Canada's Oil Sands - Centre for Energy

Canada’s Oil Sands
Third Edition
November 2011

Canada’s Oil Sands
Third Edition - November 2011
Writer: Robert D. Bott
Editor: David M. Carson
First Edition Copyright © April 2000, Petroleum Communication Foundation
Second Edition Copyright © September 2007, Canadian Centre for Energy Information
Third Edition Copyright © September 2009, Canadian Centre for Energy Information
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of the Canadian Centre for Energy Information. Professional elementary, secondary and post-secondary school educators
may, however, use and copy portions of this publication for the limited purpose of instruction and study provided that such
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Reviewers – Third Edition
Bob McManus
Alberta Energy
Lori Adamache, Randy Dobko, Nicole Spears
Alberta Environment
Stephen Rodrigues
Canadian Association of Petroleum Producers
Reviewers – Second Edition
Janet Annesley
Shell Canada Limited
Randall Barrett
Oil Sands Environmental Management Division,
Alberta Environment
Brad Bellows
Suncor Energy Inc.
Chris Dawson
Petro-Canada
Randy Dobko
Environmental Policy Branch, Alberta Environment
Bob Dunbar
Strategy West Inc.
Dianne Farkouh
Athabasca Regional Issues Working Group
Kara Flynn
Syncrude Canada Ltd.
Mike Burt
In Situ Oil Sands Alliance
Don Thompson
Oil Sands Developers Group
Peter Kinnear
Canadian Natural Resources Limited
Steve McIsaac
Inside Education
Alberta Department of Energy
Bill Rennie
Japan Canada Oil Sands Limited
Stephen Rodrigues
Canadian Association of Petroleum Producers
Pius Rolheiser
Imperial Oil Limited
Bee Schadeck
Devon Canada Corporation
Although the Canadian Centre for Energy Information has endeavoured to provide accurate and current information within this publication, the Centre for Energy
and the volunteer reviewers do not:
• make any warranty or representation, expressed or implied with respect to accuracy, completeness or usefulness of the information contained within this booklet;
• assume any responsibility or liability to any party for any damages resulting from the negligence of the Centre for Energy in preparation of any information,
method or process described in this publication; or
• endorse any product, service or process which may be described or implied within this publication.

Contents
Section 1: RESOURCES BEYOND BELIEF
5 The continental and global context
6 The nature of the resource
7 Challenges
8 Opportunities
Section 2: A MASSIVE TASK
11 Mining
12 Extraction
13 In-situ bitumen
13 Steam-assisted gravity drainage (SAGD)
13 Generating steam
14 Cyclic steam stimulation
14 Vapour extraction
15 Firefloods
15 “Cold” production
15 Processing
16 Upgrading
17 Transportation
18 Economics
20 Energy balance
20 Products and uses
Section 3: TOWARDS SUSTAINABLE DEVELOPMENT
23 Land and biodiversity
24 Water resources
26 Local and regional air quality
27 Greenhouse gases
28 Quality of life
29 Regulation and consultation
30 Research
31 The path ahead
for Further Information
32 Publications
34 Websites
35 Key definitions
CANADA’S OIL SANDS THIRD edition November 2011 1

Section 1
Resources Beyond Belief
As new sources of conventional crude oil become
more difficult and expensive to find and produce,
substantial investments are being made to develop
the oil sands bitumen resources of Western Canada.
Thick and sticky, like blackstrap molasses, oil sands
bitumen is more difficult to recover, process and
transport.
Yet the oil sands in northern Alberta have become a
major part of North American energy production and
are expected to become much more important in the
decades ahead.
2 CANADA'S OIL SANDS THIRD edition november 2011

As of July 2011, there were 92 active mining, in-situ, primary and experimental oil sands
projects in Alberta. The Alberta Energy Resources Conservation Board reports that
production in 2010 averaged more than 1.6 million barrels per day, which represents about
1.9 per cent of world oil supply – and more projects are proposed or under construction.
ERCB estimates that production could average almost 3.5 million barrels per day by 2020
if all the current and proposed projects go ahead. This would be equivalent to about
14.1 per cent of the North American daily oil consumption in 2010 (2.2 million barrels in
Canada, 19.2 million barrels in the United States, 2.1 million barrels in Mexico and 1.2 million
barrels elsewhere in North America.)
Canada also produced 424,576 barrels of conventional heavy oil per day in 2010. Upgraded
and non-upgraded bitumen and conventional heavy oil thus accounted for more than
half of Canada’s crude oil production. Without this production, Canada would have been a
net importer of crude oil. With it, Canada had a substantial positive energy trade balance
of $50.2 billion (including natural gas and coal as well as oil) and was the largest single
supplier of crude oil to the United States.
Although Canada is a net oil exporter, it imported approximately 778,016 million barrels of
crude oil per day in 2010.
Many factors have converged to make the Alberta oil sands such an important resource in
the 21st century:
• Experience gained through more than a century of research and four decades of
commercial production
• Continuing development of technologies to reduce costs and environmental impacts
• High demand, and therefore high prices, for crude oil and refined petroleum products
• Taxes and royalties that are adapted to the high capital costs and long lead times of oil
sands development
• An infrastructure of roads, pipelines and electrical power lines
• Managerial talent, technical expertise and skilled labour
• Scientific research to address the many issues arising from development and improve
development processes
• Regulatory and consultative processes to facilitate sustainable development of both
renewable and non-renewable resources
Oil sands development has created many opportunities:
• A large new source of petroleum to meet North American and global demand
• Employment for Albertans and other Canadians
• Revenues for energy companies and governments
• Economic benefits for Aboriginal people and other residents of northeastern Alberta
• Investments in education, training, scientific research and technological development
But there are also challenges arising from development:
• Greenhouse gases and other air emissions, water use and land disturbance
• Consumption of natural gas to extract and upgrade bitumen
• Strain on infrastructure and labour markets due to rapid growth
• Inflation and delays due to high demand for crucial goods and services
• Effects on Aboriginal communities and traditional land uses
CANADA’S OIL SANDS THIRD edition November 2011 3

Oil sands deposits underlie 142,000 square kilometres of Alberta, an area larger than the
island of Newfoundland or the state of North Carolina. The Athabasca oil sands area, by
far the largest, is the site of all surface mining projects and most in-situ extraction projects.
There are also large in-situ projects in the Cold Lake oil sands area. Development has been
slower in the Peace River, Wabasca and Buffalo Head Hills deposits. The Carbonate Triangle
is an area where bitumen is trapped in limestone rocks as well as sands or sandstones.
Production from the Carbonate Triangle has not been considered technologically or
economically feasible to date, but companies have acquired large leases there and
presumably see prospects for future development. Approximately 8,000 square kilometres
of bitumen resources are being evaluated in northwest and east-central Saskatchewan,
and there are significant bitumen deposits on Melville Island in the Canadian Arctic.
Alberta
Oil Sands
Projects
Alberta's
Oil Sands Projects
Click below to view
OIL SANDS
PRODUCING PROJECT
OIL SANDS AREA
Alberta
Oil EXISTING Sands
PIPELINES
Projects
SURFACE MINEABLE AREA
PIPELINES UNDER
Click CONSTRUCTION
below to view
UPGRADERS
OIL SANDS
PRODUCING PROJECT
OIL SANDS AREA
Conventional heavy oil deposits in Canada are concentrated around Lloydminster on
the Alberta-Saskatchewan border, but heavy oil has also been found in British Columbia,
offshore Newfoundland and Labrador, and in the Arctic Islands.
Peace River
Deposit
Buffalo Head
Hills Deposit
Peace River
Carbonate
Triangle
Athabasca
Deposit
Wabasca
Deposit
CNRL
Upgrader
Syncrude
Suncor
Upgrader
Upgrader
Fort McMurray
Nexen
Upgrader
Cold Lake
Deposit
CANADA
SURFACE MINEABLE AREA
EXISTING PIPELINES
PIPELINES UNDER
CONSTRUCTION
UPGRADERS
Scotford
Upgrader
Suncor
Upgrader
Edmonton
Cold Lake
To West Coast and
U.S. markets
Hardisty
Lloydminster
Husky Oil
Upgrader
CANADA
Calgary
To Eastern Canada, U.S.
markets and NewGrade
Upgrader at Regina
To U.S. markets
4 CANADA’S OIL SANDS THIRD edition November 2011

The continental and global context
The Canadian oil sands resource – the total amount of bitumen in the ground – is estimated at
1.7 trillion barrels, of which 169.3 billion barrels are considered recoverable reserves, based on current
economics and technology. Eighty per cent of these reserves, approximately 135 billion barrels, can
only be recovered through in-situ processes. Reserves currently under development, through both
mining and in-situ methods, total 25.9 billion barrels. The recoverable oil sands reserves in northern
Alberta represent a potential supply larger than the conventional crude oil reserves of Iran, Iraq or
Kuwait, and are third only to those of Saudi Arabia and Venezuela.
Bitumen and heavy oil resources are found in many other parts of the world, including off Canada’s East
Coast and in the Arctic Islands, but none of the known deposits come close to the scale of Alberta’s oil
sands and the Orinoco heavy oil region of Venezuela. In addition, there are numerous deposits of oil
shales around the world, but extracting hydrocarbons economically from oil shales has proved very
difficult. However, new technologies and processes are improving the economical viability of these
resources. Relatively abundant coal resources also can be gasified or converted into liquid fuels, but
this poses major economic and environmental challenges.
Crude oil plays a central role in the North American and world economies. Nearly all motorized
transportation (except electric rail) currently depends on gasoline, diesel, jet and marine fuels refined
from crude oil. Transportation fuels account for about three-quarters of current crude oil consumption.
Many other products, from asphalt paving and roofing to synthetic rubber, are manufactured
economically from by-products of crude oil. While alternatives such as ethanol and biodiesel can
fill some of the mobile fuel demand, it would take much of the world’s cropland to supply all the
transportation energy now obtained from crude oil. Conservation, efficiency gains and economic
recessions can also reduce consumption, but demand for crude oil is likely to remain high well into
the 21st century.
Western Canada Sedimentary Basin Cross-section
CANADA’S OIL SANDS THIRD edition November 2011 5

The nature of the resource
Like all crude oil, Canada’s bitumen resources started as living material. Hundreds of
millions of years ago, the remains of tiny plants and animals, mainly algae, were buried in
sea beds. As the organic materials became more deeply buried, they slowly “cooked” at
temperatures between 50 and 150 degrees Celsius. Eventually, this process converted the
materials into liquid hydrocarbons, as well as sulphur compounds, carbon dioxide and
water. The liquid hydrocarbons included both “light” compounds – those with only a few
atoms of carbon surrounded by hydrogen atoms – and large “heavy” molecules composed
of many more carbon atoms and relatively fewer hydrogen atoms. Light hydrocarbons are
similar to those found in gasoline, diesel and jet fuel. Heavy hydrocarbons are like those
found in grease and tar.
The hydrocarbons then migrated through rocks until they reached the surface or
something blocked their progress. Conventional light crude oil is usually trapped in porous
rocks under a layer of impermeable (non-porous) rock. In such reservoirs, the oil is not in an
underground lake but rather held in the pores and fractures of rock, like water in a sponge.
Oil sands are different. Geologists believe that about 50 million years ago, huge volumes
of oil migrated eastward and upward through more than 100 kilometres of rock until they
reached and saturated large areas of sand and sandstones at or near the surface. Bacteria
then feasted on the hydrocarbons, degrading the simplest hydrocarbons first, converting
them into carbon dioxide and water, and leaving behind the big hydrocarbon molecules
and other substances, such as trace metals, that cannot be digested. The bacteria may also
modify some of the simpler sulphur molecules, leaving complex sulphur compounds. As
a result, there are more heavy hydrocarbons, complex sulphur compounds and metals in
bitumen than in conventional crude oil. This makes extraction and processing more difficult
and expensive.
While the Athabasca oil sands are one of world’s largest known hydrocarbon resources, the
volume of original crude oil digested by the micro-organisms is believed to have been at
least two or three times greater than what now remains as bitumen.
While bacteria were the major agent in forming Canada’s oil sands bitumen, crude oil can
also be degraded or altered by other factors such as oxidation, evaporation, underground
water flows and loss of light hydrocarbons
that migrate more easily through
pores and fractures
Each grain of
in
sand
rocks. Various
Water layer
combinations is of surrounded such factors by
Sand create particle the
a layer of water and
many kinds of a film of bitumen and heavy Bitumen oil film
deposits found around the world.
In the Alberta oil sands, each grain of sand
is surrounded by a layer of water and a
film of bitumen. The water layer prevents
the bitumen from being absorbed directly
onto the sand surface, which allows for
relatively simple extraction. In contrast,
in oil shales the hydrocarbon is in direct
contact with the mineral making extraction
more difficult.
Each grain of sand
is surrounded by
a layer of water and
a film of bitumen
Water layer
Sand particle
Bitumen film film
6 CANADA’S OIL SANDS THIRD edition November 2011

Challenges
The economic, environmental and social challenges of oil sands arise from the nature of
the resource, its location, its vast scale and rapid acceleration of development since the
late 1990s. The resource is different from light crude oil and requires different methods and
facilities to produce transportation fuels and other commodities previously obtained from
conventional crude oil. Until recently, the main producing region had a small population
and modest infrastructure. The resource is so large that almost everything about its
development has occurred on a huge and often unprecedented scale, although smaller
in-situ projects are now becoming more common. Among some stakeholders, the recent
pace of development has raised questions about sustainability.
Economic challenges include inflation, shortages and delays caused by the high demand
for labour, equipment and other key goods and services as multiple projects are under
construction. Once production begins, labour requirements and the energy requirements
in the production process have been major concerns. Projects need continual maintenance
to avoid unscheduled production interruptions. As in other high-growth areas, rapid
growth has put heavy burdens on infrastructure such as roads and water treatment, and
new construction has had trouble keeping pace.
Environmental challenges involve both the impacts of individual projects and the
cumulative effects of development. Greenhouse gas emissions from production and
upgrading are about 10 per cent higher than from conventional crude; however, if
cogeneration is taken into consideration, oil sands crudes would have a carbon footprint
similar to conventional crudes. There are also emissions of gases that can cause acid
deposition and ground-level ozone or smog. Use and disposal of water are significant
issues. Impacts on soils, vegetation and wildlife of the boreal forest – not just from mining
but also from wells, plants, roads, pipelines, electric power lines and seismic cutlines – raise
questions about how ecosystems can be protected during operations and reclaimed after
production ceases.
The soaring demand for labour and services to support the projects and the effects on
the existing Aboriginal and non-Aboriginal communities are among the social challenges.
The population of the Regional Municipality of Wood Buffalo, which includes Fort
McMurray and most of the Athabasca oil sands region, increased by 144 per cent between
1999 and 2010 to almost 104,400. Traffic multiplied on the main highway and through
the airport. Local government officials, Aboriginal communities and non-government
organizations sought greater input into decisions affecting them.
Photo courtesy of
Shell Canada Inc.
Extraction and upgrading
facilities, like the mines
themselves, are on a very
large scale.
Photo courtesy of
JuneWarren Publishing Ltd.
The impact on ecosystems is
of primary concern.
CANADA’S OIL SANDS THIRD edition November 2011 7

Opportunities
The challenges represent opportunities for those who can find more effective and
sustainable ways to do things.
Lessons from four decades of commercial oil sands operations have already been
incorporated into the existing projects and those under development, and new approaches
are continually being introduced. As a result, Canadians have become world leaders in
unconventional crude oil production, and Canadian expertise is now being applied to other
bitumen resources in places such as California and Egypt.
Photo courtesy of
Suncor Energy Inc.
Companies are also working
with scientists, government
authorities and forestry
companies to reduce
cumulative impacts on soils,
vegetation and wildlife.
Photo courtesy of
Devon Canada Corporation
In 2006, the Alberta
government launched a
public consultation process
to consider economic, social,
environmental and First
Nations and Métis issues
associated with oil sands
development.
The economic opportunities – employment, regional development, government revenues
and export earnings – are numerous. Only about 10 per cent of the Alberta bitumen resource
is considered economically recoverable with current technologies, yet those reserves would
be sufficient to sustain production of three million barrels per day for more than 150 years.
New methods could unlock the resources currently beyond reach, including the deposits
in the Carbonate Triangle. Innovation could also make existing projects much more costeffective,
productive and environmentally sustainable, for both existing and new projects.
Creative solutions are being found to the labour shortages and supply bottlenecks that
slowed projects as oil sands development accelerated. Companies have built camps to
house construction workers, and some workers fly in from other provinces and fly home
for rest days. With support from industry and government, community colleges and
technical schools have expanded programs to train workers, and companies have stepped
up in-house training. Companies have also collaborated in efforts to maximize employment
opportunities, minimize competition for labour and ensure an adequate supply of skilled
trades throughout construction. Construction schedules have been altered and some work
postponed to avoid conflicts with other projects.
Wherever possible, assembly and fabrication work is done in the Edmonton area or
elsewhere outside the oil sands region. Some new upgrading facilities are located in the
industrial area near Edmonton, and upgrading capacity has been built at the project sites.
New pipelines are planned to carry diluted bitumen from producing areas to upgraders,
and upgraded crude oil to refineries. Meanwhile, work has begun on twinning the main
highway between Edmonton and the oil sands project area north of Fort McMurray, and a
second highway to the Fort McMurray area was paved in 2006. The provincial government
has also stepped up support for other infrastructure, water and wastewater treatment,
housing, schools and health facilities in Fort McMurray.
While existing projects use natural gas to provide most of the energy for operations
as well as the hydrogen for upgrading, companies are developing and implementing
technologies that reduce or eliminate the need for natural gas. Upgraders already capture
much of the energy used for extraction as waste heat and obtain considerable energy from
bitumen residues during processing, and this is expected to increase. One project obtains
substantially all its heat energy from coke and bitumen combustion and gasification.
Technologies are also being tested to extract bitumen underground without the need
for steam heat. Other possible energy sources include Alberta’s large coal resources and
nuclear reactors. One project has been proposed to gasify coal in central Alberta as a
source of fuel and hydrogen, and there have been preliminary discussions about nuclear
power options.
8 CANADA’S OIL SANDS THIRD edition November 2011

To this end, the Alberta government established the Nuclear Power Expert Panel to
provide a factual report on the issues pertinent to using nuclear power to supply
electricity in Alberta. That report is available online at www.energy.gov.ab.ca/Electricity/
pdfs/NuclearPowerReport.pdf. As well, the government conducted public consultation,
information on which is provided at www.energy.gov.ab.ca/Electricity/pdfs/AB_Nuclear_
workbook.pdf
Each project undergoes environmental assessment before approval, and regulatory
authorities also consider the cumulative effects of multiple projects on regional ecosystems.
Many research and development projects are underway to reduce environmental impacts.
Several methods have been suggested to reduce greenhouse gas emissions. One possibility
would be to inject emissions underground, known as carbon capture and storage or carbon
sequestration; some of the carbon dioxide might be used to enhance production from
conventional oil fields. On a per-barrel basis, greenhouse gases have been reduced 38 per
cent and other emissions have been reduced substantially since the 1990s, but the recent
rapid expansion of production has made further emissions reductions a high priority for
companies and government authorities.
Photo courtesy of
Suncor Energy Inc.
Many project components are
fabricated elsewhere and then
transported by rail or truck to
the oil sands area. The above
photo is a coker unit for an
upgrading plant.
Water recycling and use of non-potable groundwater already reduce impacts on
freshwater resources, and new technologies may reduce the large water requirements
for current oil sands production methods. Companies are also working with scientists,
government authorities and forestry companies to reduce cumulative impacts on soils,
vegetation and wildlife. On a per-barrel basis, most in-situ oil sands operations disturb
less land than conventional oil operations.
There are opportunities for people across Canada – and internationally – in responsible
development of oil sands bitumen resources. Production reduces North America’s
dependence on imports of crude oil from other parts of the world, and it makes more oil
available to meet global demand. A favourable trade balance benefits Canadians. According
to a study by the Canadian Energy Research Institute, over the next 25 years 9.4 per cent of
total GDP impacts and 22.8 per cent of total employment from oil sands investment and
operations in Alberta occurs in provinces outside Alberta. The study also indicates the federal
tax impact on Alberta will be $166 billion compared to $22.4 billion for the other provinces.
CANADA’S OIL SANDS THIRD edition November 2011 9

Section 2
A Massive Task
Conventional crude oil flows naturally or is pumped from
the ground, but oil sands bitumen does not flow at room
temperature and must be mined or recovered in-situ.
Deposits close to the surface are mined; those more than
about 75 metres below the surface require in-situ recovery.
Current in-situ bitumen production generally comes from
deposits more than 400 metres below the surface. Many of the
technologies used in oil sands extraction are similar to those in
other surface mining and conventional oil and gas operations,
but they are deployed on a massive scale and sometimes
in unique ways. Industry and government research and
development has also led to many entirely new technologies
for recovering and upgrading bitumen.
10 CANADA’S OIL SANDS THIRD edition november 2011

Mining shovels dig into sand
and load it into huge trucks.
Trucks take oil sands to crushers,
where it is prepared for extraction.
In some operations, a mobile
crusher near the shovel may
eliminate the need for trucks.
Hot water is added to the oil sands
and then fed via hydrotransport to
the extraction plant.
Bitumen is extracted
from the oil sands during
hydrotransport and in
the separation vessels.
The tailings are pumped
to the settling basin,
where most of the water
is recycled.
Mining
About 20 per cent of Alberta’s economically recoverable oil sands bitumen reserves
are close enough to the surface to make mining feasible. These are all located in the
Athabasca oil sands area north of Fort McMurray. An advantage of mining is that nearly
all of the bitumen is extracted from the ore, while in-situ methods leave a substantial
amount of the resource underground. A disadvantage is that a great deal of earth and ore
must be moved, disturbing significant areas of landscape. To achieve economies of scale,
the projects are very large. Each of the operating mining projects also has an upgrader on
site or is connected to an upgrader by pipeline.
The ore in the current projects’ lease areas averages about 10 to 12 per cent bitumen by
weight. Thus nearly two tonnes of oil sands are dug up, moved and processed to make
one 159-litre barrel of upgraded crude oil. The processed sand is then returned to the pit,
and the site reclaimed.
A big part of the mining operation involves clearing trees and brush from the site and
removing the overburden – the topsoil, muskeg, sand, clay and gravel – that sits atop the
oil sands deposit. This can amount to more than two tonnes of additional material that
needs to be moved in the course of producing one barrel of upgraded crude oil. The topsoil
and muskeg are stockpiled so they can be replaced as sections of the mined-out area are
reclaimed. The rest of the overburden is used to reconstruct the landscape.
The oil sands are highly abrasive and very hard on machinery. Literally tonnes of steel are
worn away from the equipment each year. Regular maintenance is expensive but vital to a
profitable operation.
When the Suncor and Syncrude projects were built in the 1960s and 1970s, they used giant
excavators called bucketwheels and draglines to dig up the oil sands ore and kilometreslong
conveyor belts to move it to bitumen extraction facilities. They used this system
because, at that time, the largest mining trucks carried less than 60 tonnes in a load.
However, the excavators and conveyors were expensive to operate and suffered frequent
breakdowns, especially in cold weather.
In the mid-1980s, Syncrude started using trucks and power shovels for a portion of its
oil sands mining. In 1993, Suncor switched its entire operation to a system that used the
world’s largest trucks and power shovels. Each truck by then could carry up to 240 tonnes in
a single load. Syncrude began phasing out its draglines and bucketwheels a few years later
and retired the last of its draglines in 2006.
CANADA’S OIL SANDS THIRD edition November 2011 11

By the late 1990s, the trucks in use were carrying as much as 360 tonnes, and the largest
trucks today carry about 400 tonnes. The truck-and-shovel system has proven much more
flexible and energy-efficient than the draglines and bucketwheels of yesteryear.
The other big innovation in the 1990s was a system called hydrotransport, which uses
pipelines instead of conveyors to carry oil sands to the processing plant. The trucks dump
the sand into a machine that breaks up lumps and removes rocks, then mixes the sand with
warm water. The resulting slurry of oil sands and hot water is transported by pipeline to the
extraction plant. As an added benefit, bitumen begins to separate from sand, water and
minerals as it travels from the mine to the plant.
In the mid-1990s, Syncrude began lowering extraction process temperatures from the
80°C that was then the customary temperature. The move to hydrotransport facilitated
a reduction in process temperature to 40°C, which is currently the norm. As a result, the
energy requirement for bitumen extraction has been essentially halved.
A new system, still in the trial stage, was introduced in 2006 and is expected to make ore
transportation even more efficient. A mobile crusher, connected to a slurry pipeline, is
located next to the power shovel so that the ore can be dumped in directly. Trucks would
still be needed to carry overburden and to reach less accessible parts of the mines, but this
system could considerably reduce the trucking requirement and related air emissions.
Extraction
Froth
Water
Sand
Frothing
If you shake hot water and
oil sands in a test tube, the
bitumen forms a froth at
the top, water collects in the
middle, and sand settles to
the bottom. The process is
similar to that used in an
old-fashioned butter churn.
At the processing plant, the mixture of oil, sand and water goes first to a large separation
vessel. Tiny air bubbles, which are trapped in the bitumen as it separates from the sand
granules, float the bitumen to the surface where it forms a thick froth at the top of the
vessel. This froth is skimmed off, mixed with a solvent and spun in a centrifuge to remove
remaining solids, water and dissolved salts from the bitumen. The solvent is recycled. The
sand and water, known as tailings, fall to the bottom of the separation vessel.
The sand is eventually sent back to the mine site to fill in mined-out areas. Water from the
extraction process, containing sand, fine clay particles and traces of bitumen, goes into
settling ponds. Some bitumen may be skimmed off the ponds if it floats to the surface.
The sand sinks to the bottom and bacteria digest the remaining bitumen, but the fine
clay particles stay suspended for some time before slowly settling. Adding gypsum helps
to speed the settling process and produces a slurry called consolidated tailings (CT) for
disposal in mined-out areas. Water is recycled back to the extraction plant for use in the
separation process.
As mining operations move further away from the main upgrading plants, some companies
have started building satellite extraction facilities. The bitumen froth is then sent to the
upgrader by pipeline. This reduces the round-trip distance for moving sand between the
mine pit and the extraction equipment.
Recovery Rates for Various Types of Production
Production type
Recovery rate
Conventional light oil
Averages about 30 per cent
Conventional heavy oil
Up to 20 per cent
In-situ oil sands
25 to 50 per cent
Oil sands mining
82+ per cent
12 CANADA’S OIL SANDS THIRD edition November 2011

In-situ bitumen
More than 80 per cent of the economically recoverable oil sands bitumen is buried too
deeply for surface mining. Most of this cannot be produced from a well unless it is heated
or diluted. Today’s major commercial in-situ projects use steam to heat and dilute the
bitumen, although several other methods are being tested or deployed.
Current in-situ production technologies recover between 25 and 50 per cent of the bitumen
in the reservoir. This is higher recovery than most conventional light crude oil wells.
Research to improve the in-situ recovery rates continues. Excluding the use of diesel as fuel
for the mining equipment and trucks, mining operations may use less energy and water
than in-situ operations on a per barrel basis. In-situ does use substantially less surface area,
is reclaimed faster and requires far less reclamation after operations cease. Research and
pilot operations are currently underway which will dramatically reduce the energy and
water consumption for in-situ oil sands development.
There are two principal in-situ steam injection methods used in Canada today. The choice
between them depends on the characteristics of the reservoir.
Steam-assisted gravity drainage (SAGD)
Most of the other current in-situ projects, particularly in the
Athabasca oil sands area, use steam-assisted gravity drainage
(SAGD). In this method, pairs of horizontal wells, one above
the other, are drilled into an oil sands formation, and steam is
injected continuously into the upper well. As the steam heats
the oil sands formation, the bitumen softens and drains into
the lower well. Pumps then bring the bitumen to the surface.
Oil production
Steam injection
Generating steam
Existing in-situ projects use natural gas-fired boilers to generate
steam, consuming between 1,000 and 1,200 cubic feet of natural
gas to produce each barrel of bitumen or about twice as much
as the mining-upgrading projects use to produce a barrel of
synthetic crude oil. In 2010, natural gas consumed by oil sands
producers was 713.3 billion cubic feet, up 4.5 per cent from 2009.
This represents 13.4 per cent of total Canadian marketed natural
gas production. This gas use includes natural gas required for
electricity generation. However, in-situ developments do not
require the use of diesel fuel to run equipment in their operations,
like typical mining development and therefore do not have that energy
requirement or the associated emissions.
Reservoir
Steam Chamber
Technologies have been developed to use crude bitumen as a fuel if needed for steam
generation. Additionally, some projects are using by-products of bitumen upgrading,
such as asphaltenes and carbon residue or coke. Most of these methods would increase
emissions of air contaminants, such as particulates, oxides of sulphur and nitrogen, and
greenhouse gases compared to natural gas; however, new technologies are being
developed to capture and store carbon dioxide and manage the other air contaminants.
CANADA’S OIL SANDS THIRD edition November 2011 13

Cyclic Steam Stimulation
Steam saturates the oil sands
formation, softening and
diluting the bitumen so it can
flow to the well during the
production phase.
Cyclic steam stimulation
Cyclic steam stimulation is used at Imperial Oil’s
Cold Lake project, Canada’s largest in-situ bitumen
producer, and at Canadian Natural Resources
Limited’s Wolf Lake Primrose project.
In this method, high-pressure steam is injected into
the oil sands formation for several weeks. The heat
softens the bitumen, while the water helps to dilute
and separate the bitumen from the sand grains. The
pressure also creates channels and cracks through
which the bitumen can flow to the well. When a
portion of the reservoir is thoroughly saturated, the
steam injection ceases and the reservoir “soaks” for
several weeks.
This is followed by the production phase, when
the bitumen is pumped up the same wells to the
surface. When production rates decline, another
cycle of steam injection begins. This process uses
vertical, deviated and horizontal wells and is
sometimes called “huff-and-puff” recovery. Shell
Canada uses a similar method, with horizontal wells,
in the Peace River oil sands area.
STAGE 1
Steam Injection
Steam is injected into
the reservoir.
STAGE 3
Production
Heated oil and
water are pumped
to the surface.
STAGE 2
Soak phase
Steam and condensed
water heat the
viscous oil.
Vapour extraction
One technology that could reduce energy
requirements is called “vapour extraction” or VAPEX.
In this method, pairs of parallel horizontal wells are
drilled as in SAGD, but instead of steam, natural
gas liquids such as ethane, propane or butane are
injected into the upper well to act as solvents so the
bitumen or heavy oil can flow to the lower well.
An industry-government consortium is currently
evaluating a VAPEX pilot project at the Dover lease
northwest of Fort McMurray, and the technology is
also being tested by several operators on their own
leases.
A number of other in-situ production systems,
including solvents, electric currents, microwaves
and even ultrasound, have been tried on an
experimental scale.
14 CANADA’S OIL SANDS THIRD edition November 2011

Firefloods
There has been some production of heavy oil and
oil sands bitumen with “firefloods” in which air
or oxygen is injected and part of the resource is
ignited to heat the reservoir. Petrobank Energy and
Resources Ltd. is using a variation on the fireflood
method near Christina Lake, south of Fort McMurray
in the Athabasca oil sands region; the system is called
“toe-to-heel air injection” or THAI TM .
Injection well
Pipe perforated in
injection zone
Air
Combustion
zone
Coke
zone
Mobile oil
zone
Production well
connected to
gathering system
This process uses no natural gas for production and
very little water, thereby substantially reducing the
GHG emissions and overall environmental footprint of
in-situ production.
“Cold” production
Conventional production methods using vertical and horizontal wells have also been used,
primarily in the Cold Lake oil sands but also in the Athabasca and Peace River oil sands,
where deposits are considered too thin to make steam injection economic. This production
method is also known as CHOPS (cold heavy oil production with sand). Technologies such
as progressive cavity pumps have improved the effectiveness of these “cold” production
methods.
Toe
Pipe perforated
from toe to heel
Frontal advance
Heel
Cold
heavy oil
Toe-to-heel air injection
Air or oxygen is injected and
part of the resource is ignited
to heat the reservoir.
Processing
In-situ bitumen processing involves using water to separate the bitumen from water and
sand. In-situ use of surface water has remained relatively constant, but the total volume
of groundwater allocated and used is increasing substantially, doubling between 2002
and 2007, with saline ground water use growing and expected to meet up to 40 per cent
of total in-situ water requirements in the future. Devon’s Jackfish project currently uses
100 per cent saline water. In-situ projects that use saline water from deep formations also
treat the water after use and then re-inject it into these same formations, so as to not
impact the surface or groundwater systems. Up to 90 per cent of the water is recycled,
with the remainder injected underground if it cannot be used in operations. Solids may be
landfilled, injected underground or used to surface roads. After processing, the bitumen
is diluted with condensate (pentanes and heavier hydrocarbons obtained from natural gas
processing) and the mixture is shipped by pipeline to an upgrader or refinery.
CANADA’S OIL SANDS THIRD edition November 2011 15

Upgrading
Compared to conventional light crude oil, bitumen typically contains more sulphur and a
much higher proportion of large, carbon-rich hydrocarbon molecules. All operating mines
have integral upgraders and 100 per cent of mineable production is upgraded within
Alberta. In 2010, about 15.3 per cent of in-situ production was upgraded in Alberta, with
most of the rest being upgraded elsewhere in Canada or shipped to the U.S. for upgrading.
Currently only a very small portion of bitumen is shipped to Asian markets.
Upgrading is the process that converts bitumen into a product with a density and viscosity
similar to conventional light crude oil. This is accomplished by using heat to “crack” the
big molecules into smaller fragments. Adding high-pressure hydrogen and/or removing
carbon can also create smaller hydrocarbon molecules. Most of the energy for upgrading is
obtained from byproducts of the process.
Upgrading is usually a two-stage process. In the first stage, coking, hydro-processing, or
both, are used to break up the molecules. Coking removes carbon, while hydro-processing
adds hydrogen. In the second stage, a process called hydrotreating is used to stabilize the
products and to remove impurities such as sulphur and nitrogen. The hydrogen used for
hydro-processing and hydrotreating is produced from natural gas and steam.
If the upgrading process includes coking,
the coke is removed from the bitumen and
used for industrial applications. Another
upgrading process adds hydrogen to
the bitumen and breaks up the large
hydrocarbon molecules – a process called
hydrogen-addition or hydrogen-conversion.
Hydrocarbons are stabilized by adding
hydrogen in the presence of catalysts.
After stabilization, the hydrocarbons
are separated into naphtha, kerosene
and gas oil.
Utilities plants provide
steam, nitrogen, oxygen,
potable water and
electricity.
Sulphur can be
recovered to be
used in fertilizer
and other products.
A range of products including light
sweet and sour crude oils and diesel
products are blended and shipped
to markets.
Upgrading produces various hydrocarbon products that can be blended together into a
custom-made crude oil equivalent, or they can be sold or used separately. The Syncrude
and Suncor mining projects use some of their production to fuel the diesel engines in
trucks and other equipment at their operations. Suncor also ships diesel fuel by pipeline to
Edmonton for sale in the marketplace.
Upgraders in Canada remove most of the sulphur from bitumen. Since sulphur may be
about five per cent of the raw resource, large volumes of this by-product are produced. The
Alberta Energy Resources Conservation Board expects annual sulphur production from oil
sands projects to rise from about 1.74 million tonnes in 2010 to about 3.07 million tonnes in
2020. Sulphur is used in the manufacture of fertilizers, pharmaceuticals and other products.
Unsold sulphur is stockpiled. Those operations that use coking also market or stockpile the
coke, which contains some sulphur as well as carbon.
16 CANADA’S OIL SANDS THIRD edition November 2011

Co-generation is the simultaneous production of electricity and heat energy from a single
facility. All of the oil sands mining operations, and several of the larger in-situ projects,
include natural gas or synthetic gas-fired co-generation. The electricity is used to meet the
projects’ own energy needs, such as operating mine machinery and in-situ well pumps, and
any excess power is sold to the provincial power grid. The heat energy is used to separate
bitumen from sand – whether at the extraction plants in the mining operations or by steam
injection at the in-situ projects. Co-generation produces fewer air emissions per unit of
energy produced compared to other thermal-electric generating facilities.
Upgrading can occur at the producing site, adjacent to a refinery or anywhere in between.
The choice of location for upgrading depends on several factors:
• Capital and operating costs of the upgrader at one location relative to another
• Potential synergies of locating an upgrader near to or in association with other
corporate assets such as a refinery
• Transportation costs
• Diluent cost and availability – crude bitumen has to be diluted to flow
through pipelines
• Pumping costs – diluted bitumen requires more energy to pump than
conventional or upgraded crude
• Marketing conditions
Photo courtesy of
Suncor Energy Inc.
Product tanks store refineryready
feedstock and diesel fuel
that is shipped by pipeline to
customers in commercial and
industrial markets throughout
North America.
Transportation
Pipelines are the least expensive and most efficient way to move petroleum products
over land. Upgraded synthetic crude oil has a density of about 850 kilograms per cubic
metre (about 34 degrees on the America Petroleum Institute gravity scale), similar to the
vegetable oil in our kitchens, and is shipped through pipelines just like the conventional
light crude oil it resembles.
Moving bitumen by pipeline is a challenge due to its high viscosity (resistance to flow, or
stickiness). Large-diameter pipelines with powerful pumps help, but producers also lower
the density and viscosity of the bitumen by diluting it with a light, low-viscosity petroleum
product such as condensate, conventional light crude oil or synthetic crude oil. Some
bitumen must be diluted by as much as 40 per cent to flow through a pipeline.
Photo courtesy of
Suncor Energy Inc.
Sand is mined using shovels with
buckets that hold 100 tonnes,
loading 400 tonne trucks.
The most common diluent for oil sands bitumen is condensate, a mixture of pentanes and
heavier hydrocarbons obtained from natural gas processing. Supplies of condensate in
Western Canada are limited. Some pipeline systems already include return lines to carry
condensate back upstream for re-use. A recent alternative uses synthetic crude to dilute
bitumen for shipment; the two fluids are separated before processing at the downstream
end. Other proposed solutions involve pipelining imported condensate from the U.S.
Midwest or Canada’s West Coast for use as diluent.
As bitumen production has increased, there have been periodic shortages of condensate
and light oil available for dilution. This is one reason why upgraders in Western Canada
increased their processing capacity.
Bitumen can also be shipped by truck, but again it must be diluted or heated first. Trucks
are used mainly to carry production from small or experimental operations to the nearest
upgrader or pipeline terminal.
CANADA’S OIL SANDS THIRD edition November 2011 17

Economics
Oil sands development depends mainly on two factors: the cost of producing and
transporting the products, and the price buyers are willing to pay. Crude oil prices are
determined by global supply and demand and change with the weather, politics and other
factors. For Western Canadian producers, refining capacity and competition in the midcontinental
U.S. and Canadian markets are also key considerations.
Photo courtesy of
Syncrude Canada Ltd.
The high demand for labour
in the oilsands region has also
alleviated unemployment
across the country.
Operating costs – the labour, natural gas and other goods and services needed to produce
a barrel – comprise about half of the supply cost for producers. In addition, companies
have to earn enough to repay the capital they invested in the project, pay royalties and
taxes to government, reclaim the sites and set aside funds for research, maintenance and
new developments. The developers have invested billions of dollars in the projects, and
they must attempt to earn a competitive return on this investment. Judging by the scale
of current and proposed activity, companies generally believe that oil sands projects are
worthwhile long-term investments.
A number of factors affect the profitability of oil sands projects. Major influences include
the exchange rate of the Canadian dollar, fiscal terms and operating expenses such as initial
capital costs, crude prices and natural gas, material and labour costs. As well, because of
unique challenges, different projects will have differing operating costs.
The operating costs for conventional light oil in Western Canada are considerably lower
than for upgraded oil sands bitumen, but conventional producers also have to invest
continually in exploration for new reserves, which can add substantially to their costs. After
a few years of production, the volume produced from a conventional well begins to decline
and the operating costs start to rise, whereas this is not the case with oil sands mining.
Operating costs in the oil sands mining projects are partly dependent on the price of
natural gas used to generate steam and electricity and to produce hydrogen in associated
upgrading facilities. If ways can be found to reduce or eliminate natural gas use, then
costs could be reduced significantly. Wages and salaries are another major component of
operating costs for mines and upgraders as they employ large numbers of skilled workers.
The operating costs to produce oil sands bitumen vary considerably. In 2011, the Alberta
Energy Resources Conservation Board estimated plant gate supply costs of $47 to $57 per
barrel for steam-assisted gravity drainage projects, compared to $63 to $81 per barrel
for stand-alone mining projects and $88 to $100 per barrel for integrated mining and
upgrading projects. The Canadian Energy Research Institute (Study 122) estimated the cost
for new SAGD and stand-alone mining projects at $93 per barrel and integrated mining and
upgrading projects at $100 per barrel. The amount of natural gas used to generate steam
and the recovery rate are the key factors. The availability of condensate and light oil to
dilute bitumen can also affect markets for these products. The price of bitumen generally
increases in the spring and summer when a lot of road-building and construction activity
requiring asphalt is under way. The spread between the price of heavy and light oils is
called the differential.
The provincial government, which owns the mineral rights to virtually all of the oil sands
resources, has recognized the long-term benefits of development in shaping royalty
arrangements for their “owner’s share” of revenues from oil sands. Alberta established a
stable “generic” oil sands royalty system in 1997 after decades of negotiating project-byproject
arrangements. Under the generic system, the province collected one per cent of
18 CANADA’S OIL SANDS THIRD edition November 2011

gross sales revenues on all production and a 25 per cent share of net project revenues after
the operator recovered capital costs to build the project.
In 2009, the government introduced its New Royalty Framework, consisting of price-sensitive
royalty rates linked to the price of West Texas Intermediate crude oil in Canadian dollars.
For projects that haven’t recovered capital costs incurred to construct the project, gross
royalty rates start at one per cent when oil is priced at $55 per barrel or less, and increase to a
maximum of nine per cent when oil is priced at $120 per barrel or more. For projects that have
recovered start-up coats, net royalty rates start at 25 per cent when oil is priced at $55 per
barrel or less, and increase to a maximum of 40 per cent when oil is priced at $120 or more.
The goals of the new Royalty Regime are as follows:
• Support sustainable economic development that contributes to a high quality of life
for all Albertans now and into the future
• Support a fair, predictable and transparent royalty regime
• Align Alberta’s royalty regime with overall government objectives
More information is available at http://www.energy.gov.ab.ca/OilSands/808.asp
One economic benefit of oil sands development is the ongoing stable employment and
significant maintenance capital expended throughout the entire life of the project, in contrast
to the ups and downs of conventional oil operations. This was an important consideration
cited by the governments when they implemented the generic royalty and tax regimes.
Though the economic effects of oil sands development are concentrated in Alberta, they also
spread across the country and internationally through purchases of equipment, materials and
services. Companies and workers pay taxes to the federal government, and Alberta is a major
contributor to equalization payments that aid poorer provinces. According to the Canadian
Energy Research Institute (Study 124), oil sands tax revenue across the country will total
$444.2 billion over the next 25 years, $321.8 billion of which will go to the federal government.
The high demand for labour in the oil sands region has also alleviated unemployment
across the country. People from Atlantic Canada, for example, now account for more than
one-quarter of the population in Fort McMurray.
CANADA’S OIL SANDS THIRD edition November 2011 19

Energy balance
The energy balance is simply the ratio between energy inputs and outputs for a given type
of energy production. Energy balances are used as indicators of efficiency when comparing
energy types and production methods.
Based on National Energy Board data for natural gas inputs and petroleum outputs, the
energy balance for oil sands mining-upgrading projects is about 1:12 and it is about 1:6 for
in-situ bitumen production. In addition, about 14 per cent of the raw bitumen is consumed
to produce energy during upgrading or is converted into by-products such as coke and
sulphur. As a result if the raw bitumen from in-situ projects is then upgraded into synthetic
crude oil, the energy balance is as low as 1:4.
The energy balance for oil sands is roughly comparable to that for ethanol produced from
sugar cane in Brazil – where one unit of energy input produces about eight units of ethanol
fuel energy – and it is much better than ethanol produced from corn in North America,
where one unit of energy input only produces about 1.3 units of ethanol fuel energy.
Since the early 1990s, energy use per barrel in oil sands mining and extraction has been
reduced about 45 per cent through the use of new technologies such as hydrotransport,
which is more efficient than conveyors or truck transport. New, low-temperature extraction
processes further reduce energy use.
Products and uses
Upgraded synthetic crude oil is a conventional light oil equivalent. The most common
products made from upgraded synthetic crude oil are transportation fuels such as gasoline,
diesel and jet fuel. Others include petrochemicals used in making synthetic rubber and
polystyrene. When bitumen is processed in refineries, it also produces transportation fuels
and some petrochemicals, as well as the asphalt needed for road paving and roofing.
Sulphur, which comprises about five per cent of oil sands bitumen, is a major by-product of
oil sands upgrading. The decision to sell or stockpile sulphur for future sale is dependent
on world sulphur markets and the availability of storage space. Until recently, Syncrude
stockpiled most of its sulphur at the upgrader site, but in 2005 Syncrude sold sulphur from
its stockpile for the first time in 10 years, and the company is now producing fertilizer from
its sulphur. Suncor and other companies have sold most of their sulphur production on
international markets despite low prices and high transportation costs for the commodity.
Canada is the world’s largest producer and exporter of elemental sulphur, which is also
obtained from sour gas production.
Common products made from
upgraded crude oil, other than
transportation fuels, include
petrochemicals used in making
synthetic rubber and plastics.
By 2018, however, upgraders could generate as much as 3.3 million tonnes of sulphur per
year. To address this issue, several countries have been identified as potential markets since
sulphur can be used to make fertilizer. Canadian supply to the United States rose 116.5 per
cent in 2010 compared to 2009. Other countries to which export increased in 2010 include
Australia, South Africa and Israel. Although exports to China decreased 37.7 per cent in
2010 over 2009, the value of sulphur exports to China increased 33 per cent to $178 million.
Sulphur is also used in other industries such as pharmaceuticals and synthetic rubber. Some
sulphur is currently used in road asphalt and potentially could be used in concrete or other
construction materials.
20 CANADA’S OIL SANDS THIRD edition November 2011

Section 3
Towards Sustainable
Development
Like many types of resource development, oil sands projects
affect land, air and water and the human, plant and animal
life they sustain.
As ecological knowledge and environmental awareness
have grown over the years, companies and government
authorities have sought better ways to reduce or eliminate
such effects.
This helps to ensure the highest possible quality of life for
industry’s workers and those who reside near its plants,
while also reducing impacts on regional and global
ecosystems.
CANADA’S OIL SANDS THIRD edition november 2011 21

The Alberta and federal governments and the petroleum industry generally subscribe to
the concept of sustainable development, defined as “development that meets today’s
needs without compromising the ability of future generations to meet their needs.”
As the pace of oil sands development began to accelerate in 1999, the Alberta government
announced the Regional Sustainable Development Strategy for the oil sands area of
northeastern Alberta. The strategy defined sustainable development this way:
"Under sustainable development, renewable resources are managed to ensure
their long-term viability and potential future use. Non-renewable resources are
managed to maximize their benefits. Sustainable development takes into account
the interdependence of trees, minerals, wildlife, water, fish, range lands, public
lands, plants and other similar resources... It considers the economic effects of
environmental decisions, and the environmental effects of economic decisions."
To implement the strategy, multi-stakeholder task forces brought together industry,
different levels of government, non-governmental organizations, Aboriginal communities
and local businesses and other interests. They sought coordinated approaches to issues
such as health care, infrastructure and air quality as well as the cumulative effects from so
much development occurring so rapidly, most of it in one geographical area.
In 2006, the Alberta government conducted public consultation through the oil sands
Multi-Stakeholder Committee (MSC), to consider economic, social, environmental and First
Nations and Métis issues associated with oil sands development.
Phase I of the process set out a vision and principles for oil sands development. Phase II
sought public input on implementing the vision and principles, and included separate,
parallel First Nations and Métis consultation focusing on potential adverse impacts of oil
sands development on constitutionally protected rights and traditional land uses.
Information gathered by the MSC supplemented previous public and interest-group input
that has been ongoing since commercial oil sands operations began.
The MSC reached consensus on 96 of 120 recommendations regarding Aboriginal
consultation, minimizing the impact of oil sands on biodiversity, improving land
reclamation, the need for protected areas, planning and monitoring processes, and
retention of a larger share of related, value-added processing.
It failed to reach consensus on the pace of development, water use, targets for greenhouse
gas emissions, limiting the amount of land available for oil sands projects, and royalties and
taxes. The Multi-Stakeholder Committee Final Report and the Aboriginal Consultation Final
Report were published in 2007 and are available at www.oilsandsconsultations.gov.ab.ca
Photo courtesy of
Syncrude Canada Ltd.
Several hundred wood bison
graze on the Syncrude site as
part of a long-term reclamation
project co-managed with the
nearby Fort McKay First Nation.
Aboriginal people, who have inhabited the oil sands region for thousands of years, have a
special interest in how development proceeds. While they have gained many opportunities
through direct employment and the creation of Aboriginal-owned businesses, they have
also expressed concern about the impacts of development on their communities, the
environment and traditional land uses.
In December 2008, the Alberta government released the Land-use Framework, which sets
out an approach on how to better manage public and private lands and natural resources in
22 CANADA’S OIL SANDS THIRD edition November 2011

light of achieving Alberta’s long-term economic, environmental and social goals. The Lower
Athabasca Regional Plan will identify and set resource and environmental management
outcomes for air, land, water and biodiversity, and guide future resource decisions while
considering social and economic impacts.
In February 2009, Alberta released Responsible Actions, a 20-year strategic plan for
Alberta’s oil sands, which addresses the economic, social, environmental, research and
innovation, and governance needs of Alberta’s oil sands regions. The plan will form a new
provincial and regional approach to managing the oil sands regions. The plan was based
on extensive stakeholder consultations described in Investing in our Future: Responding to
the Rapid Growth of Oil Sands Development, the Multi-Stakeholder Committee Final Report
and the Aboriginal Consultation Final Report. Responsible Actions also builds on existing
Alberta government policies, programs and initiatives, particularly the Provincial Energy
Strategy and Land-use Framework.
Land and biodiversity
As Canada’s largest mines, the Athabasca oil sands projects affect thousands of hectares of
boreal forest, wetlands, watersheds and muskeg. However, only four per cent of Canada’s
310 million hectare boreal forest is underlain by oil sands. Approximately 2.5 per cent
of that land, or 0.1 per cent of the boreal forest, is mineable. As at October 2011, 71,500
hectares had been disturbed. During operations, as well as when mining is completed, the
developers are required to restore the mine sites to at least the equivalent of their previous
biological productivity. Reclamation is an ongoing process with initial reclamation work
commencing as soon as three years after the land is first disturbed. This does not mean
“tree-by-tree” restoration, but rather that the region as a whole should form an ecosystem
with a productive capacity equal to or greater than that which existed before development.
Photo courtesy of
Shell Canada Inc.
Scientific studies are underway
to determine how much water
can be withdrawn from the
Athabasca River without
negative effects.
How is this done? Before operations begin, environmental scientists record existing soil
types and plant and animal species in a detailed Environmental Impact Assessment or EIA.
Trees that must be harvested are sent to nearby lumber or pulp mills. Muskeg and topsoil
are removed and stockpiled. Sand from the processing facility is returned to mined-out
areas. After an area is mined, topsoil and overburden are replaced, and an annual ground
cover such as barley is planted to stabilize the soil. The surface is then replanted with
trees, shrubs or grasses. When the area meets the provincial government’s standard for
reclamation the land is certified and it is officially returned to the Province and is no longer
under the control of the oil sands project. Once a certificate is granted the land reverts
back to the crown, would be available for public access and would be unavailable to the oil
sands project.
Syncrude and Suncor have reclaimed 4,900 and 1,300 hectares respectively and have
planted more than 8.5 million trees. Another 80 hectares has been reclaimed by Canadian
Natural Resources Limited and 16 by Shell Canada. Only Syncrude has received certification
for reclaimed land, a 104-hectare area known as Gateway Hill. Applications for certification
are generally not submitted until the reclaimed land is no longer integral to a company’s
operations as the companies want to maintain control over these areas.
Several hundred wood bison graze on the Syncrude site as part of a long-term reclamation
project co-managed with the nearby Fort McKay First Nation. The bison project is the result
of Syncrude’s research efforts into reclamation techniques that will also create productive
wildlife habitats. Wood bison were chosen as a focus because the species was native to the
CANADA’S OIL SANDS THIRD edition November 2011 23

area until their near extinction in the 1800s, and played an important role in the economy
and culture of Aboriginal communities.
Only Syncrude’s 104-hectare parcel of land known as Gateway Hill has been issued a
certificate by Alberta Environment to date (2009).
Photo courtesy of
Suncor Energy Inc.
Settling ponds allow clay and
silt to settle out of the water
used in the extraction process.
A number of improvements
have been made to the design
and operation of in-situ oil
well casings.
Research and development to address land issues is continuing. Among the issues for
upgraders are the long-term disposal or utilization options for their stockpiles of sulphur
and coke.
The use of slanted and horizontal wells greatly reduces the land disturbance associated
with in-situ bitumen projects. One surface installation, known as a pad, may contain up to
10 well pairs producing from formations with a radius of more than a kilometre. Insulated,
above-ground pipelines carry steam and bitumen among facilities and well locations at
in-situ projects. When production ceases, regulations require that the wells be sealed with
cement and the biological productivity of the site be restored. In-situ reclamation is similar
in scale and timing to conventional oil reclamation.
Mining and in-situ oil sands projects, related seismic programs, roads, pipelines and
electrical power lines disturb substantial areas of boreal forest. The “linear disturbances”
fragment the landscape and affect wildlife habitat. An approach called Integrated
Landscape Management, developed by the Alberta Chamber of Resources in the late 1990s,
brings together oil companies and forestry companies to reduce their cumulative impacts
on landscapes, forest productivity and wildlife – through measures such as narrower
seismic cutlines and coordinated planning to reduce the number of roads. “Meandering”
cutlines reduce line-of-site corridors for predators, and on-site mulching of wastes speeds
reclamation. Research is also underway to improve reforestation of reclaimed sites.
Water resources
The National Energy Board estimates that between two and 4.5 barrels of water are needed
to produce a barrel of oil sands bitumen in oil sands mining operations. Most of this, up to
90 per cent in some cases, is recycled, and industry is working to reduce water use overall.
Some water is also returned to the hydrosphere through evaporation. In-situ development
is required by the provincial environmental and energy agencies to use brackish or nonpotable
groundwater for production. Most of the water utilized in oil sands mining comes
from surface water bodies, typically large adjacent rivers.
Scientific studies were conducted to determine how much water can be withdrawn from the
Athabasca River and other watersheds without negative effects on fish and aquatic life. The total
annual allocation of water from the Athabasca River for all uses (e.g., municipal, industrial and oil
sands) is less than 3.2 per cent of flow. This compares to 37 per cent for the North Saskatchewan
River (Edmonton), 60 per cent for the Oldman River (Southern Alberta) and 65 per cent for the
Bow River (Calgary).
Current oil sands mining projects use about one per cent of the total annual water flow of
the Athabasca River. Should all existing, approved and announced oil sands projects proceed,
industry would use 2.2 per cent of the Athabasca river flow.
Industry’s withdrawal of water from the Athabasca River is capped during periods of low river
flow to protect the aquatic ecosystem.
24 CANADA’S OIL SANDS THIRD edition November 2011

The industry-funded, multi-stakeholder Regional Aquatics Monitoring Program (RAMP)
has been assessing regional watersheds, fish populations and aquatic ecosystems in the
Athabasca oil sands area since 1997. In 2010, RAMP reported that differences between
baseline flow rates and 2009 flow rates were negligible to low at eight test sites, moderate at
one test site and high at four. Similarly, differences between baseline water quality conditions
and 2010 water quality conditions at test sites were negligible to low at all 17 test sites.
Differences in invertebrate populations were negligible to low at six test sites, moderate at six
test sites and high at two sites.
The federal Fisheries Act requires that developers compensate for loss of fish habitat. The
ratio for compensation is at least two-to-one; that is, for each unit of habitat lost, at least two
units of equivalent habitat must be created, restored or protected elsewhere in the region.
The tailings ponds at oil sands mining projects pose additional challenges. In the extraction
process at the mining projects, the water picks up tiny particles of clay. Ponds are used
to hold the resulting tailings, a mixture of clay, water and trace amounts of unrecovered
bitumen. Oil sands mining developers are using various methods for managing the tailings
over the long term. Tailings ponds are not used in in-situ projects.
There are two methods of reclaiming tailings ponds, water-capped lakes and solid
landscapes. With water-capped lakes, a layer of fresh water is placed over the tailings; this
water cap could function as a normal aquatic ecosystem while the clay particles slowly
drift to the bottom. Because there is still some debate about whether the settling ponds
can become biologically productive ecosystems over the long term, the developers are
continuing to study the matter.
With solid or dry landscapes, gypsum is used to accelerate the settling time and create
consolidated tailings. Without the gypsum, the coarse sand fraction of the tailings settles
out faster than the finer clays, which may take some years to form mature fine tailings, a
mixture of water and 30 per cent solids.
In the consolidated tailings process, the tailings stream is hydrocycloned to separate the
coarse sand fraction from the fine tailings and water. The sand is then mixed with mature
fine tailings and gypsum to form an unsegregated, stable mixture that consolidates
to approximately 80 per cent solids in less than one year. Calcium-rich water released
from the concentrated tailings is added to the fine tailings from the cyclone process to
accelerate settling and produce more consolidated fine tailings which are in turn mixed
with sand and gypsum.
In-situ projects have made a continuing effort to reduce water use through increased
recycling. Developers are required to use brackish (non-drinkable) water from underground
aquifers to meet part of their water needs.
Another issue for in-situ operations is the possibility that casing failures in steaming
operations could contaminate water supplies in underground aquifers. In the Cold Lake
area, investigations of the impacts of casing failures on groundwater quality found the
effects were restricted to the immediate vicinity of a casing failure. Produced fluids released
into an aquifer from a casing failure are recovered by pumping back the released fluids.
A number of improvements have also been made to the design and operation of in-situ
oil well casings. These improvements reduce the number of future casing failures and
Photo courtesy of EnCana
Carbon sequestration not only
dispose of C0 2
safely, it reduces
greenhouse gas emissions. In
some conventional oilfields, the
carbon dioxide from oil sands
emissions could be used to
enhance oil recovery.
CANADA’S OIL SANDS THIRD edition November 2011 25

minimize their consequences. For example, by detecting breaks earlier, when they are the
size of pinholes, the amount of fluid that may be released into a groundwater aquifer is
significantly reduced.
In the late 1990s, an extensive investigation of groundwater quality around in-situ heavy oil
operations was conducted by Komex International Ltd. and Imperial Oil. The study found
that regional groundwater quality had not been affected by in-situ operations. The study
also recommended that the monitoring of groundwater quality be enhanced. The enhanced
monitoring systems determine groundwater conditions prior to new developments, as well as
monitor groundwater quality during the operating life of the development.
Local and regional air quality
Oil sands mining, processing and upgrading produce emissions that affect air quality. New
technology and more efficient operations have greatly reduced emissions per barrel of
production, but the rapid increase in production has led to increases in some emissions
such as oxides of nitrogen (NO x
). Alberta authorities have stated that they will be watching
closely the cumulative effect of air emissions.
Between 1990 and 2010, the annual average NOx concentration increased between 18
and 36 per cent at monitoring stations in the Ft. McMurray area. However, mean annual
NOx concentrations in the oil sands regions remain below those in Edmonton and Calgary
and are well below regulatory limits. NOx emissions contribute to acid deposition and
also combine with volatile organic compounds and particulate matter in the presence of
sunlight to form ground-level ozone or smog. According to Environment Canada data, oil
sands accounted for 5.5 per cent of Alberta’s total emissions of NOx in 2010. Companies
have committed to use “best available technology economically achievable” to reduce NOx
emissions. For example, new truck engines emit considerably less NOx and gas-fired heaters
must comply with strict “low-NOx” emission standards.
Emissions of sulphur compounds and hydrocarbons also affect local air quality. Syncrude
and Suncor have reduced these by capturing gases formerly released into the atmosphere
or burned in open flares. The gases are captured in flue gas desulphurization units that
produce sulphur for use in making gypsum (Suncor) or fertilizer (Syncrude).
Upgraders remove up to 99.8 per cent of the sulphur from bitumen by converting it into
elemental sulphur or retaining it in the coke byproduct, so it is not released with endproduct
combustion. The remaining sulphur is released into the atmosphere as sulphur
dioxide (SO2). This may combine with water vapour to form sulphurous acid or sulphuric
acid and contribute to acid deposition that affects forests and water resources. According
to Environment Canada data, oil sands projects accounted for 35 per cent of Alberta’s total
sulphur dioxide emissions in 2010.
The Wood Buffalo Environmental Association monitors air quality in Fort McMurray and the
surrounding area. Monitoring includes continuous air quality data and periodic air samples.
Air quality in the region generally compares favourably with that of Alberta cities such as
Edmonton, Calgary and Fort Saskatchewan. Monitoring results in 2008 showed:
• The one-hour average readings for sulphur dioxide in Fort McMurray, Fort McKay and
Fort Chipewyan were below provincial objectives for ambient air quality
• There were two exceedances of the one-hour provincial objectives for sulphur
26 CANADA’S OIL SANDS THIRD edition November 2011

dioxide in areas close to the oil sands facilities
• There was one exceedance of the 24-hour provincial objectives for sulphur dioxide
• There were no exceedances of the one-hour provincial objective for nitrogen dioxide,
carbon dioxide, ammonia, ozone or particulate matter
• There were 614 exceedances of the one-hour average provincial objective for
hydrogen sulphide
• There were 118 exceedances of the 24-hour average provincial objective for
hydrogen sulphide
The Wood Buffalo Environmental Association also operates the Terrestrial Environmental
Effects Monitoring (TEEM), an ecological monitoring program that samples bogs, fens,
lichens and other plant growth to monitor nitrogen and sulphur. The Cumulative
Environmental Management Association (CEMA) has developed management frameworks
for terrestrial ecosystem, land capability, ozone management, landscape design, acid
deposition, ecosystems management, trace metals and nitrogen.
In all the oil sands areas, including Cold Lake and Peace River as well as Athabasca, monitoring
through 2008 showed that air quality was rated good more than 95 per cent of the time.
Greenhouse gases
Oil sands operations also emit large amounts of carbon dioxide and some methane. These
are among the heat-trapping greenhouse gases that affect global climate. In 2008, oil
sands facilities were the third largest source of reported GHG emissions in Alberta tied
with transportation accounting for 15 per cent or 36.6 megatonnes of total GHG emissions
(carbon dioxide equivalent) in the province. The utilities sector was the largest source of
greenhouse gas emissions in Alberta with 58.6 megatonnes or 24 per cent of total reported
GHG emissions.
In 2007, Alberta became the first jurisdiction in North America to legislate GHG reductions
for large industrial facilities. Any facility, including oil sands, that emits more than 100,000
tonnes of GHG per year is required to reduce their emissions intensity by 12 per cent from
2003-2005 levels starting in 2007. Facilities that fail to meet this target have the option of
buying Alberta-based carbon offsets, or paying $15 per tonne over reduction targets into
the Climate Change and Emissions Management Fund. The fund supports projects and
technologies aimed at reducing GHG emissions in the province.
As part of the long-term climate change plan Alberta plans to cut projected greenhouse
gas emissions by 50 per cent or 200 megatonnes of carbon dioxide equivalents by 2050. It
translates to real reductions of 14 per cent below 2005 levels.
To date, more efficient use of energy has been the main strategy to reduce greenhouse
gas emissions from oil sands. Research is underway into the possibility of capturing carbon
dioxide emissions from oil sands plants and injecting them underground, which is known
as carbon capture and storage (CCS) or carbon sequestration. In some conventional oilfields,
the carbon dioxide from oil sands emissions could be used to enhance oil recovery. Alberta
is the first jurisdiction in North America to direct dedicated funding to implement carbon
capture and storage across industrial sectors. CCS is forecast to deliver about 70 per cent of
the long-term climate change plan’s projected 200 megatonnes carbon dioxide equivalentreduction
by 2050, with the majority of those reductions coming from activities related to
oil sands production.
CANADA’S OIL SANDS THIRD edition November 2011 27

Offsets are another option to reduce global greenhouse gas emissions. Offsets are
reductions in emissions that are caused by an activity not directly related to the source
creating the emissions. Planting millions of trees to absorb carbon dioxide creates an offset
for whoever plants the trees. In an emissions-trading system, carbon dioxide offsets can be
traded on an emissions market.
From a global perspective, what matters is the total amount of greenhouse gases emitted
during a product’s “wells to wheels life cycle” from extraction to the final use by a
consumer. According to two independent studies commissioned by the Alberta Energy
Research Institute released in 2009, greenhouse gas emissions from the oil sands are
about 10 per cent higher than direct emissions from other crudes in the United States.
However, if cogeneration is taken into consideration, greenhouse gas emissions from oil
sands are similar to those from the other crudes.
The studies, Life Cycle Assessment Comparison of North American and Imported Crude,
researched and authored by Jacobs Consultancy Canada Inc. and Comparison of North
American and Imported Crude Oil Lifecycle GHG Emissions, researched and authored by TIAX
LLC, were conducted in 2008.
The studies also indicated that greenhouse gas emissions from conventional crudes are
rising because of the increasing reliance upon heavier crudes that are more difficult to
produce. Conversely, greenhouse gas emissions from oil sands crudes are decreasing
because of technological advances.
Quality of life
Tens of thousands of new jobs come from oil sands development. Workers and their
families have flocked to the oil sands region and elsewhere in the province. While this
growth has been a boon for these individuals, it puts great pressure on public services,
housing and infrastructure. Many businesses had trouble finding and keeping staff. During
consultations in 2006, some Albertans, including the mayor of Fort McMurray, urged a
slowdown in oil sands development so that other sectors could keep pace. In 2008 and
2009, the pace of development did slow due to economic conditions that caused the delay
or outright cancellation of some projects. Capital spending in 2009 dropped 38 per cent
from $18.1 billion to $11.2 billion. However, in 2010, capital spending increased 53 per cent
to $17.2 billion, the third highest on record.
Photo courtesy of
Shell Canada Ltd.
Oil sands projects have
created new opportunities
for local businesses, including
many enterprises owned and
operated by Aboriginal people.
However, oil sands projects also created new opportunities for local businesses, including
many enterprises owned and operated by Aboriginal people. Splitting contracts into many
components makes it possible for smaller companies to bid on them. Oil sands developers
use open house events, local media and ongoing consultation to ensure that local people
are aware of upcoming business opportunities. The Northeast Alberta Aboriginal Business
Association distributes contract information among its members, and the Regional
Economic Development Link or “Red Link” facilitates opportunities through information,
communications, promotions, research, networking, and sales.
Providing employment and business opportunities is, however, just one of the ways that
the industry is transforming the social fabric and economic well-being of the oil sands
areas. Aboriginal people make up about 10 per cent of the population in the Athabasca
28 CANADA’S OIL SANDS THIRD edition November 2011

oil sands area, and industry has made a concerted effort to provide opportunities for
them. Since the 1970s, the government and oil sands companies have established
programs to train and recruit Aboriginal people as employees, contractors and suppliers,
and the new projects seek Aboriginal involvement wherever possible. In 2010, there were
more than 1,700 Aboriginal people employed in operations jobs in the oil sands. About
$5 billion worth of contracts have been awarded to local Aboriginal companies since 1998
- $1.3 billion in 2010 alone.
The Canadian Energy Research Institute forecasts that 900,000 new jobs will be created
and preserved in the oil sands between 2010 and 2035. This includes direct, indirect and
induced employment.
Regulation and consultation
The Alberta Resources Conservation Board and Alberta Environment are the principal
regulators of oil sands operations in the province. Alberta Energy and Alberta Sustainable
Resource Development also have direct roles in oil sands regulation. The National Energy
Board regulates interprovincial and international aspects such as pipelines and exports.
Photo courtesy of
Imperial Oil Ltd.
Education initiatives and
consultation efforts help
educate surrounding
communities about
Canada's oil sands.
Large projects affecting interprovincial air and water resources, and related issues such
as fisheries, are typically subject to joint federal-provincial environmental assessment.
Provincial and federal energy, environment, health and safety authorities are also involved
in many aspects of oil sands regulation.
Through the Aboriginal Policy Framework released in 2000, Alberta committed to consult
with First Nations when land management and resource development decisions may
infringe their existing treaty or other constitutional rights. Beginning in September 2003,
Alberta engaged in dialogue with industry and First Nations about consultation and the
focus of consultation policy. The province’s First Nations Consultation Policy on Land
Management and Resource Development was approved on May 16, 2005. It reinforced
the commitment for consultation that was identified in the Aboriginal Policy Framework.
The policy outlines the province’s expectations of First Nations and resource companies
in striving for increased certainty for all parties with respect to land management and
resource development activities. In addition, it outlines the province’s approach to meeting
its consultation responsibilities.
Photo courtesy of
Imperial Oil Ltd.
Through the Aboriginal Policy
Framework released in 2000,
Alberta committed to consult
with First Nations when land
management and resource
development may infringe
their existing treaty or other
constitutional rights.
Following the release of the policy, the province worked with First Nations and industry
to develop a Framework for Consultation Guidelines and sector-specific consultation
guidelines. The framework was released on May 19, 2006 and the guidelines were
implemented on September 1, 2006. In addition, the Athabasca Tribal Council began
working with the government to develop specific consultation guidelines for the Athabasca
oil sands area where development has been most intense.
In 2000, two groups were created to address traditional environmental knowledge in
the Athabasca oil sands region. The Cumulative Environmental Management Association
formed a standing committee, the Traditional Environmental Knowledge Committee,
to provide guidance on how to incorporate Aboriginal expertise into their knowledge
base. The Reclamation Advisory Committee meanwhile created a sub-group to address
traditional knowledge. Much of the science and understanding used in reclamation and
environmental activities previously were based on Western knowledge. The members
of the two bodies were aware of the needs and desires of the people indigenous to
CANADA’S OIL SANDS THIRD edition November 2011 29

the Athabasca area, and wanted to incorporate their knowledge to have a greater
understanding of what environmental protection and reclamation should encompass.
Traditional ecological knowledge includes information from people with an understanding
of how past generations lived off of the land. This includes many First Nations people, Métis
and historians of local culture.
Research
The National Energy Board estimates that only about 10 per cent of Canada’s oil sands
resource can be recovered economically with current technology. The future of this
resource will be decided in the laboratory. Government and industry have invested
heavily in oil sands and in-situ research and development for decades, and much more
will undoubtedly be spent in the future to improve the technological, environmental and
economic performance of oil sands developments.
To date, the Alberta government and private industry have each invested more than
$1 billion in research to reduce the environmental footprint of oil sands development and
increase economic recoveries.
Several hundred researchers work in industry, university and government laboratories,
primarily in the Calgary and Edmonton areas, to find solutions to the scientific and
technological challenges facing the oil sands industry. Employees and contractors
throughout the industry constantly seek more efficient, cost-effective and environmentally
sensitive ways to do things.
Some of the immediate challenges facing the scientists and technologists include: reducing
emissions of oxides of nitrogen and greenhouse gases; reducing water use and natural
gas consumption; improving the efficiency of oil sands mining, bitumen extraction and
in-situ recovery; obtaining a higher yield of desirable products from upgrading; reducing
equipment maintenance requirements; reducing the need to dilute bitumen for pipeline
transportation; and improving tailings management and reclamation methods.
Research partners from industry, the academic community and government coordinate
their efforts through associations such as the Petroleum Technology Alliance Canada
(PTAC), Canadian Oil Sands Network for Research and Development (CONRAD), the Alberta
Chamber of Resources’ Oil Sands Task Force, Black Oil Pipeline Network Steering Committee,
the CO2 Synergies Research Network, and Coordination of University Research for Synergy
and Effectiveness (COURSE).
The Alberta Energy Research Institute's research priorities with regard to oil sands include
improving bitumen upgrading; demonstrating clean carbon/coal is a viable fuel for
producing electricity; improving oil recovery technologies; developing technologies that
reduce greenhouse gas emissions; supporting new technology to reduce fresh water use by
the energy industry and advancing and adapting technology for alternative energy sources.
30 CANADA’S OIL SANDS THIRD edition November 2011

The path ahead
North Americans have a huge appetite for oil products. Each Canadian and American uses
an average of more than 20 barrels (3,178 litres) worth of petroleum-based products and
services per year.
Today, it is not possible for historic domestic sources of production to meet this demand.
Conventional light crude oil production is declining throughout most oil-producing areas of
the United States and Western Canada. The United States already imports more than half of
its oil supplies. Canada has continued to export more oil than it imports.
In fact, Canada has actually increased oil production thanks to oil sands, heavy oil and
offshore oil development. Offshore, Arctic and conventional oil resources can maintain
Canadian production and revenues for a while, but the oil sands are the nation's principal
petroleum source for the long haul.
Human ingenuity has already accomplished a great deal by making the oil sands
economically competitive with conventional oil. Environmental and social challenges
are being engaged. Continuous improvement in science, technology and management
are helping to overcome the remaining challenges to meet society’s expectations for
sustainable development.
CANADA’S OIL SANDS THIRD edition November 2011 31

For further information
Publications
Alberta Energy and Natural Resources. Energy Heritage – Oil Sands and Heavy Oils of Alberta. Edmonton: 1982.
Alberta Energy Research Institute. Life Cycle Analysis of North American and Imported Crude Oils. Two studies
commissioned and released by AERI: Life Cycle Assessment Comparison of North American and Imported Crude,
researched and authored by Jacobs Consultancy Canada Inc. and Comparison of North American and Imported Crude
Oil Lifecycle GHG Emissions, researched and authored by TIAX LLC. 2009.
AEUB. Crude Bitumen Reserves Atlas. Calgary: May 1996.
Alberta Oil Sands Technology and Research Authority. AOSTRA – A 15-Year Portfolio of Achievement. Edmonton: 1990.
Bryson, Connie, ed. Opportunity Oil Sands. Winnipeg: Fleet Publications Inc., 1996.
Bott, Robert. “True Grit – How Syncrude Manages for Success,” The Globe and Mail Report on Business Magazine.
Toronto: May 1995.
Canadian Association of Petroleum Producers. 2005 CAPP Stewardship Progress Report. Calgary: 2006.
Canadian Association of Petroleum Producers. Statistical Handbook for Canada’s Upstream Petroleum Industry. Calgary:
September 2011.
Canadian Association of Petroleum Producers. Upstream Dialogue: The Facts on Oil Sands. Calgary: October 2011
Canadian Energy Research Institute. Canadian Oil Sands Supply Costs and Development Projects (2010-2044), Study 122.
Calgary: May 2011.
Canadian Energy Research Institute. Economic Impacts of New Oil Sands Projects in Alberta (2010‐2035), Study 124.
Calgary: May 2011.
Canadian Energy Research Institute. Economic Impacts of Alberta’s Oil Resources: September 2008 Update, Vol. 1.
November 2008.
Canadian Energy Research Institute. Economic Impacts of the Petroleum Industry in Canada. July 2009.
Chastko, Paul. Developing Alberta’s Oil Sands, From Karl Clark to Kyoto. University of Calgary Press, 2004.
Comfort, Darlene J. The Abasand Fiasco: The rise and fall of a brave pioneer oil sands extraction plant. Edmonton:
Friesen Printers, 1980.
De Bruijn, Theo. Challenges for Low Cost Upgrading – A Canadian Perspective. Devon, Alberta: National Centre for
Upgrading Technology, December 1998.
Energy Resources Conservation Board. ST98-2011: Alberta’s Energy Reserves 2010 and Supply/Demand Outlook 2011-
2020. Calgary: June 2011.
Energy Resources Conservation Board. ST98-2010: Alberta’s Energy Reserves 2009 and Supply/Demand Outlook 2010-
2019. Calgary: June 2010.
Energy Resources Conservation Board. Alberta’s Energy Reserves 2008 and Supply/Demand Outlook 2009-2018. ST98-
2009. Calgary: June 2009
Ferguson, Barry Glen. Athabasca Oil Sands – Northern Resource Exploration, 1875-1951. Regina: Canadian Plains
Research Centre, 1985.
Fitzgerald, J. Joseph. Black Gold with Grit: The Alberta Oil Sands. Sidney, British Columbia: Gray’s Publishing Ltd., 1978.
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. Ottawa: Energy, Mines and Resources Canada, Canada
Centre for Mineral and Energy Technology, 1981.
McCann, T.J., and Phil Magee. “Crude Oil Greenhouse Gas Life Cycle Analysis Helps Assign Values For CO2 Emissions
Trading,” The Oil and Gas Journal. Tulsa, Oklahoma: February 22, 1999.
McKenzie-Brown, Peter; Gordon Jaremko, and David Finch. The Great Oil Age. Calgary: Detselig Publishers, 1993.
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 Crude and
Tar Sands, paper 1998.096.
Mink, Frank, and Richard N. Houlihan. “Tar Sands,” p. 129, Vol. A26, Ullmann’s Encyclopedia of Industrial Chemistry.
Weinheim, Germany: 1995.
32 Oil Sands Questions + Answers 3rd edition

Mitchell, Robert; Brad Anderson, Marty Kaga, and Stephen Eliot. Alberta’s Oil Sands: Update on the Generic Royalty
Regime. Edmonton: Alberta Department of Energy, 1998.
National Energy Board. 2009 Reference Case Scenario: Canadian Energy Demand and Supply to 2020. Ottawa: July
2009.
National Energy Board. Canada’s Energy Future: Scenarios for Supply and Demand to 2025. Calgary: 2003.
National Energy Board. Canada’s Oil Sands: Opportunities and Challenges to 2015. Calgary: May 2004.
National Energy Board. Canada’s Oil Sands – Opportunities and Challenges to 2015: An Update. Calgary: June 2006.
National Oil sands Task Force. A New Era of Opportunity for Canada’s Oil Sands. Edmonton: Alberta Chamber of
Resources, 1996.
Oil Sands Ministerial Strategy Committee. Investing in Our Future – Final Report. Edmonton: Government of Alberta,
2007. (Downloaded March 2, 2007 from http://www.gov.ab.ca/home/index.cfm?page=1551)
Prince, J.P., and Govinda Timilsina. Spreading the Wealth Around: The Economic Impacts of Alberta’s Oil Sands Industry.
Calgary: Canadian Energy Research Institute, September 2005.
Regional Aquatic Monitoring Program. 2010 Technical Report. Fort McMurray: 2011.
Regional Municipality of Wood Buffalo. Municipal Census 2007. Fort McMurray, 2007.
Regional Municipality of Wood Buffalo. Municipal Census 2010. Fort McMurray, 2010.
Rolheiser, Pius. “Riddle of the Sands,” Imperial Oil Review. Toronto: Summer 1998.
The Royal Tyrrell Museum of Paleontology. The Land Before Us – The Making of Ancient Alberta. Red Deer, Alberta: Red
Deer College Press, 1994.
Russell, Loris S. “Abraham Gesner,” Dictionary of Canadian Biography. Toronto: University of Toronto Press, 2000.
Shell Canada Ltd. 2010 Oil Sands Performance Report. Calgary: 2011
Sheppard, Mary Clark, ed. Oil Sands Scientist – The Letters of Karl A. Clark, 1920-1949. Edmonton: The University of
Alberta Press, 1989.
Statistics Canada. Energy Statistics Handbook, Second Quarter 2011. Ottawa: September 2011.
Statistics Canada. International Merchandise Trade Annual Review 2010. Ottawa: April 2011.
Statistics Canada. The Supply and Distribution of Refined Petroleum Products in Canada. Ottawa: July 2011.
Suncor Energy Inc. 2011 Summary Report on Sustainability. Calgary: July 2011
Syncrude Canada Ltd. 2009 Sustainability Report. Fort McMurray 2010
Wood Buffalo Environmental Association. 2010 Annual Report. Fort McMurray 2011
Woynillowicz, Dan, Chris Severson-Baker and Marlo Raynolds. Oil Sands Fever: The Environmental Implications of
Canada’s Oil Sands Rush. Calgary: Pembina Institute, November 2005.
Oil Sands Questions + Answers 3rd edition 33

Websites
The Canadian Centre for Energy Information web portal www.centreforenergy.com provides up-to-date information
about oil sands and crude oil in Canada. The Centre for Energy’s general introduction to the industry, Our Petroleum
Challenge, can be purchased online and provides information about drilling, pipelining and processing of crude oil
and natural gas as well as a glossary of industry terms.
Note: Most U.S. references, and some Canadian and international entities, use the American spelling for sulphur and
related compounds. When doing searches in libraries or on the Internet, also remember to check for “sulfur, sulfide,
sulfuric, sulfurous, etc.” as well as the Canadian spellings.
Alberta Energy www.energy.gov.ab.ca
Alberta Energy Research Institute www.aeri.ab.ca
Alberta Environment www.environment.gov.ab.ca
Alberta Federation of Labour www.afl.org
Alberta Geological Survey www.ags.gov.ab.ca
Alberta Oil Sands www.oilsands.alberta.ca
Alberta Utilities Commission www.auc.ab.ca
Canadian Association of Petroleum Producers www.capp.ca
Canadian Energy Research Institute www.ceri.ca
Canadian Heavy Oil Association www.choa.ab.ca
Canadian Natural Resources Limited www.cnrl.com
Clean Air Strategic Alliance www.casahome.org
Energy Information Administration www.eia.gov
Energy Resources Conservation Board www.ercb.ca
Environment Canada www.ec.gc.ca
In Situ Oil Sands Alliance www.iosa.ca
National Energy Board www.neb-one.gc.ca
Natural Resources Canada www.nrcan-rncan.gc.ca
Oil Sands Developers Group www.oilsandsdevelopers.ca
Pembina Institute www.pembina.org
Regional Aquatics Monitoring Program www.ramp-alberta.org
Regional Economic Development Alliance http://www.albertacanada.com/regionaldev/1218.html
Wood Buffalo Environmental Association www.wbea.org
34 Oil Sands Questions + Answers 3rd edition

Key definitions
Hydrocarbons are compounds of hydrogen and carbon. The simplest hydrocarbon is methane (CH4), composed of one
carbon atom and four hydrogen atoms. Methane is the principal component of natural gas.
Crude oil is a naturally occurring liquid mixture of hydrocarbons. It typically includes complex hydrocarbon molecules
– long chains and rings of hydrogen and carbon atoms. The liquid hydrocarbons may be mixed with natural gas, carbon
dioxide, saltwater, sulphur compounds and sand. Most of these substances are separated from the liquid hydrocarbons at
field processing facilities called batteries. Conventional light crude oil flows easily at room temperature.
Upgraded crude oil is a blend of hydrocarbons similar to light crude oil. It is produced by processing bitumen or heavy oil
at a facility called an upgrader. The term synthetic crude oil is sometimes also used for upgraded crude oil.
Bitumen is a thick, sticky form of crude oil. At room temperature, bitumen has the consistency of molasses. It must be
heated or diluted before it will flow easily into a well or through a pipeline. Bitumen is sometimes called extra-heavy crude
oil. A typical dictionary definition of bitumen is “a tar-like mixture of petroleum hydrocarbons.” A more technical definition
in the oil-producing industry is: A naturally occurring, viscous mixture of hydrocarbons that contains sulphur compounds
and will not flow in its naturally occurring viscous state.
Diluents are light petroleum liquids used to dilute bitumen and heavy crude oil so it can flow through pipelines.
Oil sands are naturally occurring mixtures of bitumen, water, sand and clay that are found mainly in three areas of Alberta
– Athabasca, Peace River and Cold Lake. A typical sample of oil sands might contain about 12 per cent bitumen by weight,
although bitumen content can vary widely among specific samples and sites. If the oil sands deposits are close to the
surface, bitumen can be recovered from the oil sands by open-pit mining and hot-water processing methods. Deeper
deposits require in-situ methods such as steam injection through vertical or horizontal wells. (In-situ means “in-place” in
Latin; the oil industry uses this term to indicate the bitumen is separated from the sand underground, in the geological
formation where it occurs.) Surface mining is used in the Athabasca oil sands, while in-situ methods are used in all three
major oil sands areas.
Heavy crude oil includes some crude oil that will flow at room temperatures, however slowly, but most heavy oil also
requires heat or dilution to flow to a well or through a pipeline. Therefore it is similar to bitumen, although lighter, generally
less viscous and usually containing less sulphur. In Canada, the term heavy oil refers to petroleum with a density greater
than 900 kilograms per cubic metre (or below 25.7°API on the American Petroleum Institute gravity scale).
Petroleum is a general term for all the naturally occurring hydrocarbons – natural gas, natural gas liquids, crude oil and
bitumen – although in some usage petroleum refers only to liquid hydrocarbons.
Natural gas liquids (NGLs) are ethane, propane, butane and condensates (pentanes and heavier hydrocarbons) that are often
found in natural gas; some of these hydrocarbons are liquid only at low temperatures or under pressure. NGLs can be used as
solvents for in-situ bitumen production, and condensates are the most common diluent for shipping bitumen by pipeline.
Resources are substances found in nature that are of some use. Bitumen resources, for example, are all the extra-heavy
hydrocarbons in the ground in a given area.
Reserves are the recoverable portion of resources. Governments generally define reserves as the amounts available for use
based on current knowledge, technology and economics. Securities regulators use a narrower definition that also requires
a firm development plan with reasonable timelines. As a result, there can be a wide gap between government reserves
estimates and the sum of those reported by companies.
Barrel is a common unit for measuring petroleum. One barrel contains approximately 159 litres. There are about 6.3 barrels
in one cubic metre.
All costs in this booklet are quoted in Canadian dollars unless otherwise noted.
Oil Sands Questions + Answers 3rd edition 35

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