
6.4.2
Other Mining Projects
The Mic Mac lease owned by CNRL has a production potential of 47 500 m3/d. This lease contains
an estimated 400 million cubic metres of oil sands reserves. The Mic Mac Project would likely be
developed using both mining and in situ production methods with two-thirds of the production from
mining and the remainder from SAGD.
SynEnCo Energy Inc. is proposing to build an oil sands mine and extraction plant 100 kilometres
north of Fort McMurray. The plant is scheduled to begin operation in 2004, and has a rated
production of 3 200 m3/d. SynEnCo is proposing to use coal instead of natural gas to meet the
project’s fuel requirements.
NATIONAL ENERGY BOARD
51
6.4.3
In Situ Projects
Gulf Canada - Surmont
Commercial Oil Sands
T A B L E
6 . 2
Athabasca In Situ Projects
Project
Estimated Cost
Description
Gulf Canada Resources Ltd.
Phase 1
This project is located
Phase 1: 4 000 m3/d by 2005.
Surmont
(SAGD)
Developments in phased expansions of
$300
million
about 60 kilometres
4 000 m3/d with an ultimate capacity of
southeast of Fort
16 000 m3/d by 2013 given favourable
McMurray. The oil sands
market conditions.
formation is between 300
PanCanadian Petroleum
Initial
Phase 1: 1 600 m3/d by about 2002.
and 400 metres below the
Limited - Christina Lake
$400 million
Phase 2 and 3 both add 4 750 m3/d,
surface with thickness
(SAGD)
and are dependent on the success of
varying from zero to
Phase 1. If all three phases proceed
60 metres. Each phase
production would be 11 100 m3/d in
will have its own central
2007.
facility consisting of
Petro-Canada
$290 million
Expected to start producing in late 2002
steam generators, water
MacKay River (SAGD)
reaching full production of 4 750 m3/d
recycling facilities,
in 6 to 8 months after start up.
emulsion treating and
Suncor Energy Oil Sands $450 million
Up to 5 500 m3/d of bitumen in 2004.
storage tanks for diluent
Firebag (SAGD)
Plans to increase in situ production in
and blended bitumen
stages to 22 000 m3/d by the end of
ready for transport to
the decade.
market. Each phase of
the development will be
connected by pipeline to allow water, diluent and bitumen to be shipped between any of the locations.
The Surmont project was the subject of an EUB hearing into Gulf Canada’s claim that the
production of the natural gas reserves situated above their project was detrimental to oil sands
recovery. The EUB ruled that the bitumen should be protected for development and ordered
production to cease on 146 natural gas wells in the Surmont area.
PanCanadian - Christina Lake
PanCanadian Petroleum Limited will use the SAGD method at the Christina Lake project located
approximately 170 kilometres south of Fort McMurray. This lease covers 35 sections which contains
an estimated 475 million cubic metres of bitumen. Each of the three phases will have its own plant
facility consisting of water treatment, steam generation, production separation, heat recovery, water
de-oiling, water disposal and oil facilities. The project will begin steaming in the fall of 2001.
Petro-Canada - MacKay River
This project is located about two kilometres east of the Underground Test Facility which is now
known as the Dover project. Due to the success of the Dover project, Petro-Canada believes it can
successfully take the project directly to a commercial development without having a pilot project. At
the MacKay River site there is approximately 125 metres of overburden. At this depth it is too deep
for mining but too shallow for CSS. Petro-Canada must drill the vertical portion of the well at
45 degrees followed by the horizontal portion because of the shallow formation. MacKay River has a
projected recovery of an estimated 37 to 48 million cubic metres of bitumen over a 25 year project
life span.
52
AN ENERGY MARKET ASSESSMENT
Suncor - Firebag In Situ Oil Sands
Suncor will use the SAGD technique on its in situ oil sands leases located approximately
40 kilometres northeast of the company’s oil sands plant. Suncor’s combined oil sands leases have an
in situ recovery potential of 800 million cubic metres of bitumen. The oil sands deposits in this area
lie about 250 metres beneath the surface in the McMurray Formation. The raw production from
Suncor’s open-pit mine and from the proposed in situ project can be combined and sold directly to
market or used as a feedstock in the oil sands upgrading facility. To give Suncor the capability to
process the additional bitumen, the company plans to expand its upgrading facility by adding a
vacuum tower complex by 2004 to coincide with production from the in situ facility.
6.4.4
Other Projects
Japan Canada Oil Sands Co., Ltd. will use SAGD at its Hangingstone property to produce up to
1 600 m3/d by 2002. Northstar Energy Corporation is planning to increase production to 500 m3/d at
its Dover Project. Ormat Industries Ltd. (OPTI) is planning a 4 750 m3/d in situ production
operation southeast of Fort McMurray. AEC is operating a pilot project at Pelican Lake that is
currently producing about 500 m3/d. CNRL is considering a significant expansion of its primary
bitumen production at Brintnell and Pelican Lake.
6.5
Cold Lake Deposit
6.5.1
In Situ Projects
T A B L E
6 . 3
Imperial - Cold Lake
Cold Lake is owned and
operated by Imperial Oil
Estimated
Limited.
Laboratory and
Project
Description
Cost
field research projects
$630 million Phases 11-13 (Mahkeses) will increase
Imperial Oil Limited
over the past 30 years led
Cold Lake (CSS)
bitumen production by 4 750 m3/d.
to this phased
Imperial is also considering phases 14-15
commercial production
for future expansion plans.
project. Since the oil
$230 million The first phase of 3 200 m3/d of bitumen
Alberta Energy Company
sands at Cold Lake are
in 2002. Plans call for Foster Creek to be
Foster Creek (SAGD)
buried too deeply within
producing 16 000 m3/d by 2007.
the Clearwater Formation
$130 million With improvements to facilities and
Canadian Natural Resources
for surface mining,
operating strategies it is expected to reach
Ltd. Primrose and Wolf Lake
Imperial applies cyclic
(CSS & SAGD)
full capacity of 9 500 m3/d by 2001.
steam stimulation (CSS).
Imperial currently
Two-phased plan, Phase 1 with
operates phases one
completion in mid-2003 will add about
through ten of the Cold
4 750 m3/d. Phase 2, additional
4 750 m3/d, will follow and take two
Lake facility. In 1999,
years to complete.
Imperial’s Cold Lake
production averaged
20 700 m3/d accounting for almost half of the bitumen produced in Alberta. Imperial has also
planned a 220 megawatts steam cogeneration and electrical power facility at Cold Lake. Imperial
expects to use about 45 percent of the power at the plant and will make the surplus power available to
the Alberta Power Pool.
Cold Lake In Situ Projects
NATIONAL ENERGY BOARD
53
Alberta Energy Company (AEC) - Foster Creek
AEC’s Foster Creek is located north of Wolf Lake in the middle of the Primrose Lake Air Weapons
Range. AEC has been testing its SAGD extraction method for four years at its 300 m3/d pilot
project. The first phase will require 24 well pairs, a water treatment plant, an oil treatment unit, a
testing centre and steam generators. Depending on market conditions and the success of the project,
AEC has long range plans for Foster Creek to be producing 16 000 m3/d by 2007.
CNRL - Primrose and Wolf Lake
CNRL’s Primrose and Wolf Lake thermal heavy oil projects are located approximately 55 kilometres
north of Bonnyville in northeastern Alberta. These properties, which CNRL purchased from
BP Canada Energy Company (BP) in 1999, have been operating commercially since the 1980s.
Currently, the production facilities are operating at about 50 percent of capacity.
CNRL will use both CSS and SAGD recovery techniques. CSS is used to target the Clearwater
formations higher-clay content sands, while SAGD is used in the Grand Rapids zone which has fewer
clay impurities. Their CSS process involves drilling horizontal wells rather than vertical or slant
wells and injecting steam at a rate above the required reservoir parting pressure. The higher pressure
will allow steam to penetrate farther into the oil sands allowing for fewer wells, reduced number of
cycles and increased production. By drilling horizontally through the deposit, CNRL will be able to
minimize both cost and surface disturbance by substituting a single well for between five and ten
conventional wells.
6.5.2
Other Projects
There are several other projects in the Cold Lake area. AEC is operating a pilot project at Frog
Lake. BlackRock Ventures Inc. has a pilot project at Cold Lake with potential for expansion up to
5 400 m3/d by 2010. CNRL also has primary production at Beartrap. Murphy Oil Company Ltd.
has primary production in the Lindbergh area with potential to more than double current production.
CNRL also operates a SAGD pilot project at Burnt Lake which produces about 400 m3/d. Petrovera
Resources Limited operates primary bitumen production at Elk Point, Lindbergh, Frog Lake and
Marwayne with significant expansion potential.
6.6
Peace River Deposit
Peace River
The Peace River project is owned by Shell Canada Limited. This site has an estimated 1.6 billion
cubic metres of bitumen in place. Shell operated a pilot project at this site from 1979 to 1992 which
was considered a technical success. More recently, Shell has used both CSS with multi-lateral wells
and SAGD. Between 1997 and 1999, Shell produced about 1 000 m3/d. Shell continues to assess the
feasibility of a phased expansion.
6.7
Synergistic Development
Oil sands developers are taking advantage of new opportunities and technologies as well as synergies in
their operations, in order to improve the economics and environmental performance of their projects.
An example of this is cogeneration, which is the generation of hot water or steam and electric power at
the same time from the same energy source, thereby yielding a highly efficient power plant.
54
AN ENERGY MARKET ASSESSMENT
In a conventional power
T A B L E
6 . 4
plant, waste heat in the
Current Cogeneration Facilities
form of turbine exhaust
gases or condenser
Capacity
Company
Location
cooling water is rejected
(MW)
to the environment.
TransAlta Utilities
Syncrude
265
With a cogeneration
Mildred Lake
facility, a large portion of
TransAlta Utilities
Suncor
360
the waste heat is
Poplar Creek
recovered and utilized by
an adjacent facility which
requires large amounts of
heat. Cogeneration
provides a cost-effective
ATCO Power / Shell
Shell’s Scotford
150
option for producing
Canada / Air Products
Upgrader
electricity, considering
CU Power Canada Ltd.
Shell’s Muskeg
170
the increased efficiency
River Mine
of energy conversion and
TransAlta Utilities
Imperial
220
use. Additionally,
Cold Lake
cogeneration lowers
emissions to the
environment, carbon
dioxide (CO2) in
particular, by capturing and recycling waste heat.
Description
In operation since 1978.
Construction from 1999-2001.
Phase 1 (220 MW) completed.
Two steam turbines to be
added in 2000 and 2001 to
coincide with Suncor’s
Millennium project.
Construction from 2000-2002.
Construction from 2001-2002.
Construction from 2000-2001,
45 percent of the power
needed onsite, remainder
goes to the Alberta power grid.
Table 6.4 lists the cogeneration facilities associated with integrated mining plants or in situ bitumen
projects. The table includes projects currently in operation and those scheduled to be on stream by 2002.
The supply projections for the Base Case indicate that production of synthetic crude oil and bitumen
will increase by about one and one-half times current levels by 2015. The integrated mining plants
and thermal in situ projects use natural gas to generate process heat and electric power for their
operations. Although improvements in energy efficiency are anticipated, the increase in natural gas
demand by these operations will still be substantial.
An assessment was undertaken to examine the impact of the projected rapid growth of synthetic crude
oil and bitumen production on natural gas and electrical power requirements, including an estimate
of the electrical power that will be available to the Alberta power grid.
This assessment consisted of estimating the energy use and energy intensity, on a per unit of
production basis, of current integrated mining/upgrading operations as well as in situ operations
(both thermal and primary) and existing cogeneration plants. These estimates, together with certain
assumptions, were applied to the Base Case supply projections.
The main components of this assessment are:
• current data on natural gas, electricity and internally-generated fuel usage for existing
integrated mining/upgrading plants;
• consideration of the planned configuration of proposed new projects;
• energy efficiency data for typical gas turbines used in cogeneration facilities; and,
1 35.3 cubic feet of gas equals approximately one cubic metre.
NATIONAL ENERGY BOARD
55
• the assumption that a two percent per year improvement in energy efficiency would be
achieved, and for in situ bitumen, the assumption that one-third of incremental bitumen
production will have associated cogeneration facilities.
The results of this assessment indicate that the external natural gas requirements related to integrated
mining/upgrading operations more than double from current levels by 2008, reaching 0.38 bcf/d,1
then decrease gradually to the end of the projection period (Figure 6.6a).
Natural gas demand for in situ bitumen production, including primary production, increases steadily,
reaching 0.65 billion bcf/d by 2015 (Figure 6.6b).
F I G U R E
6 . 6 A
Daily Natural Gas Requirement - Integrated Mining/Upgrading Plants
Gas Requirement (Bcf)
0.5
0.4
0.3
0.2
0.1
0.0
2000
2003
2006
2009
2012
2015
Total Gas Requirement (Bcf/d)
Total Gas (Bcf/d) Required for Plant Operation
F I G U R E
6 . 6 B
Daily Natural Gas and Electrical Power Requirements In Situ Projects
Gas Requirement (Bcf)
Electrical Power (GW.h)
20.0
1.0
0.8
15.0
0.6
10.0
0.4
5.0
0.2
0.0
2000
56
0.0
2003
2006
2009
2012
Electricity Requirement
Electricity Available to Grid
Electricity Generation
Gas Requirement
2015
AN ENERGY MARKET ASSESSMENT
F I G U R E
6 . 6 C
Daily Electrical Power Requirement - Integrated Mining/Upgrading Plants
Electrical Power Requirement (GW.h)
30
25
20
15
10
5
0
2000
2003
2006
2009
2012
2015
Total Power Gereration (GW.h)
Power Generation Requirement for Plant Operation(GW.h)
Power Available to Power Grid (GW.h)
Total natural gas demand for mining and in situ operations is estimated to reach 0.98 bcf/d by 2015,
compared to the current value of 0.46 bcf/d. By comparison, in 1999, Alberta natural gas production
averaged 13.6 bcf/d.
The cogeneration facilities installed in association with the oil sands projects are estimated to have some
excess capacity to generate power, that could be made available to the Alberta power grid. This excess
daily capacity rises to about 13 GW.h by 2015 (Figure 6.6b and 6.6c). This excess capacity would
generate about 4.8 TW.h annually, compared to current provincial annual generation of about 54 TW.h.
TransCanada Midstream Offgas Extraction Project
This is an agreement between Suncor and TransCanada Midstream to extract and separate natural gas
liquids (NGL) and olefins from “off-gas,” a byproduct of the oil sands upgrading process that is
currently used as a fuel. The recovered liquids and olefins will be transported in batches via Suncor’s
Oil Sands Pipeline to TransCanada’s Redwater, Alberta fractionation facility for further processing.
The agreement will provide revenue to Suncor from the sale of products and reduce sulphur dioxide
emissions at Suncor, as the off-gas is replaced as a fuel by cleaner burning natural gas. The plant,
which is scheduled for commissioning in 2001, will extract ethane, propane, butane, condensate,
ethylene, propylene and butylene from the off-gas. There is the potential to extract almost 3 000 m3/d
of NGLs and about 70 000 metric tonnes per year of polymer grade propylene from the off-gas.
Minerals and Precious Metals
A variety of valuable minerals, including precious metals, are known to exist within the oil sands deposits.
A number of ventures have proposed methods of extracting these minerals from current tailings ponds or
as a part of oil sands mining projects. While no operation of this type is currently operating,
assessment and economic feasibility studies are being conducted.
NATIONAL ENERGY BOARD
57
Upgrading
The incremental supply cost of expansion at both Syncrude and Suncor is significantly lower than
that of new grassroots projects due to the presence of existing upgraders and associated facilities. As
another example, Shell is taking advantage of the synergies gained by building an upgrader next to its
Scotford refinery.
6.8
Conclusion
The anticipated rapid growth in oil sands derived crude oil production is testament to the massive
resource and economic potential of Canada’s oil sands and the confidence shown by producers in the
form of financial commitment and the development and advancement of enabling technologies.
In the Base Case, synthetic crude oil production is projected to increase nearly three-fold compared
to current levels, reaching 158 000 m3/d by 2015. Similarly, bitumen production is projected to
increase by two and one-half times current production by 2015, reaching 104 000 m3/d by 2015.
Considering the declining trend in conventional heavy and conventional light crude oil production in
Western Canada, oil sands production could be over 50 percent of total Canadian crude oil
production by 2015.
A shortfall of pentanes plus for purposes of blending bitumen could occur as early as 2005, given the
Base Case supply projections. This problem has the potential to constrain bitumen production, given
that solutions currently available represent a significant added expense for producers.
The net available supply of Canadian crude oil, in the Base Case, rises to 502 000 m3/d in 2008, then
gradually declines to about 490 000 m3/d by 2015. In the $22 Sensitivity, the net available supply
includes production from the Mackenzie Delta-Beaufort Sea region and reaches a peak of about
606 000 m3/d before declining slightly by the end of the projection period. In the $14 Sensitivity, the
net available supply decreases to 314 000 m3/d by 2015, or about 5 percent below current levels.
An assessment of natural gas requirements and electrical power generation related to oil sands
development indicated that gas requirements would double to nearly 1 bcf/d by 2015, and that about
4.8 TW.h of generating capacity would be available to the Alberta power grid, also by 2015. This
represents about 7 percent of Alberta’s 1999 gas production and about 9 percent of its 1999 power
generation capacity.
References
a) Oil and Gas Exploration and Extraction Estimation Model (OGEEE), Version 6.4, by
CCH Consulting. This model forecasts activity based on historical relationships between
several variables, such as, commodity prices, cash flow, resource potential, capital and
operating costs, production rates as well as certain financial variables (inflation, interest and
exchange rates).
Selected Background Literature
Athabasca Oil Sands Developers, “Progress in Canada’s Oil Sands.” June 2000.
58
AN ENERGY MARKET ASSESSMENT
C
H
A
P
T
E
R
S
E
V
E
N
P IPELINES
7.1
Introduction
This chapter presents a discussion of the location and capacity of the pipelines that transport crude
oil in Canada and to the United States. Also included is a discussion on proposed pipeline projects
that have been announced to transport increasing crude oil production.
7.2
Alberta Hubs
The various feeder pipelines that gather and transport blended bitumen and synthetic crude oil from
northern Alberta converge at two main hubs, located at Edmonton and Hardisty (Figure 7.1). From
these hubs, crude oil is shipped in segregated batches on trunklines that serve the various markets in
Canada and the United States.
The Edmonton hub has approximately 900 000 cubic metres1 of storage capacity, and receives various
types of crude oil from numerous feeder pipelines. The crude oil is shipped from the Edmonton hub
on two main trunklines. Enbridge Pipelines Inc. (Enbridge) is the major carrier of crude oil to
eastern Canadian and U.S. markets, while the Trans Mountain Pipe Line Ltd. (Trans Mountain)
system moves crude oil to the west coast. In many instances, light crude oil received from the feeders
is co-mingled and shipped as a blend.
The Hardisty hub is located 220 kilometres southeast of Edmonton, and connects several feeder
pipelines with the Express Pipeline Ltd. (Express) trunkline and the Enbridge system. It has a storage
capacity of about 740 000 cubic metres.
With an estimated 190 000 m3/d of synthetic crude oil and bitumen production proposed to come on
stream before the year 2010, several new pipeline projects have either been recently completed, are in
various stages of construction, or awaiting regulatory approval.
7.3
Feeder Pipelines
Alberta Oil Sands Pipeline
Alberta Oil Sands Pipeline (AOSPL), owned by AEC Pipelines, runs from the Syncrude plant in Fort
McMurray to Edmonton (Figure 7.1), with a spur connection to Shell’s Scotford refinery near
Edmonton. Originally at a capacity of 37 800 m3/d, AOSPL expanded in 1998 to 43 700 m3/d.
1 One cubic metre (m3) of crude bitumen is approximately equal to 6.3 barrels or one metric tonne.
NATIONAL ENERGY BOARD
59
F I G U R E
7 . 1
Feeder Pipelines
Athabasca
Terminal
E
LD
CO
D
AC
NOR
H
T
EP
IPE
TRANS M
OUNTAIN
SA
SK
AT
C
Edmonton
Terminal
H E WAN RIVER
HU
ATHABASCA
PE
LAK
PEMBINA
BR
IE
G
NN
CH
KO
LE
N
ID
GE
BOW RIVER
EN
BO
COLD LAKE
RA
TE
ATHABASCA
DE
SUNCOR
BOW
RAIN
FE
AOS
COR
RIDO
R
ALBERTA
SASKATCHEWAN
ATHABAS
C
A R IV E R
FORT
McMURRAY
Y
Hardisty
Terminal
GIBSON
SK
HU
SK
Y
LLOYDMINSTER
BATTLE
RIV
E
R
BP
Athabasca Pipeline
The Athabasca Pipeline, owned by Enbridge, commenced operations in the spring of 1999. This
76 centimetre pipeline can ship about 15 900 m3/d of synthetic crude oil and blended bitumen from
Fort McMurray through Cold Lake and into the Enbridge and Koch Hardisty terminals.
The pipeline could be expanded to 90 500 m3/d by adding pump stations. Expansion will only occur
after transportation agreements have been executed with shippers.
60
AN ENERGY MARKET ASSESSMENT
Cold Lake Pipeline
The Cold Lake Pipeline System, owned by AEC Pipelines L.P., Koch Pipelines Canada L.P. and
CNRL, has a capacity of 40 900 m3/d. This partnership has entered into long term shipping contracts
with Imperial, AEC, CNRL and Koch. The system consists of a 60 centimetre pipeline moving
blended bitumen from the Cold Lake area to Edmonton and a 30 centimetre diluent return line.
Pelican Lake Pipeline
Pelican Lake Pipeline, owned by AEC, CNRL, PanCanadian and Chevron Canada, has a capacity of
23 800 m3/d. It carries blended heavy crude oil from Pelican Lake to terminals in both Wabasca and
Mitsue, and into the Rainbow pipeline for delivery to the Edmonton hub. Completed in June 1998,
Pelican Lake pipeline began operations at 4 800 m3/d.
ECHO Pipeline
ECHO Pipeline is owned by CNRL and Gibson Petroleum Company Ltd. The 150 kilometre
pipeline transports heavy crude oil from the Elk Point area south of Cold Lake to the Gibson
terminal at Hardisty. The 30 centimetre diameter pipeline is unique in that it is insulated and has a
mid-point booster/heater that preserves the heat contained in the crude oil, allowing it to be
transported without the addition of condensate at the originating point. Blending of condensate with
the crude oil occurs at Gibson’s Hardisty terminal to meet shipper requirements and downstream
Enbridge and Express pipeline specifications. The ECHO pipeline has a capacity of 8 600 m3/d.
Husky Pipelines
Husky Pipelines, owned by Husky Oil, has several gathering pipelines that transport blended heavy
crude oil production from Cold Lake and west central Saskatchewan to the Husky upgrading and
refining facilities at Lloydminster, Alberta or to the Hardisty hub.
Manito Pipeline
Manito Pipeline is owned by Murphy Oil Company Ltd. and Van Horne Pipeline Limited. It
consists of a 25 centimetre pipeline moving blended heavy crude oil south to the Kerrobert,
Saskatchewan terminal for injection into the Enbridge system, with a small ten centimetre pipeline
moving condensate northbound to Dulwich, Saskatchewan.
Rangeland Pipeline
Rangeland Pipeline, owned by BP, is supplied by the Federated, Pembina, and Imperial pipelines.
Rangeland has a Sundre to Rimbey mainline connecting to the Imperial pipeline, which runs north to
Imperial’s Edmonton refinery. Rangeland also runs south from Sundre to the U.S. border at
Montana, where it connects to the Conoco pipeline which supplies Billings, Montana and Salt Lake
City, Utah markets. Rangeland delivers mainly light crude oil and pentanes plus, but also ships Cold
Lake blend crude oil from the Imperial pipeline for delivery into Billings. With a capacity of
16 500 m3/d, the Conoco pipeline delivers crude oil into the Great Falls, Montana and Billings
markets. At Cutbank, Montana the Conoco system intersects with the Front Range pipeline, which
carries Bow River crude oil from the Milk River pipeline.
Crude oil produced in Wyoming is also carried on the Conoco and ExxonMobil pipelines. However,
as a result of the natural decline in local production over the last five to seven years, only half of the
11 600 m3/d capacity has been utilized to serve the Billings market.
NATIONAL ENERGY BOARD
61
Conoco also has a pipeline running from Guernsey, Wyoming to Denver, Colorado supplying up to
12 700 m3/d of crude oil to the Frontier refinery in Cheyenne, Wyoming, and up to 9 500 m3/d of
crude oil to the Conoco and Ultramar Diamond Shamrock refineries in the Denver area.
Bow River Pipeline
The Bow River Pipeline, owned by Koch Pipelines Canada LP, runs south from Hay River, Alberta to
the Murphy Milk River pipeline, which is connected to the Front Range Pipeline, where it serves the
Billings and Salt Lake City markets. It has a capacity of 15 900 m3/d and ships medium and heavy
crude oil. The Bow River Pipeline also runs north from Hay River to the Hardisty hub.
Koch is contemplating reversing one of its three northbound pipelines to ship heavy crude oil south
into the Billings market. Depending on the crude oil type, the reversed pipeline would have a
capacity of 4 000 to 4 800 m3/d. The earliest startup date would be the first quarter of 2001 to
accommodate the asphalt season.
Milk River Pipeline
The Milk River Pipeline, owned by Murphy Oil Company Ltd., delivers crude oil mainly from the
Bow River pipeline and the Manyberries pipeline into the Conoco system by way of the Front Range
Pipeline in northern Montana. Milk River has a capacity of about 15 900 m3/d.
Wascana Pipeline
The Wascana Pipeline, owned by Murphy Oil Company Ltd., has a capacity of 7 900 m3/d. It runs
from the Enbridge system at Regina, Saskatchewan to the United States border in eastern Montana
where it connects to the Equilon pipeline system. The Equilon pipeline is connected to the Butte
system, which delivers crude oil into Guernsey or Casper, Wyoming through the Belle Fourche
Pipeline. Crude oil moved on Wascana can ultimately be delivered to the Salt Lake City area, or east
to the Wood River region via the Platte pipeline.
The Equilon and Butte pipelines each have a capacity of approximately 17 500 m3/d, and supply both
Canadian and U.S. domestic crude oil to the Guernsey and Casper hubs.
7.4
Trunklines
Enbridge Pipelines Inc.
Enbridge Pipelines Inc., owned by Enbridge Inc., has a total capacity of approximately 350 000 m3/d.
Enbridge is the primary transporter of crude oil from western Canada to Ontario and the United
States (Figure 7.2). It receives crude oil at Edmonton and Hardisty, Alberta; Kerrobert and Regina,
Saskatchewan; and Cromer, Manitoba. Enbridge serves the major refineries in Ontario and the Great
Lakes region of the U.S. through the Lakehead pipeline system. This region is the largest market for
all types of Canadian crude oil.
Enbridge also ships refined petroleum products from Edmonton to Saskatchewan and Manitoba, and
transports natural gas liquids from Edmonton, Kerrobert, and Cromer to Sarnia, Ontario as well as
various locations in the U.S. midwest. It has four parallel pipelines running from Edmonton to
Hardisty and into the U.S. midwest. Enbridge serves the U.S. Rocky Mountain area indirectly via its
connections to Express pipeline at Hardisty and the Wascana system at Regina.
62
AN ENERGY MARKET ASSESSMENT
F I G U R E
7 . 2
Major Canadian and U.S. Crude Oil Pipelines and Markets
Fort McMurray
Cold Lake
Edmonton
Riv
er
Kerrobert
n
Ce
ex
Enb
e
Clearbrook
oc
o
PADD IV
Am
Frontier
Mandan
e9
Lakehead
Sarnia
PADD II
BP Amoco
Salt Lake
City
Portland
En
Guernsey,
Ft. Laramie
Casper
in
eL
dg
bri
St. Paul
Expre
Koch
o
oc
BP
Montréal
Superior
Enbridge
moc
o
BP A
Billings
Toledo
Chicago
ss-Pla
tte
Patoka
as
x
Te
Denver
-N
Wood
River
ew
Capline
ico
ex
M
Cushing
PADD I
Mid V
alley
PADD V
Portland Montreal
ridg
n
Co
Cutbank
Regina
Cromer
Wa
sca
na
Anacortes
Express
M
Hardisty
Bow
ns
a
Tr
Ran
gela
nd
o
Vancouver
Lloydminster
n
ai
t
un
PADD III
Midland
St. James
Houston
Port Arthur
The Lakehead system is 15.3 percent owned by Enbridge, and connects to the Enbridge pipeline at
the Canada/U.S. border in southern Manitoba. The Lakehead pipeline delivers crude oil directly to
the large Chicago, Illinois market, and north to Sarnia, Ontario. The Lakehead system also connects
to other pipelines, including the 30 percent Enbridge owned Mustang Pipe Line Partners system,
which delivers western Canadian crude oil into the Patoka and Wood River, Illinois hubs. In
addition, it connects to the Minnesota pipeline, which ships crude oil to refineries at Twin Cities,
Minnesota.
Enbridge experienced apportionment during most of the 1990s, reflecting substantial increases in
heavy and synthetic crude oil production. As a result, Enbridge proposed three expansions. The first
expansion (Terrace Phase I), completed in early 1999, added about 27 000 m3/d of capacity.
Phase II and Phase III of the Terrace expansion project propose to further increase capacity on the
Enbridge system. The Phase II expansion, proposed for the fourth quarter 2001, will provide
incremental capacity of 6 300 m3/d. Phase III, proposed for the fourth quarter 2002, will add a
further 22 200 m3/d of new capacity. It should be noted that the timing and capacity of the
expansions are subject to shipper commitments.
If all phases proceed, the Terrace expansion project would provide 55 500 m3/d of additional capacity
on the Enbridge system.
Trans Mountain Pipe Line Ltd.
Trans Mountain is a subsidiary of BC Gas Inc., and has a total capacity of 39 300 m3/d. Trans
Mountain delivers crude oil from the Edmonton hub and Kamloops, B.C. to the Chevron refinery in
Vancouver, B.C.. As well, it ships refined petroleum products to terminals in Vancouver and
Kamloops from the Edmonton refineries. Trans Mountain also ships Canadian crude oil through its
NATIONAL ENERGY BOARD
63
subsidiary pipeline at Sumas, Washington to Washington State refiners, as well as through its
Westridge dock facility to other west coast and offshore refiners. Its export capacity is estimated to
be 19 000 m3/d. Trans Mountain currently ships small volumes of synthetic crude oil.
Express Pipeline Ltd.
Express Pipeline, owned by AEC, is a 27 300 m3/d trunkline that commenced operations in April
1997. It runs from Hardisty to markets in Guernsey and Salt Lake City. Express also owns the Platte
pipeline, which it connects to at Casper. At the Casper hub, Platte transports Canadian crude oil and
U.S. domestic crude oil from the Conoco and ExxonMobil pipelines in Montana to the Wood River
market. In Missouri, the Platte pipeline intersects with the ARCO system that runs from Cushing,
Oklahoma to the Chicago market. Platte’s terminals at Casper and Guernsey have a total storage
capacity of about 254 000 cubic metres.
Express is proposing to serve two new markets. The first is Kansas, which will be supplied by the
new Holdrege, Nebraska connection, which is expected to be in operation by December 2000. This
is anticipated to take 1 600 m3/d of Express/Platte capacity, providing shippers with access to the
Kansas refining market of over 46 000 m3/d. The second connection to Billings, Montana, should
begin operations in the second quarter of 2001 and utilize 1 600 m3/d of pipeline capacity, providing
shippers with access to 23 800 m3/d of refining capacity.
As well, Express is forecasting an expansion to its baseload capacity of about 7 900 m3/d in January
2002, adding another 9 500 m3/d in January 2004 bringing total capacity at Hardisty to about
44 400 m3/d.
7.5
New Pipelines
Figure 7-1 illustrates both the existing and proposed feeder pipelines. The proposed projects are
described below.
Corridor Pipeline
The Corridor project, owned by Trans Mountain, will consist of three pipelines. The first pipeline
will run from Shell’s Muskeg River Mine near Fort McMurray to Shell’s Scotford refinery near
Edmonton, and will carry 34 100 m3/d of diluted bitumen. The second pipeline will be a 10 300 m3/d
return pipeline for diluent. This grassroots system is scheduled to be completed in 2002.
The third pipeline will transport 23 000 m3/d of synthetic crude oil from the Scotford refinery to the
Edmonton hub. It will include a return pipeline for 19 000 m3/d of supplementary feedstock. This is
also expected to be completed in 2002.
Also committed to this project, according to Trans Mountain, is oil sands production from Syncrude,
Suncor, Shell and JACOS. Trans Mountain also expects that oil sands output from the Petro-Canada,
Koch and Gulf projects will utilize this pipeline.
Cold Lake Pipeline
The existing Cold Lake Pipeline System which transports crude oil to Edmonton will be expanded
with the construction of a new 60 centimetre pipeline to transport heavy oil from the Cold Lake area
to Hardisty where it will connect with the Express Pipeline System, Koch Hardisty terminal and
other facilities. This new pipeline, owned by AEC Pipelines L.P., Koch Pipelines Canada L.P. and
64
AN ENERGY MARKET ASSESSMENT
CNRL, will have an initial capacity of 31 750 m3/d and is expected to be on stream in January 2002.
In addition, the system will be extended north to AEC’s Foster Creek SAGD project.
7.6
Conclusion
With the completion of projects described in this chapter there will be a substantial increase in feeder
pipeline capacity to transport synthetic crude oil and blended bitumen into the Edmonton and
Hardisty hubs. Trunkline capacity to move crude oil out of Alberta to the various markets will
increase by 45 900 m3/d by January 2004, if all announced proposals proceed.
Based on the estimated production of synthetic crude oil and bitumen over the next 15 years, it is
expected that additional trunkline capacity will be added. Proposals have been announced by Express
and Enbridge to serve key markets in Ontario, PADD II and PADD IV (Table 7.1).
The pace of pipeline capacity
expansion is dependent on
market conditions, and it is
difficult to precisely predict the
order and timing of these
proposals. However, producers
will attempt to penetrate the
most economical markets which
historically have been Ontario
and the U.S. midwest, and more
recently PADD IV.
NATIONAL ENERGY BOARD
T A B L E
7 . 1
Announced Trunkline Capacity Expansions
Capacity Increase
Completion
Enbridge
6 300 m3/d
4Q/2001
Express
7 900 m3/d
Jan/2002
Enbridge
22 200 m3/d
4Q/2002
Express
9 500 m3/d
Jan/2004
65
C
H
A
P
T
E
R
E
I
G
H
T
M ARKETS
8.1
Introduction
The production of Canadian synthetic crude oil and blended bitumen has grown significantly over
the past few years, and this trend is expected to continue. As illustrated in Chapter 6 — Crude Oil
Supply, there will be large increases in synthetic crude oil and blended bitumen production
throughout the forecast period (Figure 8.1).1
It should be noted, however, that conventional light crude oil and equivalent is projected to decline
throughout the forecast period. As well, conventional heavy crude oil output will begin to decline
after 2003. Since the rising volumes of synthetic crude oil and blended bitumen could be expected to
offset these declines, the net increases in synthetic crude oil and blended bitumen will be the focus of
the discussion in this chapter (Figure 8.2).
Currently, three-quarters of Canada’s synthetic crude oil and blended bitumen production is delivered
to domestic refineries, all of which are operating at or close to capacity. Following the reversal of the
Enbridge Sarnia-to-Montreal pipeline (Line 9), Canadian markets for both conventional and
synthetic crude oil have declined, with most Ontario refiners now running significantly more
imported light crude oil. Given this, the U.S. market, with its declining indigenous conventional
crude oil supplies, will be a vital outlet for the additional production of synthetic crude oil and
blended bitumen. It is likely that new U.S. markets will have to be developed.
F I G U R E
8 . 1
Gross Synthetic and Blended Bitumen Production
Thousand m3/d
350
300
250
200
150
100
50
0
1999
2001
2003
Synthetic
2005
2007
2009
2011
2013
2015
Blended Bitumen
1 One cubic metre (m3) of crude bitumen is approximately equal to 6.3 barrels or one metric tonne.
66
AN ENERGY MARKET ASSESSMENT
F I G U R E
8 . 2
Net Synthetic and Blended Bitumen Production
Thousand m3/d
350
300
250
200
150
100
50
0
1999
2001
2003
2005
Synthetic
2007
2009
2011
2013
2015
Bitumen Blend
PADDs II and IV will be the primary growth markets for the rising quantities of synthetic crude oil
and blended bitumen. However, as discussed later in this chapter, the level of market growth is
dependent on several critical factors.
In this chapter, we will examine the various markets for synthetic crude oil and blended bitumen,
including the current market share based on the Board’s 1999 statistical data. The likelihood of
producers finding markets for the additional synthetic crude oil and blended bitumen will also be
discussed.
8.2
Refining/Upgrading
The United States is the largest potential market for the rising volumes of synthetic crude oil and
blended bitumen. However, unless the quality of these non-conventional crude oils improves or
investments are made to upgrade refineries, this market could become saturated.
Synthetic crude oil is a low sulphur feedstock with no residual fuel oil. It does not produce yields
comparable to light sweet conventional crude oil, and therefore large quantities cannot be run in a
traditional refinery. Synthetic crude oil is generally processed in a light crude oil cracking refinery,
and typically represents less than thirty percent of the total crude oil slate. It also has poorer distillate
qualities, resulting in an inferior yield of cracked products.
If refinery modifications are made, more synthetic crude oil could be absorbed in the U.S.
marketplace. Light crude oil refineries are good candidates for conversion through the addition of
hydrocracker facilities. Alternatively, producers could improve the quality of synthetic crude oil
upstream. For example, by increasing the diesel cetane index to a minimum of 40 and improving the
smoke point on distillate, marketability would be significantly enhanced. Additional hydrotreating
would improve the quality of the distillate and gas oil fractions.
Bitumen is very heavy and viscous, and must be blended with diluent to transport it to market. It is
expected that new refinery conversion capacity will have to be added to provide expanded markets for
the increasing volumes of blended bitumen. Expansions to refineries currently processing blended
NATIONAL ENERGY BOARD
67
bitumen and the conversion of light crude oil refineries could be considered. Upgrading at the
source is another possibility. The likelihood of these options is highly dependent on economics and,
specifically, the differential between light and heavy crude oil.
The price differential between light and heavy crude oil, as represented by the spread between the
light Par crude oil at Edmonton and Lloydminster blend at Hardisty, is impacted by many different
factors including seasonality and the available quantities of each grade of crude oil. As more blended
bitumen production comes on stream, periods of oversupply in the traditional heavy oil markets are
likely to develop. In these circumstances, the differential would be expected to widen, which in turn
would stimulate additional upgrading facilities. In order to encourage new refinery residual
conversion capacity in the U.S. Midwest, the differential would have to be maintained at C$6.00 per
barrel or higher for a sustained period of time.
A further inducement to upgrade refinery capacity may occur as a result of a new Canadian government
requirement that sets the amount of sulphur in motor gasoline to be no more than 150 ppm by July
2002, with further reduction to 30 ppm by 2005. This will make it necessary for refineries to invest in
expanding their facilities, and many Canadian refiners are expected to make the change to 30 ppm in
one step, in order to reduce the total capital cost. Most U.S. refiners will also have to make large
investments in order to meet new environmental regulations imposed by the U.S. government. With
these expenditures ahead of them, the question is whether refiners will take advantage of the
opportunity to combine the cost of the enhancements needed to meet the environmental standards with
the upgrading investments required to process a more diverse slate of crude oil.
8.3
Markets for Canadian Crude Oil
8.3.1
Western Canada
In 1999, western Canada was the largest market for synthetic crude oil. There are nine refineries in
western Canada: Chevron, Co-op, Husky (2), Imperial, Moose Jaw Asphalt, Parkland, Petro-Canada
and Shell. The combined refining capacity is about 88 800 m3/d, of which thirty percent represents
synthetic crude oil runs and three percent represents blended bitumen runs (Figure 8.3).
T A B L E
8 . 1
Canadian Crude Oil Markets - 1999 (m3/d)
Canadian
Canadian
Synthetic
Blended
Crude Oil
Bitumen
13 333
27 302
2 540
49 365
14 444
8 571
3 175
74 000
35 050
14 444
8 571
3 175
255 556
18 722
5 183
1 011
25
Refining
Refining
Canadian
Canadian
Capacity
Runs
Light1
Heavy
W. Canada
88 800
83 016
39 841
E. Canada - all
216 200
199 206
E. Canada - Ontario
87 500
PADD I
269 000
Market
PADD II
574 500
574 500
34 740
55 105
14 692
23 842
PADD III
1 198 900
1 197 816
255
0
0
0
PADD IV
85 800
84 247
12 235
20 639
2 119
2 287
PADD V
491 200
477 550
9 704
27
13
56
1
Includes condensate and pentanes plus
Source:
Statistics Canada, National Energy Board and the U.S. Energy Information Administration
68
AN ENERGY MARKET ASSESSMENT
As mentioned previously in the
refining/upgrading section, despite the large
amount of synthetic crude oil available, many
refineries cannot process more than about
thirty percent of their crude slate as synthetic
crude oil, due to quality issues. However,
there are relatively low transportation costs
associated with acquiring synthetic crude oil
close to home. With low delivery costs, the
ongoing decline in conventional light crude
oil production, and evolving technologies for
upgrading synthetic crude oil, producers can
expect to capture a larger share of the
western Canadian market, provided the
quality issues are addressed.
Blended bitumen currently represents only
three percent of the crude slate of the nine
western Canadian refineries but has the
potential to displace some conventional
heavy crude oil in this market. However,
significant upgrades would have to be made.
Expansions to existing refineries could be
undertaken or, if bitumen production were
partially upgraded in the field, it could
displace some conventional heavy crude oil.
F I G U R E
8 . 3
Western Canada Receipts of Canadian
Crude Oil - 1999
Thousand m3/d
90
80
70
60
50
40
30
20
10
0
Total
Refinery
Capacity
Total
Canadian
Refinery Runs Crude Slate
Conv. Heavy
Blended Bitumen
Conv. Light*
Synthetic
* Includes condensate and pentanes plus
Still, conventional heavy crude oil is favored because it yields a higher quality asphalt. Given that
adequate supplies of conventional heavy crude oil are available, it is unlikely that blended bitumen
will displace it to any great degree by 2015.
8.3.2
Eastern Canada
There are twelve refineries located in eastern Canada; however, synthetic crude oil and blended
bitumen are transported only as far as the province of Ontario. There are six refineries in Ontario,
with a combined refining capacity of 87 500 m3/d (Figure 8.4). These refineries are owned by
Imperial (2), Nova, Petro-Canada, Shell and Sunoco.
Ontario refiners, in aggregate, currently process a slate of 12 percent synthetic crude oil and four
percent blended bitumen. In 1999, over 62 percent of refinery runs in Ontario were conventional
light crude oil; 23 percent consisted of imported light crude oil. The Board expects that the
percentage of imported crude oil will increase above the 1999 level reflecting the impact of the
reversal of the Enbridge Sarnia-to-Montreal pipeline (Line 9).
There is some potential for synthetic crude oil to find a larger market share in Ontario. There was
once a concern that, with the capital investment required to upgrade the plants to meet the new
sulphur regulations for motor gasoline, as many as three eastern Canadian refineries would close.
However, these refineries are all presently running close to or at capacity, and this is expected to
continue. As well, with the new technologies being developed to reduce sulphur levels in gasoline, it
is now believed that refiners will invest the capital required to upgrade their facilities in response to
the environmental regulations. During the planning process for these investments, refiners could
NATIONAL ENERGY BOARD
69
F I G U R E
consider increasing their takes of synthetic
crude oil. It is unlikely, however, that
markets for blended bitumen will increase to
any significant extent.
8 . 4
Ontario Receipts of Canadian
Crude Oil - 1999
Thousand m3/d
90
80
70
60
50
40
30
20
10
0
Total
Refinery
Capacity
8.3.3 United States
The United States market is divided
geographically into five Petroleum
Administration for Defence Districts —
“PADDs” (Figure 7.2).
Companies wishing to export Canadian
crude oil must first obtain authorization from
the Board. From September 1973 to June
1985, Canada imposed controls on oil
exports to reflect the requirements of the
domestic price control regime and to address
international oil market developments. All
oil exports required a licence, issued by the
Board, imposing volume, price and other
restrictions on the terms of export contracts.
Export charges were levied to make up the
difference between controlled domestic
prices and those available in export markets.
Total
Canadian
Refinery Runs Crude Slate
Conv. Heavy
Blended Bitumen
Conv. Light*
Synthetic
* Includes condensate and pentanes plus
Deregulation in 1985 marked the end of the Board determining the prices of exported oil. The
Board now issues, pursuant to an application, short-term export orders, which have no restrictions on
volume or price. While exporters may
apply to the Board for a long-term licence,
F I G U R E
8 . 5
all exports today are under short-term nonPADD I Receipts of Canadian Crude Oil restrictive orders. In fact, since
1999
deregulation, the Board has not received an
Thousand m3/d
application for a long-term licence. The
Board monitors export volumes and prices
300
to ensure its awareness of events in the oil
250
market. Based on these observations, the
following sections discuss the Board’s view
200
of potential export markets for Canadian
150
unconventional crude oil.
PADD I
PADD I has 12 major refineries: American,
BP Amoco, Coastal, Motiva, Pennzoil,
Sunoco (2), Tosco (2), United, Valero and
Young. They have a combined refining
capacity of approximately 269 000 m3/d,
and currently run a slate of mainly foreign
crude oil and some U.S. domestic crude oil
(Figure 8.5). Over 190 000 m3/d of the
100
50
0
Total Refinery Total Refinery Canadian
Capacity
Runs
Crude Slate
Conv. Heavy
Blended Bitumen
Conv. Light*
Synthetic
* Includes condensate and pentanes plus
70
AN ENERGY MARKET ASSESSMENT
PADD I crude oil requirement is imported and, of that, Canada provided 24 941 m3/d in 1999. A
large portion of this is production from the east coast of Canada.
PADD I takes only a minor amount of Canadian synthetic crude oil at this time, and it is expected
that PADD I will absorb only small additional amounts. Canadian synthetic crude oil competes with
cheaper foreign crude oil in this market, and would have to be further upgraded upstream and
significantly price-discounted in order to capture a larger market share.
Blended bitumen is less likely to find a home in this market, as few refineries currently have coking
facilities. There has been some discussion, however, of coking facilities being installed in the next few
years. Nevertheless, it is expected that PADD I refiners will continue to rely on conventional crude
oil from Canadian and foreign sources as their main feedstock.
PADD II
The largest U.S. market for Canadian crude oil production is PADD II. It has a combined refining
capacity of 574 500 m3/d (Figure 8.6). In 1999, 93 percent of Canadian crude oil exports were
delivered into PADD II, with 14 692 m3/d of that being synthetic crude oil and 23 842 m3/d blended
bitumen. This market takes more synthetic crude oil and blended bitumen than the other four
PADDs combined, and is the largest processor of blended bitumen among all Canadian and U.S.
markets.
PADD II can be divided into four smaller regions: Chicago; Wood River and Southern PADD II;
North Dakota/St. Paul/Superior; and Toledo/Detroit.
Chicago
Canadian producers ship crude oil into the
Chicago market via the Enbridge/Lakehead
pipeline system. The four refineries (BP
Amoco, CITGO, Clark and ExxonMobil)
located in this region have a combined
capacity of approximately 132 500 m3/d.
These refineries also process crude oil
shipped via mid-continent and Gulf Coast
pipelines. Chicago is the largest PADD II
regional market for Canadian crude oil, and
has the largest potential to absorb
additional production of Canadian
synthetic crude oil and blended bitumen.
In order for this to occur, however, the
economics would have to provide an
incentive for refiners to back out U.S.
domestic or foreign crude oil to allow for a
larger share of Canadian crude oil.
In PADD II, particularly in Chicago,
synthetic crude oil competes directly with
Louisiana light sweet crude oil (LLS)
which is of similar quality. Currently, LLS
holds a larger market share of PADD II, as
NATIONAL ENERGY BOARD
F I G U R E
8 . 6
PADD II Receipts of Canadian Crude Oil 1999
Thousand m3/d
600
500
400
300
200
100
0
Total
Refinery
Capacity
Total
Canadian
Refinery Runs Crude Slate
Conv. Heavy
Blended Bitumen
Conv. Light*
Synthetic
* Includes condensate and pentanes plus
71
it is easier for refineries to process. However, if upgrades to synthetic crude oil were made upstream
and it is price-discounted slightly, it may be able to obtain a greater portion of the Chicago market.
In addition, the U.S. Gulf Coast is a major source of light sour conventional crude oil, projected to
produce an incremental 111 000 m3/d by 2002. This could put some competitive pressure on the
market share of light Canadian crude oil, although it is likely that the bulk of this supply will be
refined in PADD III.
Blended bitumen is not a largely used crude oil in the Chicago market. There is currently only
9 700 m3/d of bitumen blend processed, while Canadian conventional heavy crude oil makes up
36 600 m3/d of the Chicago area refinery slate. While these refineries currently have a sufficient
supply of conventional crude oil, Canadian conventional heavy crude oil is expected to decline
significantly throughout the forecast period. Nevertheless, it is unlikely that blended bitumen grades
will capture more of the Chicago market until price differentials allow for upgrading.
Wood River and Southern PADD II
The Wood River and southern PADD II area is a potential growth market for synthetic crude oil and
blended bitumen. There are three main refineries in Wood River: Clark, Equilon and Marathon
Ashland. Canadian producers, via the Express/Platte pipeline system and the Enbridge/Lakehead/
Mustang pipeline interconnect, easily access the Wood River area, which has a combined refining
capacity of approximately 86 700 m3/d. In addition, there are several other refineries in the vicinity of
Wood River.
Due to the accessibility of this region, it has become a good market for Canadian conventional light
and heavy crude oil. Though there is potential for increased market share, the issue facing synthetic
crude oil producers in the Wood River market is the competition from PADD III crude oil.
PADD III crude oil supplies are close to Wood River, and thus have lower transportation costs. The
quality of synthetic crude oil will have to be improved upstream and price-discounted before it can
make major strides in this market. However, it is expected that, with the decline in both Canadian
and U.S. domestic supplies of light conventional crude oil, synthetic crude oil will eventually
penetrate the Wood River area.
In the case of blended bitumen, very small volumes were run in 1998; however, according to the
Board’s data, no blended bitumen was processed in 1999. It is expected that the Wood River refiners
will again take small amounts of blended bitumen, and producers will continue to penetrate this
market.
North Dakota/St. Paul/Superior
The Northern PADD II area is served by the Enbridge/Lakehead system, with the Minnesota
pipeline connecting it to the St. Paul, Minnesota/Superior, Wisconsin area. The BP Amoco pipeline
connects to the North Dakota market. There are four main refineries (BP Amoco, Koch, Murphy
and Marathon Ashland) with a combined refining capacity of almost 121 500 m3/d. These four
refineries receive over 75 percent of their crude requirements from Canada, and the three
eastern-most plants process a significant amount of synthetic crude oil and blended bitumen.
There is little competition from foreign crude oil in this region. Synthetic crude oil competes with
Canadian conventional crude oil and U.S. domestic crude oil, which is on a steady decline of about
four percent per year and not easily delivered to this market.
72
AN ENERGY MARKET ASSESSMENT
In 1999, synthetic crude oil increased its market share in the St. Paul and Superior market by twelve
percent relative to 1998. It is expected that synthetic crude oil demand will continue to grow, given
the complexity of the refineries in this region.
This is also the case with blended bitumen. The bulk of the PADD II blended bitumen receipts are
shipped to St. Paul and Superior. With the upgrading capabilities of some of the refineries in this
region, blended bitumen will continue to have a large market share, and could potentially displace
some conventional heavy crude oil imports.
Toledo/Detroit
The Enbridge/Lakehead pipeline delivers Canadian crude oil into the Toledo/Detroit area to four
refineries. The combined capacity of the BP Amoco, Marathon Ashland (2) and Sun refineries is
roughly 69 800 m3/d. In 1999, almost 20 000 m3/d of Canadian crude oil was processed.
Synthetic crude oil makes up about nine percent of the Canadian crude oil that is shipped to the
Toledo/Detroit area. There could be a potential market for additional synthetic crude oil to be
absorbed in this market, provided that the cost of U.S. domestic supply is higher than that of
Canadian synthetic crude oil.
Blended bitumen has a very small market share in this region, making up only 3 000 m3/d of the total
Canadian crude oil deliveries. It is expected that if the light/heavy differential were to widen
sufficiently, upgrades could be made to the refineries; however, the differential would have to be
sustained for some time before this would occur.
PADD III
PADD III has 50 major refineries, most of
which are large and complex. This region
has a refining capacity of 1 198 900 m3/d
(Figure 8.7). The crude oil slate of the
PADD III refineries consists mainly of
U.S. domestic crude oils and foreign
imports. PADD III occasionally takes
minor amounts of conventional light
Canadian crude oil via tanker; however, as
this is comparatively more expensive
method to transport crude, it is unlikely
that Canadian deliveries to PADD III will
increase.
F I G U R E
8 . 7
PADD III Receipts of Canadian Crude Oil 1999
Thousand m3/d
1200
1000
800
600
400
200
The U.S. Gulf is the primary source of
domestic light sour conventional crude oil
for the majority of the PADD III
refineries. In addition, many of the
refineries in this region have joint ventures
with certain producing countries, and it is
expected that indigenous and foreign crude
oil will continue to be the main supply
sources for PADD III.
NATIONAL ENERGY BOARD
0
Total
Refinery
Capacity
Total
Canadian
Refinery Runs Crude Slate
Conv. Heavy
Blended Bitumen
Conv. Light*
Synthetic
* Includes condensate and pentanes plus
73
PADD IV
PADD IV has a combined refining capacity of 85 800 m3/d (Figure 8.8). Canadian crude is transported
via the Express/Platte pipeline, Rangeland/Conoco system and the Bow River/Cenex pipelines.
PADD IV is land-locked, and as a result, receives all of its crude oil requirements from either local
supply or Canada. Based on the Board’s 1999 export statistics, nearly half of the slate of PADD IV
refineries consists of Canadian crude oil. The Board believes that PADD IV could be capable of
absorbing substantial amounts of unconventional crude oil, provided producers address the quality
issues.
PADD IV can be divided into three market regions: Montana, Utah and Colorado/Wyoming.
Montana
There are four major refineries in Montana:, Cenex, Conoco, ExxonMobil and Montana Refining.
Together, they have a total refining capacity of about 28 000 m3/d. As a result of its proximity to the
producing areas of Canada, its land-locked status, as well as its accessibility by pipeline, this region
takes a large amount of Canadian crude oil. In fact, over 75 percent of the crude oil processed in this
region is Canadian. Of this volume, little synthetic crude oil was processed in 1999, although
2 200 m3/d of blended bitumen was run.
It is projected that with the depleting indigenous supply, the demand for Canadian crude oil,
especially synthetic crude oil and blended bitumen, will increase in this area. Combined with the
upcoming Express spur line into the Billings area, over 3 000 m3/d of synthetic crude oil could
immediately be added to the crude diet of these refineries.
Blended bitumen will also be marketable in this area, as the refineries are reasonably complex, and
able to process a heavier feedstock. In fact, 20 percent of the heavy crude oil run in Montana is
blended bitumen.
F I G U R E
8 . 8
PADD IV Receipts of Canadian Crude Oil 1999
Thousand m3/d
100
90
80
70
60
50
40
30
20
10
0
Total
Refinery
Capacity
Total
Canadian
Refinery Runs Crude Slate
Conv. Heavy
Blended Bitumen
Conv. Light*
Synthetic
Utah
Utah has a combined refining capacity of
about 24 600 m3/d, split amongst four
refineries: BP Amoco, Chevron, Flying J
and Phillips. The Utah refineries rely
primarily on indigenous crude oil supply,
running only 25 percent Canadian crude
oil (about 5 740 m3/d). However, local
crude oil supply is declining at a rate of
approximately four percent per year, and
refiners will likely increase their synthetic
crude oil diet from the 1999 quantities of
2 000 m3/d if the quality improves.
Blended bitumen is not currently being
processed in Utah to any great extent, as
the refineries are relatively simple, capable
of processing mainly light crude oils.
Without significant upgrades, these
refineries will not run heavier crude types.
* Includes condensate and pentanes plus
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AN ENERGY MARKET ASSESSMENT
Colorado/Wyoming
The five refineries in Colorado/Wyoming are: Conoco, Frontier, Little America, Sinclair Oil and
Ultramar Diamond Shamrock have a combined refining capacity of around 33 200 m3/d. In 1999,
these refineries received more than 10 000 m3/d of Canadian crude oil. Export statistics over the past
two years show increasing volumes of both synthetic crude oil and blended bitumen moving into
these refineries, and it is expected that there is some potential for additional market share as the
PADD IV supply continues to decline.
PADD V
PADD V is a large region, with 26 refineries totalling 491 200 m3/d of capacity (Figure 8.9). Of these
refineries, only the seven located in Washington State regularly take Canadian crude oil, while the
California refineries occasionally take spot volumes.
California
Very little Canadian crude oil is delivered into the California market. It is not accessible by pipeline;
as a result Canadian crude oil must be delivered through the Trans Mountain pipeline to its
Westridge dock facility, and shipped to the California refineries by tanker. Unless Canadian crude oil
is discounted significantly compared with foreign and U.S. domestic supplies, it is unlikely that
California will be a growth market for Canadian crude.
Washington State
The Washington State refineries are owned
by BP Amoco, Equilon, Sound, Tesoro,
Tosco and U.S. Oil. The total refining
capacity in Washington State is
105 600 m3/d. Of this capacity, the
refineries process about 10 000 m3/d of
Canadian light crude oil, and only small
amounts of blended heavy.
The Washington State refineries typically
run Alaskan North Slope (ANS). ANS is in
decline, and these refiners will require
additional crude oil to replace these
volumes. It is possible that within five to
seven years, synthetic crude oil will displace
some ANS volumes. Until that time,
Canadian light crude oil will compete based
simply on economics.
It is doubtful that blended bitumen will find
a market in Washington State refineries due
to their current configuration and access to
light conventional crude oils from both
Alaska and foreign sources.
NATIONAL ENERGY BOARD
F I G U R E
8 . 9
PADD V Receipts of Canadian Crude Oil 1999
Thousand m3/d
600
500
400
300
200
100
0
Total
Refinery
Capacity
Total
Canadian
Refinery Runs Crude Slate
Conv. Heavy
Blended Bitumen
Conv. Light*
Synthetic
* Includes condensate and pentanes plus
75
8.4
Competition From Foreign Crude Oil Sources
Latin American crude oil is delivered into U.S. markets through the Gulf Coast. Venezuela has
always provided competition for Canadian crude oil, and will soon be producing a sweet, bottomless
crude oil that will likely be marketed in the Gulf Coast. Although the production costs of this new
crude will be lower than those in Canada, it is assumed that its introduction will not lead to a decline
in the overall market price of crude in this area, and therefore will not threaten the Canadian share of
the PADD II market.
Both Mexico and Venezuela are large heavy crude oil producers, and Venezuela is expecting to
produce a heavy sour synthetic crude oil. Historically, their delivered cost to Chicago is lower than
that of Canada’s. However, most exported Mexican and Venezuelan crude oil is committed to Gulf
Coast refineries because of joint ventures. It is likely that the PADD II market will continue to
represent only a small share of their production. PADD II will continue to be dominated by
Canadian crude oil, and that it is unlikely that foreign producers will sacrifice Gulf Coast prices in
order to penetrate the midwest market.
8.5
Overall Assessment of Available Markets for Synthetic
Crude Oil and Blended Bitumen
This section includes a discussion of the key factors that are likely to play a role in determining
whether the market can absorb the growing production of synthetic crude oil and blended bitumen.
These include emerging trends in the international and North American markets as well as specific
characteristics of the synthetic crude oil and blended bitumen markets. On the basis of these
considerations, an overall assessment of the likelihood of markets being available will be provided.
Crude oil is being produced throughout the world at close to full capacity with the bulk of the spare
capacity residing in OPEC. Of this, nearly all of the spare capacity is in Saudi Arabia, Kuwait and the
United Arab Emirates, and most of it is medium/heavy sour crude oil. Given that the future growth
in petroleum product demands will, for the most part, be for transportation fuels and that there is
currently little spare desulphurization capacity, it is expected that there will, over time, be a widening
of the light/heavy and sweet/sour crude oil price differentials. Such a widening of the differentials
could provide the environment for refiners to install additional upgrading capacity to process
incremental quantities of crude oil, including those from Canada.
It appears that at least one of Canada’s main competitors recognizes that upgrading will be required.
In this connection, Mexico recently announced an initiative designed to lighten its Maya heavy grade
crude oil in the next three years in a bid to increase the number of refineries that can refine this
feedstock. The process being studied involves subjecting Maya crude to hydrogen at high
temperatures and pressure in the presence of a catalyst.
Refiners generally strive to increase output levels through improvements to internal processes and
through ongoing minor investments. This results in small increases in refinery capacity, referred to
as “capacity creep”. This capacity creep factor in the U.S. has typically been about one to two
percent per year and could provide for the processing of small additional quantities of Canadian
synthetic crude oil and blended bitumen. As well, the demand for petroleum products is expected to
increase at a rate of one and a half to two percent per year. This growth, coupled with the current
high refinery utilization rates in the U.S., suggests that further refinery expansions can be expected.
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AN ENERGY MARKET ASSESSMENT
Refiners in North America will be making significant investments in the coming years to meet the
announced environmental regulations with respect to the sulphur content of motor gasoline and
diesel fuel. In the course of planning their investments to achieve these targets, refiners will likely
have the opportunity to assess and decide on the quality of crude oil they will process in the future.
This could, in turn, allow for the efficient planning of the necessary upgrading investments that will
be required to meet both the new product specifications and desired crude slate.
Refiners who are not familiar with the characteristics of synthetic crude oil are generally reluctant to
process it. This reflects the fact that synthetic crude oil yields a higher proportion of middle
distillates than other light crude oils, and that the distillate products processed are inferior in quality.
Despite this, when refiners process synthetic crude oil on a test basis, the more complex refineries
often find that it fits well into their crude slate.
Oil sands producers are continually seeking additional customers and looking for new approaches to
market the growing volumes of synthetic crude oil. In this connection, solutions to the quality issue
are being investigated. One possibility would be for producers to partially upgrade the synthetic
crude oil at the source of production and for refiners to provide the balance of the upgrading at the
refinery level.
The Board believes that there will be available markets for the growing volumes of synthetic crude oil
contained in this assessment. There is likely to be some growth in Canada, both in the east and in
the west. As well, there could be some additional markets in PADD V (i.e. mainly Washington State)
as ANS supplies decline. PADD IV will be capable of processing substantially more synthetic crude
oil in the coming years. PADD II will, however, be the main market for the growing synthetic crude
oil outputs. The U.S. market could be capable of absorbing more synthetic crude oil than the
quantities contained in the assessment, but this would likely require a significant price discount on
synthetic crude oil relative to other light crude oils. If there were temporary periods when it became
difficult to market the growing quantities of synthetic crude oil, there would be the option of placing
some of the surplus in the Ontario market which currently imports more than 32 000 m3/d of light
sweet crude oil. The Board, however, does not believe that there will be a need to do this.
It appears that the marketability of the blended bitumen supply contained in the Board’s projection is
somewhat less certain than that for synthetic crude oil. It is possible that the announced projects may
not all go ahead on the indicated schedules. Just recently, for example, Husky Oil announced that it
was delaying, for the second time, the expansion of its heavy crude oil upgrader, stating that it was
concerned about the significant new outputs that will be produced during the next several years. In
terms of specific markets, there are some limited growth prospects in Canada, and PADD IV should
be able to absorb additional quantities of blended bitumen. The bulk of the volumes, however, are
expected to be marketed in PADD II.
The Board is of the view that temporary supply gluts or imbalances will likely exist from time to time
as new in situ bitumen projects come onstream. It is expected, however, that this will result in a
widening of the light/heavy crude oil price differential, which will, in turn, provide the incentive to
install additional upgrading facilities. During the past ten years, there have been substantial
upgrading investments made at the refinery level in the U.S., in the form of expansions to existing
facilities and the installation of new coking equipment. It is expected that this trend will continue.
NATIONAL ENERGY BOARD
77
8.6
Conclusion
An opportunity for Canadian producers to sell their increasing outputs of synthetic crude oil and
blended bitumen is developing in the North American marketplace. Product demands are growing
and more crude oil will have to be processed to satisfy there requirements. As well, conventional
light and conventional heavy crude oil production in both Canada and the U.S. is expected to decline
during the projection period.
The Board’s assessment of available markets for synthetic crude oil is that the increased production
will likely be absorbed in the marketplace, although some price discounting relative to other light
crude oils could be required. In the $22 Sensitivity, production of synthetic crude oil is about
14 percent higher than in the Base Case; the Board believes that these quantities could be marketed,
but the price discount would likely have to widen. Marketing would not be an issue in the
$14 Sensitivity because there would be substantially reduced production of synthetic crude oil.
In the case of blended bitumen, marketability appears to be somewhat less certain than that for
synthetic crude oil, and it is conceivable that temporary supply imbalances could occur. The Board
believes, however, that in these situations there would be a widening of the light/heavy crude oil price
differential, which would provide the incentive to install upgrading facilities and, in turn, eliminate
the supply imbalances. In the $22 Sensitivity, production of blended bitumen would be 30 percent
greater than in the Base Case. In this situation, it is unlikely that the market could absorb these
volumes. Again, marketing would not be an issue in the $14 Sensitivity because of significantly
reduced output of blended bitumen.
78
AN ENERGY MARKET ASSESSMENT
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9.1
Introduction
This chapter identifies a number of environmental issues associated with the oil sands industry, the
main industry practices that contribute to these impacts, and the systems and practices that are used
to manage these impacts.
Oil sands development processes can be loosely divided into the categories of mining, extraction,
upgrading and in situ operations. Each of these processes has the potential to impact the
environment. During surface mining, the primary environmental issues relate to land disturbance
during exploration, site preparation and active mining, productivity and stability of reclaimed lands
after the mine is decommissioned, surface and groundwater use and quality, and air emissions from
mining equipment and the open pit. Environmental issues associated with extraction include air
emissions from the extraction facilities and vehicles, storage and disposal of tailings, and wastewater
from processed sand and tailings. For upgrading, the main environmental issues relate to air
emissions and waste materials such as coke, wastewater and sulphur.
Bitumen may also be recovered by in situ techniques, in which steam or solvents are used to heat and
dilute or extract the bitumen. The primary environmental issues associated with in situ recovery
include land disturbance and habitat fragmentation during exploration, site preparation and operation
(due to linear disturbances such as seismic lines, roads, pipelines, and the presence of well pads,
facilities and utility corridors), air emissions, and surface and groundwater use and quality.
9.2
Regulatory Background
9.2.1
Regulatory Framework
Oil sands development in Alberta is regulated by both the EUB and Alberta Environment (AENV).
The EUB operates under the legislative mandate of the Energy Resources Conservation Act and the Oil
Sands Conservation Act (OSCA). AENV’s authority is defined by the Environmental Protection and
Enhancement Act (EPEA), the Water Act and the Public Lands Act. The legislation requires that both
the EUB and AENV consider the environmental effects of proposed new or expansions to existing oil
sands projects when their approval is required. In addition, the EUB and AENV both have
responsibilities for the ongoing regulation of oil sands operations. To coordinate the responsibilities
of these two regulatory bodies, a memorandum of understanding (MOU) was signed in 1996. The
MOU describes the respective roles and responsibilities of the EUB and AENV in considering oil
sands development applications and in regulating ongoing oil sands operations. The MOU includes a
coordinated regulatory approval process to be used when applications require approvals under both
NATIONAL ENERGY BOARD
79
OSCA and EPEA. Although separate approvals are issued by the EUB and AENV, the application
activities are integrated to ensure that they are conducted in a complementary, efficient and consistent
manner.
Under its environmental assessment provisions, EPEA requires that an applicant for any oil sands
mine or any upgrader producing greater than 2000 cubic metres of crude bitumen per day conduct an
Environmental Impact Assessment (EIA).1 In an EIA, the potential environmental effects of the
proposed project are evaluated and, if applicable, mitigative measures are proposed to minimize the
impacts. The EIA is submitted to AENV and is reviewed for completeness and for purposes of EPEA
approvals by AENV. The EIA may also be submitted to the EUB as part of its oil sands approval
process.
To determine if the proposal is in the public interest and should proceed, the EUB reviews, among
other things, the economic, social and environmental effects of the project. The EUB review process
may include a public hearing for applications that can not be easily resolved due to concerns or
objections. If the EUB finds that the proposal is in the public interest, it issues a decision report and
approves the application. AENV also issues approvals to establish, operate and reclaim oil sands
developments. Both EUB and AENV approvals may impose measures to mitigate, avoid or
compensate for possible adverse environmental effects as well as requirements and conditions under
which the oil sands development must operate. Federal agencies may also participate in the
provincial environmental assessment process as a responsible authority or interested party.
An application may also require an approval by an agency of the Federal Government, usually as a
result of triggering the Fisheries Act or the Navigable Waters Act and hence the Canadian Environmental
Assessment Act (CEAA). In the federal environmental assessment process, the review of the proposal
could be subject to a screening or comprehensive study, and possibly a formal public review or
mediation process. For example, Shell’s Muskeg River mine project was subject to a CEAA screening
by the Department of Fisheries and Oceans as a result of triggering the Fisheries Act.
9.2.2
Multi-Stakeholder Initiatives
Industry-regulatory-public working groups are important components of oil sands development and
environmental management. Several regional groups have been established to study and propose
options to address social and environmental impacts, including the following:
Wood Buffalo Environmental Association (WBEA)
The WBEA is a multi-party community-based association established to monitor air quality,
including both ambient concentrations and receptor-based effects, in the Wood Buffalo region.
Membership includes industry, First Nations, regional and provincial governments and environmental
interest groups.
The Fort McKay First Nation was instrumental in establishing the WBEA. Fort McKay was
concerned about environmental impacts to the community. Government and industry responded to
Fort McKay’s concerns by working with the community as members of the Air Quality Task Force.
In 1987, the task force recommended ongoing dialogue and a consensus-based approach to air quality
concerns and problem resolution. These recommendations resulted in the formation of the Regional
Air Quality Coordinating Committee. In the spring of 1997, the committee changed its name to
WBEA and became responsible for ownership and operation of a consolidated air quality monitoring
1 One cubic metre (m3) of crude bitumen is approximately equal to 6.3 barrels or one metric tonne.
80
AN ENERGY MARKET ASSESSMENT
network in the region. WBEA also expanded its mandate to include ecological and health effects
monitoring. WBEA is an active participant in the Clean Air Strategic Alliance (CASA), which is an
incorporated entity established in 1994 to manage air quality issues in Alberta. The regional air
quality monitoring program developed by WBEA is part of CASA’s provincial ecological effects
monitoring program.
The Terrestrial Environmental Effects Monitoring Program is a sub-committee of WBEA. This
program was designed to detect possible changes in soil chemistry and tree growth resulting from
acidic deposition, as well as certain other indicators of environmental stress
Cumulative Effects Management Association (CEMA)
CEMA is a multi-stakeholder group established in 1997 to develop management systems to address
the cumulative effects of regional development in northern Alberta. CEMA also provides an on
going point of contact for issues related to cumulative effects. Regional stakeholders are able to
contact CEMA to present new issues, or to voice concerns, questions or comments on the progress of
regional issues.
As part of the CEMA initiative, industry and other stakeholders, including Environment Canada and
Alberta Environment, established the NOx and SO2 Management Working Group in 1999. The
purpose of this group is to address concerns related to the cumulative effects of nitrogen oxides
(NOx), sulphur dioxide (SO2), and volatile organic compounds (VOCs), set appropriate ambient
concentrations and regional carrying capacity guidelines, and develop management objectives
including timelines and stakeholder responsibilities. It is expected that a management system for
NOx and SO2 emissions will be designed and established by 31 January, 2001.
There are several other regional initiatives which are addressing environmental issues related to oil
sands, including:
• the Regional Aquatics Monitoring Program, which is a multi-stakeholder program with a
mandate to monitor aquatic environments in the oil sands region;
• the Alberta Oil Sands Community Exposure and Health Effects Assessment Program,
which collects field information on the exposure of residents in the Regional Municipality
of Wood Buffalo to air contaminants, including information on health effects;
• the Heavy Metals Working Group, which has been established to study the issue of heavy
metals deposition in the oil sands region, including the movement of heavy metals in the
food chain. Five heavy metals specifically being studied are nickel, vanadium, mercury, aluminum and cadmium;
• the Sustainable Ecosystems Working Group, which was established to guide development
and resource use in the region so that cumulative impacts do not exceed the carrying
capacity of the environment. Three subgroups have been struck to help develop objectives
for Wildlife, Biodiversity and Landscape components; and,
• the Surface Water and Fish Working Group, which will study the in-stream flow needs and
integrity of the Muskeg River and other rivers and streams in the region. Activities may
include conducting a scientific review of the methodology for in-stream needs for brownwater river systems.
NATIONAL ENERGY BOARD
81
Reclamation Advisory Committee (RAC)
RAC is a multi-stakeholder group established in early 1999 to follow-up on the direction and
recommendations of the Oil Sands Mining End Land Use Committee. The purpose of RAC is to
make integrated and regionally sound recommendations regarding reclamation and appropriate end
land uses. The committee serves as a steering group for other working groups addressing various
operational uses associated with oil sands mining, including the development of guidelines where
needed.
Canadian Oilsands Network for Research and Development (CONRAD)
CONRAD is a collaborative research and development network established in January 1994.
CONRAD is comprised of representatives from industry, government and academia and is funded by
industry. Although the initial focus of CONRAD was directed at mining projects, the focus was later
expanded to include in situ recovery. CONRAD now includes five technical planning groups (TPGs)
for each of mining, extraction, upgrading, environmental and in situ recovery. Each TPG develops a
project portfolio that may include fundamental research, exploratory research, technology
development or research application. During its first four years of operations, CONRAD members
invested approximately $52 million in research and development efforts.a
9.2.3
Policies and Guidelines
Oil sands development is also guided by policies and guidelines that are developed by regulatory
agencies or the multi-stakeholder working groups. The Regional Sustainable Development Strategy
(1999) creates a resource management framework for balancing development with environmental
protection. Other examples of policies include the Fort McMurray-Athabasca Oil Sands Sub-Regional
Integrated Resource Plan (1996) and the Fish and Wildlife Policy for Alberta (1982). Examples of
guidelines include the Alberta Ambient Air Quality Guidelines (1997), the Canadian Environmental
Quality Guidelines (1999), the Approaches to Oil Sands Water Release (1996), the Guidelines for
Reclamation to Forest Vegetation in the Oil Sands Region (1998), the Land Capability Classification for Forest
Ecosystems in the Oil Sands Region (1998) and the Guidelines for Wetland Establishment on Reclaimed Oil
Sands Leases (2000).
9.3
Environmental Issues
9.3.1
Land
At an oil sands mining operation, land is disturbed during exploration and development of the open
pit because surface vegetation and tree cover, topsoil, muskeg, sand, clay and gravel are removed.
The construction of the plant and support infrastructure, such as roads and utility corridors, further
disturbs the land. When mining operations are complete, the disturbed land must be reclaimed and
remediated. Land is also disturbed during in situ operations as a result of seismic mapping, and the
construction of wells and support infrastructure such as roads, pipelines and power line corridors.
Land Reclamation
The Alberta Environmental Protection and Enhancement Act requires oil sands operators to reclaim land
that has been disturbed by oil sands operations so that it is capable of supporting the intended land
uses. A major challenge when reclaiming land disturbed by mining operations is re-establishing selfsustaining ecosystems. To support such systems, the soil must contain the proper combination of salt,
silt and clay, organic material and nutrients. Soil structure is also important as it affects soil
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AN ENERGY MARKET ASSESSMENT
properties and processes such as erosion, infiltration, water holding capacity, aeration, root
penetration and mechanical strength. A common method used to reclaim a disturbed area is to cap it
with a mixture of organic material (i.e. muskeg or peat moss) and underlying mineral materials. This
reclamation mixture is placed over the materials to be reclaimed, primarily tailings sand and
overburden. Placement over new materials such as consolidated/composite tailings is currently in the
field pilot test stage.
Both Syncrude and Suncor continually reclaim soil materials and reconstruct mined-out areas. Trees
and shrubs are planted and grasses are sown to prepare the land. To date, Syncrude has planted
approximately 1.5 million seedlings in new landscapes. Since mining began in 1967, Suncor has
planted approximately 2.4 million trees and reclaimed more than 600 hectares of land.
Biodiversity
Reclaiming land disturbed by oil sands operations includes the objective of re-establishing a diversity
and abundance of habitats and qualities that is consistent with pre-disturbance levels. Ultimately, the
region should form an ecosystem that has the equivalent capability to that which existed before
development. It is anticipated that multi-stakeholder initiatives such as CEMA and AENV’s Regional
Sustainable Development Strategy will provide opportunities for issues such as wildlife management
and changes in biodiversity to be addressed.
Habitat Fragmentation
In situ extraction is often regarded as environmentally superior relative to surface mining because it
does not require the clearing of large surface areas or the excavation of overburden. However,
disturbance to wildlife, wetlands and vegetation may result due to the network of seismic lines, roads,
power line corridors, pipelines and other infrastructure required for project operation. This network
of “linear disturbance” may result in habitat fragmentation, where extensive and contiguous
ecosystems are broken up into fragments of various sizes and shapes. Habitat fragmentation can
negatively affect sensitive species, and the roads or corridors also permit increased access for hunting
and other recreational uses in areas which were formerly inaccessible.b
To address the concern of habitat fragmentation, in situ developers are looking to advancements in
technology. For example, horizontal well schemes use 30 percent less surface land than that used in
vertical well schemes.c Therefore, in situ developers may use multi-well pads with long horizontal
segments to reduce overall surface disturbances to wildlife habitat and vegetation. Ongoing
reclamation projects ensure that the duration of the surface disturbance is reduced. Operators are
also developing project plans which avoid environmentally sensitive sites when establishing drilling
locations and production facilities.
The in situ industry contends that these projects have fewer environmental effects than surface
mining operations and are therefore preferable to mining operations. However, other groups, such as
the Pembina Institute for Appropriate Development, disagree. Although they acknowledge that, on
an individual basis, in situ projects may have fewer environmental effects than a surface mining
operation, they are concerned that the cumulative impacts of widespread in situ projects could cause
extensive impacts on large areas of the Province.d The EUB and AENV believe that multistakeholder initiatives such as the Regional Sustainable Development Strategy will be effective in
addressing the regional environmental issues that may originate from continued development of in
situ and surface mineable oil sands projects in northern Alberta.e
NATIONAL ENERGY BOARD
83
Tailings Management
Surface mining operations and subsequent water-based extraction of the oil sands produce large
volumes of tailings. Tailings slurry from the extraction plants contain water, residual bitumen, sand,
silt and clay, and solvent. The slurry is pumped into large settling basins or ponds, where the coarse
sand quickly separates from the fine clays and silts. The silts and clays settle out to form a layer
which consolidates very slowly. When this layer reaches 30 percent solids by weight (one to two
years), it is known as “mature fine tails”. At Syncrude, the company’s combined tailings ponds hold
350 million cubic metres of unsettled sludge dating back to the mine opening in 1978, while Suncor
has 90 million cubic metres of tailings to treat.f
The principle environmental threats from tailings ponds are the migration of pollutants through the
groundwater system and the risk of leaks from tailings impoundments to the surrounding soil and
surface water. To ensure that seepage from tailings ponds does not contaminate groundwater and
surface water sources, tailings ponds are designed and constructed to guard against erosion, breaching
and foundation creep over the long term.g In addition, monitoring programs for groundwater and
surface water are conducted to ensure the integrity of the tailings ponds. Until recently, tailings
ponds would likely be reclaimed by capping with water to form an artificial lake.
Recent research into reclamation options which would result in a dry landscape has resulted in the
development of a treatment method which involves adding gypsum to a fine-enriched tailings slurry.
Consolidated or composite tailings (CT) are a combination of coarse tailings (sand), mature fine tailings
(silts and clays) and gypsum which results in a mixture that will not separate into the sand and clay
components, but will quickly consolidate to release water (less than one year). This rapid water
release leads to a consolidated dense tailings deposit (80 percent solids) within a short period of time
and provides the opportunity to reclaim the tailings disposal area as a solid landscape.h
Oil sands operators, including Suncor, Syncrude and Shell, are currently using CT as their preferred
tailings management strategy. However, this technology is still in the development stage, and better
tailings management options may become feasible and economic in the future. Therefore, the EUB
requires that operators submit annual progress reports on CT research and development activities
until it is satisfied that a solid landscape can be achieved. It also requires operators to continue to test
alternative tailings management technologies and submit progress reports on tailings research.i
One such alternative strategy currently under development is “thickened tailings” which is also
known as “paste technology”. With thickened tailings, tailings and liquid are combined with a
flocculant to create a mix that is thicker than the traditional mix of water and tailings called “slurry.”
Because the tailings contain less water and are thicker, a smaller disposal area is needed for surface
disposal than with a traditional tailings slurry. Also, thickened tailings solidify to a walkable state
within a few days.
A combination of methods will likely be used to create the final reclaimed landscape. While the oil
sands industry now has the technology to manage fine tailings, research and development will
continue to improve the methods and make them more effective and more economical.
Wastewater Management
There are several sources of wastewater from oil sands operations. The sources of wastewater can be
categorized as either operational wastewater or reclamation wastewater. Operational wastewater
sources include CT release water, mine drainage, basal aquifer water, coker and upgrader wastewaters,
sewage treatment system wastewaters and cooling waters. Reclamation wastewater sources include
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AN ENERGY MARKET ASSESSMENT
fine tails release water, and runoff and drainage from sand dumps, dykes, CT deposits, fine tails
deposits, coke piles, and landfills and sulphur piles.
Under the Alberta Environmental Protection and Enhancement Act, oil sands operators must manage
both reclamation and operational wastewater. Specific management strategies are required for each
wastewater type based upon the timing and volume of the release, as well as the physical, chemical
and toxicological characteristics of the wastewater. When wastewater is to be discharged into a
waterbody, AENV requires that the quality of the wastewater discharge and the receiving waters be
monitored to ensure that water of unsuitable quality is not released off-site. Management strategies
may also involve treatment of the wastewater. For example, the main source of toxicity in the water
phase of fine tailings are carboxylic acids (napthenic acids). There are two methods to treat fine
tailings pond water undergoing research: bioremediation and electrocoagulation. With
bioremedation, pond waters are treated with bacteria and nutrients under aerobic conditions. With
electrocoagulation, electrical current is used to destabilize and remove dissolved and suspended solids,
including organic compounds, inorganic salts and heavy metals.j CT release water, on the other
hand, can be recycled back into the CT process. The increased volume of water recycled from the
CT deposit reduces the need for river water use as make-up water in the extraction process.k
To address the issue of oil sands wastewater, government and industry formed the joint Oil Sands
Water Release Technical Working Group. This group produced the report Approaches to Oil Sands
Water Release in 1996, which provides government and industry with information and methodologies
for the management of wastewater and can be used in the development of guidelines and operating
procedures for wastewater management.
9.3.2
Water Use and Quality
Oil sands projects, both mining and in situ, require large volumes of water. Therefore, water use and
conservation is an important issue in oil sands operations.
Surface Water
The primary source of surface water for oil sands extraction and upgrading operations is the
Athabasca River, although other watercourses and waterbodies may be affected by channel removal or
diversions depending on the location of the project. In order to use water, an operator must obtain a
license from the province. This license stipulates the amount of water that can be withdrawn from
the source, and water release quality and disposal rates. In addition, all oil sand operators are
required to develop comprehensive water management plans.
At the completion of a mining operation, a lake may be created in the mined-out pit. These lakes are
referred to as “end pit lakes”. Oil sands operators ensure that all releases from end pit lakes will meet
or exceed regulatory requirements. Monitoring programs have been or will be established to
document activities and hydrological effects on watercourses related to mine operations and closure
conditions. These programs are required to measure changes and to provide information so that
operators can respond to such changes as necessary.
Groundwater
The primary groundwater issue related to surface mining is the depressurization of the basal aquifer.
There are concerns that groundwater volumes may be affected by this depressurization. AENV
requires that this issue be addressed in EPEA applications. Project-specific monitoring also occurs in
order to measure the impact of mining operations on adjacent water bodies and wetlands.
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85
For in situ projects, the primary groundwater issues relate to use of groundwater for steam injection/
bitumen recovery. With the anticipated increase in activity related to thermal projects, it is likely that
there will be increased demand on groundwater resources. Consequently, it will be necessary to
optimize the use of water by adopting processes which employ low steam-oil ratios. One such
process is SAGD, which benefits from an improved steam-oil ratio and higher ultimate recovery in
the order of 60 percent.l
There are also concerns about the impacts of in situ steam injection and bitumen removal on regional
hydrogeology. Well drilling and operating practices are therefore reviewed continually in order to
ensure that groundwater quality is not compromised. For example, well monitoring provisions have
been included for certain operations to enable the early detection of well failures. Technological
changes have also been used to address the concern of well failures. In 1994, the EUB directed the
use of a special double-walled casing design, improved monitoring to detect failures and surface
setbacks beyond the normal 100 metre provision.m
Another potential environmental issue associated with in situ development is the mobilization of
heavy metals through the groundwater, possibly as a result of increases in water and sediment
temperatures and pressures immediately adjacent to thermal injection. To address this issue, AENV
is requiring operators of in situ projects to establish a groundwater monitoring system in order
prevent and detect potential contamination of the groundwater system.
9.3.3
Air Emissions
Oil sands projects are large, use considerable amounts of energy and produce both gaseous and
particulate emissions to the atmosphere. Air emissions are produced from mining equipment, from
the open face of the mine, and from extraction and upgrading facilities. Utilities supplying electricity,
water and steam to the mining, extraction and upgrading processes also produce emissions. For the
in situ industry, air quality issues are primarily related to energy consumption during steam
generation. Sources of air emissions in the oil sands industry also include infrastructure activities
such as roads (traffic), pipelines, engines and buildings.
Greenhouse Gases
Greenhouse gases (GHG) are atmospheric gases such as carbon dioxide (CO2), methane (CH4) and
nitrous oxide (N2O) caused by natural events and human activities. There is generally a scientific
consensus that climate change is associated with increasing concentrations of GHG emissions in the
atmosphere arising from man made sources. For mining production, the main source of GHG
emissions is the co-generation of electricity and steam for operations, the steam being used mainly in
the extraction process that separates the bitumen from the sand. For in situ developments, the main
source of CO2 emissions is the generation of steam in thermal plants. The majority of methane
emissions (90 percent) are from the venting of casing gas at satellite facilities. The remainder is from
cleaning plants (nine percent) and wellheads (one percent).n
New technology and more efficient operations have greatly reduced emissions per unit of production.
The expansions of the Syncrude and Suncor plants provided the opportunity to adopt the new
technologies that have been developed through research and development. Syncrude, for example,
predicts that its GHG emissions per unit of production will be 38 percent lower by 2008 compared to
1990 emissions.o The lower per unit emissions anticipated at both plants arise from:
• replacing electricity intensive drag lines and bucket wheels with truck and shovel mining;
• hydrotransport of the ore instead of the use of conveyors;
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AN ENERGY MARKET ASSESSMENT
• switching to low temperature extraction methods, thereby greatly lowering energy needs;
• improving energy integration between extraction and upgrading and onsite electricity
generation;
• adding co-generation using natural gas;
• not increasing coke use;
• using waste heat recovery systems; and,
• implementing leak detection and repair programs.p
At the same time that more efficient technology is being adopted, synthetic crude oil quality is
improving. The synthetic crude oil can displace conventional light crude oil at refineries. Due to its
residue-free nature, little heavy fuel oil and coke are produced. This in turn allows for greater use of
natural gas in the refining process which subsequently reduces GHG emissions.
Although GHG emissions per unit of synthetic crude oil production have been greatly reduced, an
increase in production could lead to an increase in total emissions. For example, Syncrude’s total oil
production is expected to more than double by 2008 leading to an overall increase in GHG emissions.
Suncor acknowledged that “doubling oil sands production will increase GHG emissions from our
operation.”q Actions being taken by industry to limit GHG emissions while increasing production
include:
• implementing new, energy-efficient technologies in both existing operations and new
operations;
• capturing vented methane and reducing flaring of solution gas;
• developing alternative and renewable sources of energy;
• pursuing GHG offsets;
• supporting environmental and economic research; and,
• educating and engaging employees, customers and communities on climate change.
GHG emissions were estimated for the production of bitumen and synthetic crude oil by the oil
sands sector and are shown in Figure 9.1.1 The predicted emissions are a result of the supply
projections contained in this report. As stated in Chapter 6, the Board’s oil sands supply projections
are broadly based on discussions with industry combined with the Board’s own analysis. The
assumptions used in this report to estimate GHG emissions are the same as those contained in the
Board’s 1999 Supply and Demand report.r The methodology is based on a study conducted by the
Canadian Association of Petroleum Producers (CAPP), with further development by CAPP and
Environment Canada. The total emissions of GHG are generated by applying emission factors for
each greenhouse gas to the supply projections. The emission factors are for the most part obtained
from Environment Canada and Natural Resources Canada. The approach uses a model developed by
1 Although CO2 is the predominant anthropogenic greenhouse gas, CH4 and N2O have a stronger impact, molecule
for molecule, on warming the atmosphere. These gases are therefore compared to CO2 by using the Global
Warming Potential (GWP) value, which is defined as the measure of the warming effect that a gas has on the
atmosphere, relative to CO2. The GWP of CH4 is 21 and that of N2O is 310. Emissions of these gases are
multiplied by their respective GWP to obtain a CO2 equivalent
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87
F I G U R E
9 . 1
Estimated Greenhouse Gas Emissions
Mt CO2 Equivalent
35
30
25
20
15
10
5
0
1998
2000
2002
2004
2006
Bitumen
2008
2010
2012
2014
Synthetic
Natural Resources Canada. Commitments made by companies to reduce their emissions under the
Voluntary Challenge Registry1 program are explicitly included in the model.
Emissions of GHG in 2000 are predicted to be 13.0 mega-tonnes (Mt) from synthetic crude oil
production and 8.2 Mt from bitumen production. By 2015, synthetic crude oil emissions are
predicted to be 31.7 Mt, while bitumen emissions are predicted to be 17.2 Mt. These estimates are
similar to those found in the report Canada’s Emissions Outlook: An Updates. In that report, emissions
of GHG in 2000 were estimated to be 13.6 Mt from synthetic crude oil production and 8.1 Mt for
bitumen. By 2015, emissions of GHG were estimated to be 30.5 Mt for synthetic crude oil and
18.8 Mt for bitumen.
Sulphur Dioxide (SO2)
The burning of petroleum coke or produced gas to produce steam and electricity, the use of diesel
equipment and the upgrading of bitumen result in emissions of SO2, which can be chemically
transformed into acidic pollutants such as sulphuric acid (leading to acidification of soils and water
bodies). Emissions of sulphur compounds and hydrocarbons can also contribute to urban smog and
affect local air quality.
In Alberta, operators who emit SO2 are expected to meet the requirements of Alberta’s Ambient Air
Quality Guidelines for SO2. They are also expected to participate in multi-stakeholder air quality
forums and to contribute to air quality management through compliance and corporate stewardship.
New and improved technology has greatly reduced emissions of SO2. Although oil production has
more than doubled, annual SO2 emissions have not increased; in fact, Suncor’s emissions are at an
1 The Voluntary Challenge and Registry (VCR) was established in 1995 as an element of Canada’s National Action
Program on Climate Change. Its purpose is to encourage private and public sector organizations to voluntarily limit
their net greenhouse gas emissions as a step towards meeting Canada’s climate change goals. The VCR publicly
records the commitments, progress and achievements of all VCR Inc. registrants, including the Action Plans and
Progress Reports that form the basis for the GHG emission reduction activities planned by organizations. More
than 900 organizations have joined the initiative since 1995.
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AN ENERGY MARKET ASSESSMENT
all-time low. The biggest contributor to lower SO2 emissions at Suncor was the flue gas
desulphurization plant, which completed its first year at capacity operation in 1998. The plant
removes approximately 95 percent of SO2 emissions produced as a result of burning coke to generate
electricity and steam.t A similar result is expected at Syncrude, where new equipment such as a flue
gas desulphurization unit added to the upgrader, along with a sulphur plant and sour water treater,
will all contribute to reducing the total volume of SO2 emissions, even though production will more
than double.
Nitrogen Oxides (NOx)
NOx (NO2 and NO) is produced by the burning of fossil fuels and contributes to the acidification of
soils and water bodies. NOx can contribute to the formation of ground-level ozone through a
complex photochemical reaction with volatile organic compounds. In the oil sands industry, NOx
sources include diesel engines, extraction and upgrading plants, cogeneration facilities and fixed
sources such as gas fired heaters and boilers.
NOx is also a compound for which air quality guidelines have been developed. In Alberta, operators
who emit NOx are expected to meet Alberta’s Ambient Air Quality Guidelines for NO2. They are also
expected to participate in multi-stakeholder air quality forums and to contribute to air quality
management and monitoring through compliance and corporate stewardship.
Industry is using new technology and improvements in equipment in order to control NOx emissions.
For example, the use of low NOx burners, natural gas for incremental power generation, and lowemissions mine fleet technology all contribute to lower NOx emissions. Both Suncor and Shell are
committed to using low-emissions engine technology even if it is not required by Canadian
regulations. Suncor, for example, plans to implement low-emissions mine fleet technology as it
retires its 240-ton mine trucks and expects that NOx and particulate matter emissions of its mine fleet
could be reduced by 30 to 40 percent by using the improved technology.u
Volatile Organic Compounds (VOCs)
VOCs are carbon-containing compounds that can cause odours and may combine with other gases to
form ground-level ozone and other photochemical oxidants. VOCs also contribute to the formation
of particulate matter. In addition, many VOCs are toxic themselves. The VOCs that react with NOx
to form ozone include ethylene, propane, butane and BTEX (benzene, toluene, ethylbenzene and
xylene). In the oil sands industry, VOC sources include tailings ponds, extraction plant vent, and
fugitive emissions from process tank areas, tank farms and the exposed mine face.
In Alberta, operators who emit VOCs are expected to participate in multi-stakeholder air quality
forums and to contribute to air quality management through compliance and corporate stewardship.
Forums such as the Canadian Council of Ministers of the Environment have also been used to
develop some codes to manage emissions of these compounds. In addition, CAPP has also
established a best management practice protocol for the control of benzene.
VOC emissions are being managed by process changes and technology improvements. For example,
in EUB Decision 99-2, Shell committed to using either technological or operational-based means to
improve solvent recovery from the extraction process. Shell will use a light hydrocarbon solvent to
remove residual solids and water from the extracted bitumen. The solvent contained in the tailings
will be recovered by using solvent recovery units and re-used to ensure that the amount of
unrecovered solvent going to the tailings ponds is minimized, thereby reducing fugitive emissions of
VOCs.
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89
Ozone
Ground-level ozone is a colourless gas that forms just above the earth’s surface. It is formed when
NOx and VOCs react in the presence of warm temperatures and sunlight. Ground-level ozone is a
major component of smog, which when inhaled can lead to adverse health effects such as respiratory
problems. Ozone not only affects human health, but can also damage vegetation, decrease the
productivity of some crops, and may contribute to forest decline. Ozone can also damage synthetic
materials and some textiles, cause cracks in rubber, accelerate fading of dyes and speed up
deterioration of some paints and coatings.
Although oil sands production is not a direct source of ozone, the release of NOx and VOC emissions
in the presence of certain meteorological conditions could contribute to ground-level ozone
formation. Because of the cumulative effects of industrial emissions, Environment Canada has
identified the need for regional ozone management. It therefore supports the AENV’s Regional
Sustainable Development Strategy initiative as an appropriate multi-stakeholder forum to manage
regional air quality in the oil sands region. The EUB also expects that oil sands operators, in
collaboration with the WBEA, AENV and other stakeholders, will continue to compile information
regarding ozone formation from precursor compounds and any associated impacts on potential ozone
receptors.v
Particulate Matter
Particulate Matter (PM) is composed of micron-sized solid and liquid matter small enough to be
suspended in air. Depending on their size, these particles can be inhaled and trapped in the airways
and lungs, leading to adverse health effects. PM can also lead to urban smog, reduced visibility and
can contribute to the acidification of soils by entrapping NOx and SO2. In the oil sands industry,
sources of PM include windblown soil, road dust and industrial activities as well as motor vehicles and
power plant emissions. Secondary sources of PM include emissions of SO2, NOx and VOCs, which
act as precursors to particulate formation in the atmosphere.
Both Alberta and Canada have ambient air quality objectives for total particulate matter. Recently,
PM less than or equal to 10 microns in size (PM ≤ 10) was declared toxic under the Canadian
Environmental Protection Act. The Federal Government now has the authority to develop strategies
for the control of PM. The government has two years to develop control measures to reduce
exposure to PM ≤ 10 and a further 18 months to implement the measures.
In the oil sands industry, emerging low emissions engine technology has the potential to significantly
reduce PM and secondary PM precursor emissions. Other efforts to reduce PM focus on process
redesign, such as the use of electrostatic precipitators. Oil sands operators, through their
participation in the WBEA and other multi-stakeholder forums, also ensure that appropriate air
monitoring programs for communities adjacent to oil sands operations are established and
maintained.
9.3.4
Cumulative Environmental Impacts
The nature of the numerous oil sands projects being planned can strain the regulatory system
designed to address environmental impact assessment and approvals. The challenge of these projects
lies in the fact that these large developments lie adjacent to each other. The activity level raises the
question of how the numerous projects, in close proximity, will collectively and cumulatively interact
with the environment.w
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AN ENERGY MARKET ASSESSMENT
The potential for regional impacts generated from existing, approved and planned oil sands projects
became a key issue in the spring of 1997 during the public pre-hearing meeting for the Syncrude
Aurora Mine application. Noting that potential conflicts may occur from several mines and associated
facilities developing at the same time, Environment Canada recommended that stakeholders in the oil
sands region consider opportunities for collaborative actions. At the same hearing, the Department of
Fisheries and Oceans encouraged a regional forum for industry and stakeholders to ensure that
site-specific plans for the protection and mitigation of fish and fish habitat were adequate.x
In December 1997, Shell Canada submitted its proposal for its Muskeg River Mine Project to the
EUB. This was followed by Suncor’s Millennium Project application in April 1998 and Syncrude’s
Mildred Lake Upgrader Expansion Project application in July 1998. To respond to the important
challenges related to cumulative effects assessment (CEA), the oil sands industry established the
Athabasca Oil Sands Cumulative Effects Assessment Initiative. A result of this initiative was the
Athabasca Oil Sands CEA Framework Report which was released in February 1999. It described a
common framework for conducting cumulative environmental effects assessments of oil sands projects
in the oil sands region.
In September 1998, AENV led the development of the Regional Sustainable Development Strategy
(RSDS) for the Athabasca oil sands region. The development of the RSDS involved a partnership
with stakeholders and regulators, including industry, First Nations and Aboriginal communities,
environmental interest groups, local business groups, and municipal, provincial and federal
government agencies. The RSDS was based upon 72 environmental issues compiled from the
Athabasca Oil Sands CEA Framework Report, from project-specific environmental impact assessments in
the region, and from issues raised during EUB hearings on oil sands mining and in situ projects. The
issues were grouped into 14 themes, which were then divided into three categories based on the
priority in which stakeholders wanted to see them addressed. For issues in each theme, there are
groups designing management strategies including monitoring and research programs. The intent of
the RSDS is that data will be shared to
ensure comprehensive decision making at all
RSDS Categories and Themes:
levels. Where objectives and indicators are
complex and difficult to determine or
Category A (based on information gaps and
measure, regional stakeholders representing
urgency): sustainable ecosystems and land use;
scientific, traditional, industrial, public and
cumulative impacts on wildlife, soil and plant
regulatory interests will work together to
species diversity; effects of all air emissions on
develop a common understanding and
human health, wildlife and vegetation; and effects
agreement on the management system.
of heavy metals deposition - bioaccumulation and
AENV will deliver overall coordination and
consumption.
leadership of the RSDS. CEMA will provide
a point of contact for regional stakeholders
Category B (based on information gaps and work
regarding new issues, concerns, questions or
underway): access management; cumulative
comments. Both AENV or CEMA will track
impacts on fish habitat and populations; effects of
the progress of issues.y
9.3.5
Socio-Economic Effects
The key socio-economic issues relating to oil
sands development include:
• increases in regional employment,
leading to changes in population
dynamics;
NATIONAL ENERGY BOARD
tailings pond emissions; effects of acid deposition
on sensitive receptors; and cumulative impacts on
surface water quality.
Category C (based on information gaps, work
underway and lower level of urgency): end pit lake
water quality; cumulative impacts of surface water
quantity; cumulative impacts on groundwater
quantity and quality.
91
• impacts on First Nations, Métis peoples and traditional land use;
• impacts on local and regional service providers including the areas of housing, education,
health services, social services and emergency services;
• impacts on transportation and other infrastructure such as utilities and bridges;
• project-specific employment and contracting issues; and,
• economic benefits to the regional, provincial and national economies.
Socio-economic issues are being addressed primarily through two groups: the Regional
Infrastructure Working Group and the joint Athabasca Tribal Council/Athabasca Resource
Development Working Group.z
The main purpose of Regional Infrastructure Working Group is to identify priority items relating to
physical and social infrastructure, determine the appropriate authority to initiate action, and forward
information to assist with planning and resolving these items. Membership includes oil sands
developers, community groups and the Regional Municipality of Wood Buffalo. For particular issue
areas, the working group will strike a subcommittee and invite stakeholders to become members of
these subcommittees.
The Athabasca Tribal Council/Athabasca Resource Development Working Group was established to
address development impacts on aboriginal people. The primary impact of oil sands development on
aboriginal people is the effect on the traditional way of life. Traditional lands are being affected by
industrial and lumber activities, resulting in the reduced ability of the land to sustain the traditional
ways of life. Other issues include education, training, employment and business opportunities,
retention of culture, adjusting to a wage economy, and physical infrastructure during both
construction and operation of the oil sands project. A sub-committee will provide linkage to CEMA.
Socio-economic issues are also addressed during the EUB approval process. As part of this process,
project proponents are required to conduct public consultation with stakeholders, including
aboriginal groups in the impacted communities or within the project areas. Companies may enter
into agreements with stakeholders, particularly the aboriginal groups, if they deem it beneficial in
resolving issues identified during the public consultation process. Many companies also have
aboriginal policies and programs in place to enhance benefits to aboriginal groups. These programs
may encompass the areas of education, employment, business development, community development
and environmental issues, particularly the understanding of cumulative environmental effects on
traditional lands.
9.4
Conclusion
Alberta’s oil sands resources are vast. The increasing project development currently underway or
proposed will bring with it many challenges for the industry, the public and the regulators. Careful
planning is required to ensure that no irreparable damage is done to the people and the environment,
and that natural resources are developed in a sustainable manner taking into account the needs of the
future generations. Although, in general, technological improvements have reduced environmental
impacts on a per unit basis, cumulative environmental impacts may increase as overall production
increases. The many multi-stakeholder groups established over the last several years will be critical to
managing the cumulative effects of increasing development in the oil sands region. In addition, the
RSDS and subsequent development of management systems, a new and innovative approach to
managing the cumulative effects of an industry, will need to be closely scrutinized for their
effectiveness.
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References
a) Yildirim, Erdal. “Oil Sands Development in Canada,” 7th UNITAR International
Conference on Heavy Oil and Tar Sands, Beijing, China, 1998.
b) MacCrimmon, Gail and Thomas Marr-Laing. Patchwork Policy, Fragmented Forests: In Situ
Oil Sands, Industrial Development and the Ecological Integrity of Alberta’s Boreal Forest,
pp. 10-13, May 2000.
c) The Oil Sands: A New Energy Vision for Canada, Appendix B: Environment Report, Securing a
Sustainable Future for Canada’s Oil Sands Industry, The National Task Force on Oil Sands
Strategies of the Alberta Chamber of Resources, p. 4, Spring 1995.
d) MacCrimmon and Marr-Laing, 2000.
e) Alberta Energy and Utilities Board, Decision 2000-7, Pan Canadian Resources, Application for
Steam-Assisted Gravity Drainage (SAGD) Recovery Scheme, Christina Lake Thermal Project,
February 2000.
f) Avery, Bryant. “Syncrude Starts Tailings Cleanup,” Calgary Herald, D2, July 20, 2000.
g) Stosur, George J., Sandra L. Waisley, Thomas B. Reid and Leland C. Marchant, “Tar
Sands - Technology, Economics and Environmental Issues for Commercial Production
Beyond the Year 2000,” 7th UNITAR International Conference on Heavy Oil and Tar
Sands, Beijing, China, 1998.
h) Mikula, R.J., V.A. Munoz, K.L. Kasperski, O.E. Omotoso and D. Sheeran, “Commercial
Implementation of a Dry Landscape Oil Sands Tailings Reclamation Option: Consolidated
Tailings,” 7th UNITAR International Conference on Heavy Oil and Tar Sands, Beijing,
China, 1998.
i) Alberta Energy and Utilities Board, Decision 99-2, Shell Canada Limited Muskeg River Mine
Project, February 1999.
j) Stosur, 1998.
k) Ibid.
l) Isaacs, Eddy E., Ted Cyr, Chu Hsi, and Surindar Singh, “Recovery Methods for Heavy Oil
and Bitumen in the 21st Century,” 7th UNITAR International Conference on Heavy Oil and
Tar Sands, Beijing, China, 1998.
m) Sadler, Keith and Richard Houlihan, “Oil Sands Development in Alberta - An EUB
Perspective,” 7th UNITAR International Conference on Heavy Oil and Tar Sands, Beijing,
China, 1998.
n) Oil and Natural Gas Industry Foundation Paper prepared for the National Climate Change
Secretariat, 1998.
o) Petroleum Communication Foundation, Canada’s Oil Sands and Heavy Oil, April 2000.
p) Foundation Paper, 1998.
q) Suncor Energy, “About Project Millennium,” www.suncor.com.
r) National Energy Board, Canadian Energy Supply and Demand to 2025, 1999.
s) National Climate Change Process, Analysis and Modeling Group, Canada’s Emissions
Outlook: An Update, December 1999.
NATIONAL ENERGY BOARD
93
t) Suncor Energy, 1999 Progress Report on Environment, Health and Safety, and Social
Responsibility, Section 6 of 21, October 1999.
u) Alberta Energy and Utilities Board, Addendum B to Decision 99-7, Application by Suncor
Energy Inc. for Amendment of Approval No. 8101 for the Proposed Millennium Development,
July 1999.
v) AEUB, Decision 99-2.
w) Baker, J.G., J.R. Creasy, R.M Christie and D.D. MacGregor, “Cumulative Effects of
Multiple Mega-Projects: The Case of Oil Sands Development in Alberta,” 1999.
x) Ibid.
y) Alberta Environment, Regional Sustainable Development Strategy for the Athabasca Oil Sands
Area, July 1999.
z) Golder Associates Ltd., Athabasca Oil Sands CEA Framework Report, February 1999.
Selected Background Literature
Air Pollution Prevention Directorate, Towards a National Particulate Strategy for Canada: A Discussion
Paper from Environment Canada, July 1997.
Alberta Energy and Utilities Board, Addendum to Decision 99-7, Application by Suncor Energy Inc. for
Amendment of Approval No. 8101 for the Proposed Project Millennium Development, July 1999.
Alberta Energy and Utilities Board, Decision 2000-7, Pan Canadian Resources, Application for a SteamAssisted Gravity Drainage (SAGD) Recovery Scheme, Christina Lake Thermal Project, February 2000.
Alberta Energy and Utilities Board, Decision 2000-23, Ranger Oil Limited Cold Lake Oil Sands Area
Primary Recovery Scheme, April 2000.
Alberta Energy and Utilities Board, Decision 99-2, Shell Canada Limited Muskeg River Mine Project,
February 1999.
Alberta Energy and Utilities Board, Decision 99-25, Application by Syncrude Canada Ltd. for Amendment
of Approval No. 7550 Proposed Mildred Lake Upgrader Expansion, October 1999.
Alberta Energy and Utilities Board, Information Letter 96-07, EUB/AEP Memorandum of Understanding
on the Regulation of Oil Sands Developments, April 1996.
Alberta Environment, Guidelines for Reclamation to Forest Vegetation in the Athabasca Oil Sands Region,
Report #ESD/LM/99-1, October 1998.
Alberta Environment, Guideline for Wetland Establishment on Reclaimed Oil Sands Leases, Report
#ESD/LM/00-1, March 2000.
Alberta Environment, Regional Sustainable Development Strategy for the Athabasca Oil Sands Area,
July 1999.
Avery, Bryant. “Syncrude Starts Tailings Cleanup,” Calgary Herald, D2, July 20, 2000.
Baker, J.G., J.R. Creasy, R.M Christie and D.D. MacGregor, “Cumulative Effects of Multiple
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Mega-Projects: The Case of Oil Sands Development in Alberta”, 1999.
Bott, Robert. “Oil Sands: Digging in for the Long Term”, Petroleum Communication Foundation,
Winter 2000.
Golder Associates Ltd., Athabasca Oil Sands CEA Framework Report, February 1999.
Isaacs, Eddy E., Ted Cyr, Chu Hsi and Surindar Singh, “Recovery Methods for Heavy Oil and
Bitumen in the 21st Century,” 7th UNITAR International Conference on Heavy Oil and Tar Sands,
Beijing, China, 1998.
Lachambre, Phillip C., “The Oilsands Industry and Syncrude Canada Ltd. Growth Plans,” 7th
UNITAR International Conference on Heavy Oil and Tar Sands, Beijing, China, 1998.
Lang, B.A., Suncor Energy Inc. Oil Sands Millennium Project, Suncor Energy, 1998.
Li, Xiaomei, Yongsheng Feng, and Martin Y.P. Fung, “Land Reclamation of Oil Sands Processing
By-Products: An Aggregation Approach,”7th UNITAR International Conference on Heavy Oil and
Tar Sands, Beijing, China, 1998.
MacCrimmon, Gail and Thomas Marr-Laing. Patchwork Policy, Fragmented Forests: In Situ Oil Sands,
Industrial Development and the Ecological Integrity of Alberta’s Boreal Forest, May 2000.
Mikula, R.J., V.A. Munoz, K.L. Kasperski, O.E. Omotoso and D. Sheeran. “Commercial
Implementation of a Dry Landscape Oil Sands Tailings Reclamation Option: Consolidated Tailings,”
7th UNITAR International Conference on Heavy Oil and Tar Sands, Beijing, China, 1998.
National Climate Change Process, Analysis and Modeling Group, Canada’s Emissions Outlook: An
Update, December 1999.
Oil and Natural Gas Industry Foundation Paper, prepared for the National Climate Change Secretariat,
September 1998.
Oil Sands Mining End Land Use Committee, Report and Recommendations, 1998.
Oil Sands Vegetation Reclamation Committee, Guidelines for Reclamation to Forest Vegetation in the
Athabasca Oil Sands Region, 1998, ISBN 0-7785-0411-5.
Oil Sands Water Release Technical Working Group, Approaches to Oil Sands Water Releases,
1996, 34 pp.
The Oil Sands: A New Energy Vision for Canada, Appendix B: Environment Report, Securing a Sustainable
Future for Canada’s Oil Sands Industry, The National Task Force on Oil Sands Strategies of the Alberta
Chamber of Resources, Spring 1995.
The Pembina Institute, News Release, Oil Sands Watchdog Calls for Moratorium on New “In Situ”
Oilsands Development, 2 November 1999.
Petroleum Communication Foundation, Canada’s Oil Sands and Heavy Oil, April 2000.
NATIONAL ENERGY BOARD
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Polikar, Marcel, Ted Cyr and Keith Sadler. “Alberta Oil Sands: The Advance of Technology, 1978-98
and Beyond,” 7th UNITAR International Conference on Heavy Oil and Tar Sands, Beijing, China,
1998.
Sadler, Keith and Richard Houlihan, “Oil Sands Development in Alberta - An EUB Perspective,”
7th UNITAR International Conference on Heavy Oil and Tar Sands, Beijing, China, 1998.
Stosur, George J., Sandra Waisley, Thomas B. Reid, and Leland C. Marchant. “Tar Sands Technology, Economics and Environmental Issues for Commercial Production Beyond the Year
2000,” 7th UNITAR International Conference on Heavy Oil and Tar Sands, Beijing, China, 1998.
Suncor Energy, Progress Report on Environment, Health and Safety, and Social Responsibility, 1999.
Suncor Energy, Our Journey Towards Sustainable Development, 2000.
Suncor Energy, Project Millennium: Sustainable Development, 2000.
Syncrude Canada Ltd., 1999 Action Plan.
Wood Buffalo Environmental Association, 1998 Annual Report.
Yildirim, Erdal. “Oil Sands Development in Canada,” 7th UNITAR International Conference on
Heavy Oil and Tar Sands, Beijing, China, 1998.
96
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G
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A
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G LOSSARY
Apportionment
The method of allocating the difference between the total
nominated volume and the available pipeline operating capacity,
where the latter is smaller.
Aquifer
An underground geological formation, or group of formations,
containing water.
Associated Gas
Natural gas which overlies and is in contact with crude oil in the
reservoir.
Barrel
One barrel is approximately equal to 0.159 cubic metres or
158.99 litres or approximately 35 Imperial gallons.
Biodiversity
The variety of living components in an ecosystem.
Bitumen or Crude Bitumen
A highly viscous mixture, mainly of hydrocarbons heavier than
pentanes. In its natural state, it is not usually recoverable at a
commercial rate through a well because it is too thick to flow.
Blended Bitumen
Crude bitumen to which light oil fractions have been added in
order to reduce its viscosity and density to meet pipeline
specifications.
Cetane Number
A number for designating the percentage of pure cetane in a
blend of cetane and alphamethylnapthalene that matches the
ignition quality of a diesel fuel sample. This number, specified
for middle distillate fuels, is synonymous with the octane number
of gasolines.
CH4
Methane.
CO2
Carbon dioxide.
Coke
A solid black carbon residue remaining after valuable
hydrocarbons are extracted from bitumen.
Coker
A vessel in which bitumen is cracked into its fractions and coke
withdrawn to start the conversion of bitumen into upgraded
crude oil. The lighter fractions, primarily naphtha and gas oils,
become the main ingredients of the final blend.
NATIONAL ENERGY BOARD
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Composite Tails (CT)
Also known as consolidated tails. This technology combines fine
tailings with gypsum and sand as tailings are deposited. The
mixture causes the tailings to settle faster, enabling final
reclamation to occur sooner.
Condensate
A mixture comprised mainly of pentanes and heavier
hydrocarbons recovered as a liquid from field separators,
scrubbers or other gathering facilities or at the inlet of a
processing plant before the gas is processed in a plant.
Conventional Crude Oil
Crude oil which, at a particular point in time, can be technically
and economically produced through a well using normal
production practices and without altering the natural viscous state
of the oil.
Cracking
The process of breaking down the larger, heavier more complex
hydrocarbon molecules into smaller, lighter molecules.
Cyclic Steam Stimulation
CSS is a method of recovering bitumen from a reservoir using
steam injection to heat the reservoir to reduce the viscosity of the
oil and provide pressure support for production. Oil production
occurs in cycles, each of which begins with a period of steam
injection followed by the same well being used as a producer.
Diluent
Any lighter hydrocarbon, usually pentanes plus, added to heavy
crude oil or bitumen in order to facilitate its transport on crude
oil pipelines.
Ecosystem
A biological community of interacting organisms and their
physical environment.
Extraction
A process unique to the oil sands industry, in which bitumen is
separated from the oil sands.
Fossil Fuels
Hydrocarbon based fuel sources such as coal, natural gas, natural
gas liquids and crude oil.
Greenhouse Effect
A naturally occurring phenomenon in the earth’s atmosphere in
which incoming solar short-wave radiation passes relatively
unimpeded, but long-wave radiation emitted from the warm
surface of the earth is partially absorbed, adding net energy to the
lower atmosphere and underlying surface, thereby increasing
their temperature.
Heavy Crude Oil
Generally, a crude oil having a density greater than 900 kg/m3.
Horizontal Well
A well which deviates from the vertical and is drilled horizontally
along the pay zone. In a horizontal well, the horizontal extension
is that part of the wellbore beyond the point where it first
deviates by 80 degrees or more from vertical.
98
AN ENERGY MARKET ASSESSMENT
Hydrocarbons
Organic chemical compounds of hydrogen and carbon atoms that
form the basis of all petroleum products. Hydrocarbons may be
liquid, gaseous or solid.
Hydrocracking
The breaking of hydrocarbon chains into smaller molecules in
the presence of hydrogen and a catalyst such as platinum. The
end result is a high quality gasoline and other light hydrocarbons.
Hydrotreating
A process used to saturate olefins and improve hydrocarbon
streams by removing unwanted materials such as nitrogen, sulfur,
and metals utilizing a selected catalyst in a hydrogen
environment.
Integrated Mining Plant
A combined mining and upgrading operation where oil sands are
mined from open pits. The bitumen is then separated from the
sand and upgraded by a refining process.
In Situ Recovery
The process of recovering crude bitumen from oil sands other
than by surface mining.
Light Crude Oil
Generally, crude oil having a density less than 900 kg/m3. Also a
collective term used to refer to conventional light crude oil,
upgraded heavy crude oil and pentanes plus.
Muskeg
A water-soaked layer of decaying plant material, one to three
metres thick, found on top of the overburden. Muskeg supports
the growth of shallow root trees such as black spruce and
tamarack.
Natural Gas Liquids
Those hydrocarbon components recovered from natural gas as
liquids. These liquids include, but are not limited to, ethane,
propane, butanes, and pentanes plus.
NOx
Oxides of nitrogen.
Oil Sands
Sand and other rock material which contain bitumen. Each
particle of oil sand is coated with a layer of water and a thin film
of bitumen.
Overburden
The layers of sand, gravel and shale which overlie the oil sand
and must be removed before mining can begin. Overburden
underlies the muskeg in many places.
PADD
Petroleum Administration for Defence Districts.
Pentanes Plus
A mixture mainly of pentanes and heavier hydrocarbons obtained
from the processing of raw gas, condensate or crude oil.
Real Price
The price of a commodity after adjusting for inflation. In this
report most real energy prices are expressed in 1997 dollars.
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Reclamation
Returning disturbed land to a stable, biologically-productive
state.
Recovery - Improved
Improved or enhanced recovery is the extraction of additional
crude oil from reservoirs through a production process other
than primary recovery.
Recovery - Primary
The extraction of crude oil from reservoirs utilizing the natural
energy available in the reservoirs and pumping techniques.
Reserves - Established
The sum of the proven reserves and half probable reserves.
Reserves - Initial Established
Established reserves prior to deduction of any production.
Reserves - Proven
Reserves recoverable under current technology and present and
anticipated economic conditions, specifically demonstrated by
drilling, testing or production.
Reserves - Remaining
Initial reserves less cumulative production at a given time.
Reservoir
A reservoir (or pool) is a porous and permeable underground
rock formation containing a natural accumulation of crude oil
that is confined by impermeable rock or water barriers.
Resources - In Place
The gross volume of crude oil estimated to be initially contained
in a reservoir, before any volume has been produced and without
regard for the extent to which such volumes will be recovered.
Resources - Recoverable
That portion of the ultimate resources potential recoverable
under expected economic and technical conditions.
Resources - Ultimate Potential
An estimate of all the resources that may become recoverable or
marketable, having regard for the geological prospects and
anticipated technology.
SAGD
Steam-Assisted Gravity Drainage is a steam stimulation technique
using horizontal wells in which the bitumen drains, by gravity,
into the producing wellbore. In contrast to cyclic steam
stimulation, steam injection and oil production are continuous
and simultaneous.
Smoke Point
A test measuring the burning quality of jet fuels, kerosene, and
illuminating oils. It is defined as the height of the flame in
millimeters beyond which smoking takes place.
Stand Alone Upgrader
An upgrading facility that is not associated with a mining plant or
a refinery.
SO2
Sulphur dioxide
100
AN ENERGY MARKET ASSESSMENT
Supply Cost
Expresses all costs associated with resource exploitation as an
average cost per unit of production over the project life. It
includes capital costs associated with exploration, development,
production, operating costs, taxes, royalties and producer rate of
return.
Synthetic Crude Oil
Synthetic crude oil is a mixture of hydrocarbons generally similar
to light sweet crude oil, derived by upgrading crude bitumen or
heavy crude oil.
Unconventional Crude Oil
Crude oil which is not classified as conventional crude oil (e.g.,
bitumen).
Upgraded Crude Oil
Generally refers to crude bitumen and heavy crude oil that have
undergone some degree of upgrading, but is commonly
synonymous with synthetic crude oil.
Upgrading
The process of converting bitumen or heavy crude oil into a
higher quality crude oil either by the removal of carbon (coking)
or the addition of hydrogen (hydroprocessing).
VAPEX
Vaporized Extraction is a process similar to SAGD but using a
vaporized hydrocarbon solvent, rather than steam, to reduce the
viscosity of crude oil in the reservoir.
Viscosity
The measure of the resistance of a fluid to flow. The lower the
viscosity, the more easily a liquid will flow.
Volume - Initial In Place
The volume of crude bitumen or crude oil currently interpreted
to exist before any production.
Volume - Ultimate In Place
A value representing the volume expected to ultimately be found
by the time all exploratory and development activity has ceased.
West Texas Intermediate
WTI is a light sweet crude oil, produced in the United States,
which is the benchmark grade of crude oil for North American
price quotations.
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EUB R ESOURCE
E STIMATION M ETHODOLOGY
The EUB originally calculated the in-place volume of crude bitumen using a volumetric methodology
called the Building Block Method. On a quarter section basis, over the entire deposit and for each
horizon containing bitumen, a volume was determined where the minimum cut-offs were exceeded.
These cut-offs are three percent bitumen by weight and 1.5 metres of net pay for the sandstone
reservoirs in the in situ recovery areas and six percent and 3.0 metres pay for the surface mining areas;
and 30 percent bitumen by volume and five percent rock porosity for the carbonate reservoirs. The
data for each quarter section was taken from drill holes, or inferred from the lowest value of
surrounding lands. A standard volumetric determination was made by:
Bitumen volume =
(
net pay x weight percent bitumen x bulk density
100
)
x (area)
More recently, a mapping program has been used to generate a pay thickness map of each horizon in
a deposit. The produced rock volume is reduced to the weight or volume bitumen content. This is
the same method applied to gas or oil pools in the rest of the province.
Recoverable bitumen volumes are determined separately for those areas that can be accessed by
surface mining and those areas where recovery must be through in situ methods.
a) Surface mining methods are assumed for those areas where the overburden thickness is
75 metres or less. After application of cut-offs for minimal bitumen saturation and
thickness, the total surface mineable volume was reduced by 10 percent to allow for
environmental corridors along the major rivers, 10 percent for isolated ore bodies which are
not likely to be developed, 10 percent for surface facilities (plants, tailings ponds, and waste
dumps) and 18 percent for mining/extraction losses. Prior to 1999, the EUB counted only
the volumes in the active mine sites as reserves ( the remainder being a resource). Since
then, they have assumed that all of the mineable areas (less the previously stated losses) are
developable and the previous resource volumes are now counted as reserves.
b) Prior to 2000, for in situ methods, the EUB only counted reserves for active commercial
projects, primary recovery schemes and experimental recovery schemes. Starting in 2000,
the EUB has determined reserves for those areas that are deemed to be amenable to in situ
recovery methods. In-place cut-offs for thermal projects are increased to a minimum
thickness of 10 metres. An estimated recovery factor of 20 percent is applied to thermal
projects and five percent for primary recovery areas, which are less than some of the
current projects to better reflect the uncertainties involved. On an annual basis, the
recovery factors may have to be adjusted to reflect actual recovery information for the
various recovery schemes.
102
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T A B L E
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A 2 . 1
Economic Assumptions
Supply Cost
1) Full cycle supply cost - is the price at the field
location needed to exactly balance revenues with
capital investments, operating costs, royalties and
taxes, and a 10 percent return over the 30 year
project life, except land costs.
2) Expressed as an average cost per barrel of oil
production at the source field locations.
Rate of Return
10 percent
Royalty
Alberta Oil Sands regime
Federal Taxes
Current Oil Sands terms
Provincial Taxes
Current Alberta rates
Project Sizes
3 000 to 16 000 m3/d
Natural Gas Prices
C$2.00 - C$5.00 /GJ
The estimates are calculated using cash flow model PEEP for assessing Athabasca McMurray and
Cold Lake Clearwater formations, and several different commercial production scales ranging from
3 000 to 16 000 m3/d. It is assumed that each case is a stand-alone project and independent of other
development projects.
Capital costs include reservoir delineation, drilling and completion of well-pairs, site preparation, and
central facilities. It is assumed that well pairs are drilled from common pads and are positioned with
the injection well directly above the production well.
T A B L E
A 2 . 2
Reservoir and Bitumen Characteristics
Oil Sands Area
Athabasca
Cold Lake
Oil Sands Deposit
McMurray
Clearwater
8
10
26 - 28
30
No
No
Figures 1 & 2
Figures 3 & 4
API
0
Porosity (percent)
Aquifer
Well Pair Profile
NATIONAL ENERGY BOARD
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F I G U R E
A 2 . 1
Well-Pair Performance Profile - High Quality Athabasca; No Water Zone
Injection and Production (m3/d)
Cumulative SOR (m3/m3)
600
6
500
5
400
4
300
3
200
2
100
1
0
0
0
2
4
6
Typical Well Oil m3/d
F I G U R E
8
10
Injection m3/d
12
Cum. SOR m3/m3
A 2 . 2
Well-Pair Performance Profile - High Quality Cold Lake; No Water Zone
Injection and Production (m3/d)
Cumulative SOR (m3/m3)
700
7
600
6
500
5
400
4
300
3
200
2
100
1
0
0
0
2
Typical Well Oil m3/d
104
4
Injection m3/d
6
Cum. SOR m3/m3
AN ENERGY MARKET ASSESSMENT
F I G U R E
A 2 . 3
Well-Pair Performance Profile - Low Quality Athabasca; No Water Zone
Cumulative SOR (m3/m3)
Injection and Production (m3/d)
700
7
600
6
500
5
400
4
300
3
200
2
100
1
0
0
0
2
4
Typical Well Oil m3/d
F I G U R E
6
8
10
12
Cum. SOR m3m3
Injection m3/d
A 2 . 3
Well-Pair Performance Profile - Low Quality Cold Lake; No Water Zone
Injection and Production (m3/d)
Cumulative SOR (m3/m3)
700
7
600
6
500
5
400
4
300
3
200
2
100
1
0
0
0
2
Typical Well Oil m3/d
NATIONAL ENERGY BOARD
4
Injection m3/d
6
8
Cum. SOR m3/m3
105
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T A B L E
A 3 . 1
World Oil Price
1997
1998
1999
2000
2001
2002
2005
2010
2015
Base Case
20.69
14.24
18.6
26
22
18
18
18
18
$14 Sensitivity
20.69
14.24
18.6
26
20
14
14
14
14
$22 Sensitivity
20.69
14.24
18.6
26
24
22
22
22
22
1
1.02
1.04
1.06
1.08
1.1
1.16
1.28
1.42
Cdn$ in U.S. funds
0.72
0.68
0.67
0.68
0.71
0.72
0.74
0.76
0.77
Canada Real GDP Growth %
3.8
3.1
3.7
3.2
3
2.9
2.5
2.1
2.1
WTI (US$[1997]/barrel)[1]
Consumer Price Index
(1997=1.0)
1
West Texas Intermediate crude oil price at Cushing, Oklahoma.
106
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C ONVERSION TABLE
Abbreviation Table
Prefixes
k
kilo
M
mega
G
giga
T
tera
P
peta
E
exa
Imperial/Metric
Conversion Table
Equivalent
103
106
109
1012
1015
1018
Physical Units
m
metre
m3
cubic metres
L
b
Energy Content Table
Energy Content Table
Energy Measures
GJ
gigajoule
PJ
petajoules
Energy content
0.95 million BTU
Electricity
MW
megawatt
GW.h gigawatt hour
TW.h terawatt hour
Energy content
Natural Gas
Mcf
thousand cubic feet
Bcf
billion cubic feet
Tcf
trillion cubic feet
Energy content
1.05 GJ
1.05 PJ
1.05 EJ
3600 GJ
3.6 PJ
Equivalent
3.28 feet
6.3 barrels (oil, LPG)
35.3 cubic feet (gas)
litre
0.22 imperial gallon
barrel (oil, LPG) 0.159 m3
Natural Gas Liquids
m3
Ethane
m3
Propane
m3
Butanes
Energy content
18.36 GJ
25.53 GJ
28.62 GJ
Crude Oil
m3
Light
m3
Heavy
m3
Pentanes Plus
Energy content
38.51 GJ
40.90 GJ
35.17 GJ
Greenhouse Gas Emission Factors
Combustion Sources
CO2
CH4
N2O
NATIONAL ENERGY BOARD
Energy Production Sources
Bitumen Production
Oil Sands
3
439.2 kg/m
741.2 kg/m3
3
25.04 kg/m
42.47 kg/m3
3
2.45 kg/m
8.56 kg/m3
107
National Energy
Board
Office national
de l’énergie
Canada’s Oil Sands:
oiloil
A Supply and Market Outlook
to 2015
oiloil
An ENERGY MARKET ASSESSMENT • October 2000

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