Is Nuclear Technology an Appropriate
Alternative to Natural Gas for
Alberta’s Oilsands?
BUEC 663
Capstone Course
Professor: Joseph Doucet
Brad Wooley
April 13 2007
Table of Contents
1
Introduction
2
Current Oil Sands Operations and Natural Gas
2.1
2.2
2.3
3
Current Oil Sands Operations
Natural Gas Demand for Oil Sands Operations
Greenhouse Gas Emissions from Natural Gas-Fuelled Oil Sands
Nuclear Technology and its Application to the Oil Sands
3.1
3.2
3.3
Nuclear Technology Development in Canada
The CANDU Reactor
Application of Nuclear Technology to the Oil Sands
3.3.1 Surface Mining versus In-Situ Application
3.3.2 Potential Use of Nuclear Technology
3.3.2 Nuclear vs. Natural Gas at a Project Level
4
Sustainability of Nuclear Technology for the Oil Sands
4.1
Fuel Supply for Nuclear Technology
4.1.1 Reactor Uranium Requirements
4.1.2 Uranium Supply
4.2
Environmental Implications
4.2.1 GHG Emissions
4.2.2 Water Implications
4.2.3 Waste Management
5
Regulation of Nuclear Technology
6
Conclusion
1
Introduction
Canada is the world’s seventh largest oil producer at over 2.5 million barrels per
day in 2005 and this production is expected to increase to over 4.6 million barrels per day
by 2015. Most of Canada’s production is from conventional crude, but the vast majority
of Canada’s reserves are actually in the Alberta oil sands. More than one million barrels
per day (bpd) of Canada’s oil is from the Alberta oil sands and the Canadian Association
for Petroleum Producers (CAPP) expects this production will more than triple by 2015.1
Extracting and refining oil from the oil sands requires an incredible amount of
energy. The primary source of energy for Alberta’s oil sands is natural gas. Along with
the use of water and reduction of emissions, the use of natural gas in the extraction and
processing of oil sands represents one of the greatest challenges facing the oil sands
industry today. With increased natural gas prices, decreasing supply and increased
demand of natural gas and increased focus on the reduction of greenhouse gas emissions,
of which the oil sands industry is a large contributor, the need to find an alternative to
natural gas is made all the more pressing.
One potential alternative source of energy for the Alberta oil sands industry in
nuclear power. Nuclear power generation has never been a part of Alberta’s energy
industry, but at least one Alberta company has considered building a C$5.5 billion ($4.7
billion) nuclear plant in the oil sands region to generate steam and electricity, which are
both key to the process that separates bitumen from the oil sands.
1
Canadian Association for Petroleum Producers. The Canadian Oil Sands, Opportunities and Challenges.
February 2006. http://www.capp.ca/raw.asp?x=1&dt=PDF&dn=98992
Energy Alberta Corp. wants to put a Canadian-designed Candu twin-reactor plant
in the region by 2016. The steam produced by the facility would be piped to thermal oil
sands producers, who could pump it into the ground to liquefy the bitumen.
The electricity produced could replace natural gas-fired generation plants, cutting
emissions of carbon dioxide.2
There are many challenges to consider with respect to the introduction of nuclear
power generation in Alberta. In general, these challenges include but are not limited to;
technology development, public and government resistance to nuclear power in Alberta
and significant environmental concerns, including the long-term storage of radioactive
waste and impact to water resources in Alberta.
The intent of this paper is to determine whether or not nuclear energy is a viable
option for Alberta’s oil sands industry. The paper will provide a brief overview of the
different types of oil sands operations and their current demand for natural gas as the
primary energy supply. Current nuclear power generation technologies and potential
application to the oil sands industry will be discussed. In terms of sustainability of
nuclear power in Alberta, the supply of uranium for nuclear power generation and the
potential environmental implications will also be considered. Finally, a brief overview of
regulation of nuclear power in Canada and a conclusion will be provided.
2
Canada wary of nuclear power for oil sands. March-2007. http://ca.today.reuters.com/news
2
Current Oil Sands Operations and Natural Gas
2.1
Current Oil Sands Operations
There are two types of oil-sands operations in Alberta. The more shallow deposits
are harvested in a strip-mining-style, where earth is peeled back and massive trucks and
shovels remove the product. It is then super-heated with water or steam, and the tar-like
bitumen is removed.
Right now mining is the largest component, more than 60 percent of production of
oil sands. More than 80 percent of global reserves are too deep for conventional surface
mining operations. Two primary technologies -- called "in situ" technologies have been
developed for deep extraction.
Cyclic Steam Stimulation (CSS) uses high-pressure steam delivered through pipes
to heat up the heavy bitumen, which is brought to the surface.
For Steam Assisted Gravity Drainage, a method gaining in popularity, two
parallel pipes are drilled vertically and then jut in a 90-degree angle. The top pipe injects
steam, and the one below collects the bitumen and draws it to the surface. Both in situ
and surface mining bitumen needs further intensive processing and upgrading so that it is
capable of being refined or sent away in a pipeline.
2.2
Natural Gas Demand for Oil Sands Operations
Natural gas-fired facilities generate steam and provide process heat for the
bitumen recovery, extraction and upgrading of Alberta’s oil sands. Further, natural gas
provides a source of hydrogen used in hydroprocessing and hydrocracking as part of the
upgrading process. Although there is considerable variation between individual projects,
it takes up to 1000 cubic feet of natural gas to produce one barrel of bitumen from in situ
recovery. The demand for mining recovery is a more modest 250 cubic feet per barrel
(see Table 1.0 below).
Table 2.0 – Natural Gas Requirements for Alberta Oil Sands
(Cubic feet per barrel of synthetic crude)
In 2004, the Alberta Chamber of Resources stated that in terms of natural gas use
by the oil sands industry in Alberta the “business as usual” case is “clearly unsustainable
and uneconomical”.3 An extrapolation of natural gas usage (demand) by oil sands
development to 2030, based on 2004 project natural gas rates, would rise from 10% of
the total natural gas supply in 2010 to an unthinkable 60% or more by 2030.
.
2.3
Greenhouse Gas Emissions from Natural Gas-Fuelled Oil Sands
Air emissions from natural gas powered oil sands operations include carbon
dioxide (CO2), sulphur dioxide (SO2) nitrogen oxides (NOx), hydrogen sulphide (H2S),
carbon monoxide (CO), methane and other volatile organic compounds, ozone and
particular matter. The most critical air emissions issue facing the industry today is the
3
Alberta Chamber of Resources. Oil Sands Technology Roadmap. 2004.
http://www.acr-alberta.com/ostr.htm
implementation of the Kyoto Protocol and its potential impact on climate change. The
Kyoto Protocol specifically targets CO2 Equivalent (CO2E) emissions. The CO2E
emissions as a result of oil sands development are expected to exceed the 2012 Kyoto
Target without significant reductions in CO2E emissions intensity.4 The impact of the oil
sands industry could be even larger if residues or coal are used as an alternative to natural
gas for energy and hydrogen (see Figure 2.1 below).
Figure 2.1: Greenhouse Gas Emissions
from Oil Sands Development
The emissions from mining-based recovery is estimated at 40 kg CO2E per barrel
with natural gas feed and In-Situ-based recovery using natural gas as a fuel will emit
approximately 60 kg CO2E per barrel. Upgrading the bitumen to synthetic crude oil
using hydrogen from natural gas emits 70 kg CO2E per barrel.5
4
Alberta Chamber of Resources. Oil Sands Technology Roadmap. 2004.
http://www.acr-alberta.com/ostr.htm
5
A Crash Program Scenario for the Canadian Oil Sands Industry. Kjell Aleklett. June-2006.
http://www.peakoil.net/uhdsg/20060608EPOSArticlePdf.pdf
3
Nuclear Technology and its Application to the Oil Sands
3.1
Nuclear Technology Development in Canada
The Nuclear industry in Canada dates back to 1942 when a joint British-Canadian
laboratory was set up in Montreal, under the administration of theNational Research
Council of Canada, to develop a design for a heavy-water nuclear reactor. This reactor
was called National Research Experimental and would be the most powerful research
reactor in the world when completed. In 1944, approval was given to proceed with the
construction of the smaller ZEEP (Zero Energy Experimental Pile) test reactor at Chalk
River, Ontario and in Sept-1945, the 10 Watt ZEEP successfully achieved the first selfsustained nuclear reaction outside the United States. ZEEP operated for 25 years as a key
research facility.6
In 1952, the Canadian Government formed Atomic Energy of Canada Ltd.
(AECL), a Crown corporation with the mandate to develop peaceful uses of nuclear
energy. In 1954, a partnership was formed between AECL, Ontarion Hydro and
Canadian General Electric to build Canada's first nuclear power plant, called the Nuclear
Power Demonstration (NPD). The 20 MWe NPD started supplying Canada’s first nuclear
generated electricity in 1962 and successfully demonstrated the unique concepts of onpower refuelling using natural uranium fuel, and heavy water moderator and coolant.
These features formed the basis of a successful fleet of CANDU power reactors.
CANDU is an acronym for CANada Deuterium Uranium built and operated in Canada
and elsewhere.7
6
7
CANDU Owners Group. http://www.candu.org/candu_reactors.html
AECL. http://www.aecl.ca/About.htm
3.2
The CANDU Reactor
There are 29 CANDU reactors in use around the world, and a further 11 CANDU-
Derivatives in use in India. The reactors in India were developed from the CANDU
design after India detonated a nuclear bomb and Canada stopped nuclear dealings with
India.8 A total of 18 CANDU reactors are operating in Canada and an additional two are
in the process of being refurbished. The province of Ontario dominates Canada’s nuclear
industry, containing most of the country’s nuclear power generating capacity. Ontario
has 16 operating reactors providing about 50% of the province’s electricity. The
provinces of Quebec and New Brunswick each have a one reactor. Overall, nuclear
power provides about 15% of Canada’s electricity.
The CANDU designer is AECL (Atomic Energy of Canada Limited).. Over 150
private companies in Canada supply components for the CANDU system (AECL takes
the lead role in developing the markets and projects, while drawing in Canadian and offshore partners. In general, AECL acts as project integrator; most of the revenues flow to
private industry.
The CANDU reactor uses natural uranium fuel and heavy water (D2O) as both
moderator and coolant. In the CANDU design, the heat of fission is transferred, via a
primary water coolant, to a secondary water system. The two water systems "meet" in a
bank of steam generators, where the heat from the first system causes the second system
(at lower pressure) to boil. This steam is then dried and passed to a series of highpressure and low-pressure steam turbines. The turbines are connected in series to an
8
Wikipedia. CANDU Reactor. http://en.wikipedia.org/wiki/CANDU_reactor
electrical generator. The primary water system, which becomes radioactive over time,
does not leave the reactor's containment building.
It is a highly complex system from start to finish, involving a series of energy
transformations with associated efficiencies. The potential energy of nuclear structure is
converted first to heat via the fission process, then steam pressure, kinetic energy (of the
turbine and generator), and ultimately to electrical energy if the reactor is required for
electricity.. 9
Figure 3.1 – Schematic of the CANDU Reactor
All CANDU reactors follow the same basic design, although variations can be
found in most units. Power output in current operating units ranges from 125 MWe up to
over 900 MWe. There are several advanced-CANDU products under development by
AECL. The CANDU-ACR (Advanced CANDU Reactor) is the next generation of
CANDU reactors, currently being brought to market by AECL. The CANDU-ACR
retains the fundamental features of CANDU design, while optimizing others to achieve
higher efficiency and lower capital cost.
9
CANDU Nuclear Power Technology. http://www.nuclearfaq.ca/cnf_sectionA.htm#a
3.3
Application of Nuclear Technology to the Oil Sands
3.3.1 Surface Mining versus In-Situ Application
The primary objectives of nuclear technology development in Alberta for the oil
sands industry would be to produce steam for the recovery process, hydrogen for the
upgrading process and electricity to meet increased demand. The use of nuclear
technology would significantly reduce the demand for natural gas, which would reduce
CO2E emissions from oil sands operations and decrease the industries sensitivity to
fluctuating natural gas prices.
The volume of steam and natural gas required per barrel of bitumen recovered
from SAGD operations (1000 mcf NG) are approximately four times the volume required
for surface mining operations (250 mcf NG).10 For this reason, the greatest potential for
nuclear technology development in the Alberta oil sands is to supply steam for the steamintensive SAGD operations. In-Situ operations (primarily SAGD) currently provide
approximately 43% of total oil sands production and are expected to contribute almost
50% of oil sands production by 201511. With future technology development, the
contribution of bitumen recovered from in-situ operations relative to the overall recovery
of bitumen in Alberta could increase significantly.
10
Alberta Chamber of Resources. Oil Sands Technology Roadmap. 2004.
http://www.acr-alberta.com/ostr.htm
11
Canadian Association of Petroleum Producers. www.capp.ca
3.3.2
Potential Use of Nuclear Technology
In 2005, a company called Energy Alberta Corporation was formed with the
intent of using nuclear power to provide steam, electricity and hydrogen to support oil
sands growth in Alberta. In August of 2006, the company entered into an exclusivity
agreement with AECL to market own and operate a CANDU reactor12. The strategic
approach of the company is four-pronged and intends to use nuclear technology for the
following;
•
Provide steam supply for the SAGD process in the oil sands
Note: A significant challenge with respect to the supply of steam for SAGD is the fact that highpressure steam can only be economically transported a distance of 15-km, so a nuclear steam
plant must be located within a radius of 15 km of large in-situ oil sands deposits.
•
Generate electricity to support the extraction process of the oil sands
•
Generate hydrogen and electricity for upgrading crude bitumen
•
Supply electricity for Alberta utilities
Additional opportunities for the use of nuclear technology include the use of
oxygen, which is a byproduct of hydrogen produced from water, to produce liquid
transport fuels from natural gas or as a means of producing CO2 rich exhaust from
combustion processes. CO2 can be used to enhance oil recovery while simultaneously
sequestered underground. Zirconium production from the zircon concentrated in the
waste may also be feasible.13
12
Nuclear’s New Frontiers and the Canadian Oil Sands. March 1 2007. Wayne Henuset.
http://www.cna.ca/seminar2007/docs/presentation_henuset.pdf
13
Nuclear Energy in Industry: Application to the Oil Industry.
http://www.cns-snc.ca/events/CCEO/nuclearenergyindustry.pdf
3.3.2
Nuclear vs. Natural Gas at a Project Level
In 2003, Atomic Energy of Canada Limited (AECL) contracted the Canadian
Energy Research Institute (CERI) to compare the economics of nuclear and gas-fired
options to supply steam to an oil sands reservoir using SAGD technology.14 The
comparison was made between an ACR-700 (Advanced CANDU Reactor), with a gross
output of 728 MWe and a typical natural gas-fired facility. Each facility produced
enough steam to supply a 157 barrel per day SAGD operation and approximately 100
MW of electricity.
The capital requirement for the nuclear facility ($1400M) was significantly higher
than the natural gas-fired facility ($230M), but the high capital cost of the nuclear facility
was significantly offset by the lower cost of fuel for the nuclear facility. A summary of
the annual cost per tonne of steam supplied is outlined in Table 3.1. The project
comparison, which was completed in 2002, assumed a natural gas price of C$4.25/GJ.
The current forecast for the price of natural gas in 2007/2008 is between C$6.00/GJ and
C$8.00/GJ.15
Table 3.1: Steam Supply Costs ($/t)
14
Potential for Nuclear Energy in Alberta’s Oil Sands. 2003. Robert Dunbar.
http://www.strategywest.com/downloads/choa20031118.pdf
15
Canadian Natural Gas Outlook. November 2006. Natural Resources Canada.
http://www2.nrcan.gc.ca/es/erb/CMFiles/WINTER_OUTLOOK_2006_ENGLISH209OEQ-061120064763.pdf
The economics of the project comparison clearly identified the fact that the steam
supply costs from a nuclear facility are very sensitive to the capital cost of the project and
the costs associated with the natural gas-fired facility are very sensitive to the price of
natural gas. With respect to the price of natural gas, the break-even point was
approximately C$4.00/GJ. If natural gas prices were higher than C$4.00/GJ, the nuclear
facility would supply steam to the SAGD operation at a lower cost per tonne of steam
(see Figure 3.2).16
Figure 3.2: Natural Gas Price Sensitivity
The study also took into consideration the amount of GHG emissions for each
facility. The natural gas-fired facility produced 3Mt of GHG per year and the nuclear
facility produced no GHG. This difference highlighted the gas-fired facility’s potential
sensitivity to future Kyoto compliance costs, which would further increase the difference
between the steam supply costs, in support of the nuclear facility.
16
Potential for Nuclear Energy in Alberta’s Oil Sands. 2003. Robert Dunbar.
http://www.strategywest.com/downloads/choa20031118.pdf
4
Sustainability of Nuclear Technology for the Oil Sands
4.1
Fuel Supply for Nuclear Technology
4.1.1
Reactor Uranium Requirements
Canada’s 18 operating power reactors, with combined capacity of some 12.5
GWe, require about 2000 tonnes of uranium (tU) from mines each year17. This is
equivalent to approximately 160 tU per GWe. While this capacity is being run more
productively, with higher capacity factors and reactor power levels, the uranium fuel
requirement is increasing but not necessarily at the same rate. The factors increasing fuel
demand are offset by a trend for higher burn up of fuel and other efficiencies, so demand
is relatively steady. Reducing the tails assay in enrichment reduces the amount of natural
uranium required for a given amount of fuel and reprocessing of spent fuel from
conventional light water reactors also utilizes present resources more efficiently, by a
factor of about 1.3 overall.
4.1.2
Uranium Supply
Canada’s known recoverable uranium resources are 444,000 tU, which is the
equivalent of 9% of the world’s total. Australia and Kazakhstan are the only two
countries in the world with more recoverable uranium, accounting for 24% and 17%
respectively.18 Canada produces approximately one third of the world’s uranium mine
output and production is expected to increase further as new mines come into production.
In 2006, 9863 tU of uranium were produced from Saskatchewan production centers and
17
Natural Resources Canada. 2005. Canada’s Uranium Industry.
http://www2.nrcan.gc.ca/es/erb/erb/english/View.asp?x=497&oid=1188
18
Supply of Uranium. World Nuclear Association. http://www.world-nuclear.org/info/inf75.html
approximately 1400 tU was used for domestic reactors, the remaining uranium was
exported from Canada around the world. To put this in perspective in terms of nuclear
technology for the oil sands, if two ACR-700 reactors, equivalent to ~1.4 GWe, were
constructed and in operation in Alberta, using 160 tU per GW, the use of uranium for
domestic reactors in Canada would increase from 1400 tU to approximately 1624 tU or
slightly over 15%. The increased tonnes mined to support two ACR-700 reactors would
be equivalent to approximately 2% of total Uranium production in Canada. Assuming
production of uranium from northern Saskatchewan remains relatively constant and
ignoring new discoveries from exploration, the currently proven and recoverable reserves
will last approximately 40 years.
Canada has almost completed a transition from second-generation uranium mines
(started 1975-83) to new high-grade mines, all in northern Saskatchewan. The
Saskatchewan government actively encourages and supports uranium mining in the
province where it is found to be environmentally acceptable. There are three uranium
mines operating in northern Saskatchewan, the largest producer being the McArthur
River Mine, which produced 8492 tU in 2006.19 There are further new uranium projects
coming into production in the next few years and significant uranium exploration is
concentrated in northern Saskatchewan, but there are also prospects in Labrador and the
Northwest Territories.
19
Supply of Uranium. World Nuclear Association. http://www.world-nuclear.org/info/inf75.html
4.2
Environmental Implications
4.2.1
GHG Emissions
Generation of steam and electricity with nuclear technology for the oil sands
would produce significantly less CO2 emissions than a natural gas-fired facility. Nuclear
power plants do not produce emissions when they are generating electricity, but certain
processes used to create and fuels the plants do. These include emissions associated with
construction of the plant, mining and processing of the uranium to fuel the plant, routine
operation of the plant, the disposal of used fuel and other waste by-products, and the
decommissioning of the plant.20
The most significant contributors to GHG emissions throughout the entire lifecycle of steam and electricity generation from nuclear technology are the processes
involved with the mining and fabrication of the uranium. The Pembina Institute
estimates total GHG emissions from uranium mining and refining activities in Canada to
be between 240,000 and 366,000 tonnes of CO2 per year.21
In terms of electricity production, the emissions produced from nuclear
technology throughout the entire life-cycle of the process (including uranium mining and
refining activities), including CO2 emissions, is significantly less than most other
electricity production technologies. (See Table 4.1)
20
Nuclear Energy Institute. Life Cycle emissions analysis.
http://www.nei.org/index.asp?catnum=2&catid=260
21
The Pembina Institute. Nuclear Power in Canada: Key Environmental Impacts
http://pembina.org/pdf/publications/Nuclear_backgrounder.pdf
Table 4.1: Emissions Produced by 1 kWh of Electricity Based on Life-Cycle Analysis
Generation
option
Hydropower
Coal - modern
plant
Nuclear
Natural gas
(combined
cycle)
Biomass
forestry waste
combustion
Wind
Solar
photovoltaic
4.2.2
Greenhouse gas
emissions gram
equiv CO2/kWh
2-48
790-1182
SO2 emissions
milligram/kWh
NOx emissions
milligram/kWh
5-60
700-32321+
3-42
700-5273+
0
18-29
5
30-663+
2-59
389-511
3-50
4-15000+[1]
2-100
13+-1500
0
72-164
2
1-10+
15-101
12-140
701-1950
0
217-320
7-124
13-731
21-87
24-490
14-50
16-340
0
70
5-35
12-190
NMVOC
Particulate matter
milligram/kWh milligram/kWh
Water Implications
The complete process of producing steam and electricity for the oil sands using
nuclear technology can have significant impacts on water quality and conservation.
With respect to the uranium mining operations, the groundwater can be
contaminated with radio-nuclides, heavy metals and other contaminants, particularly in
the large tailings management facilities required to store the tailings from the mining
operation. Uranium mining and milling facility surface water discharges have also
resulted in the contamination of the receiving environment with radio-nuclides and heavy
metals. In 2006, Environment Canada completed an ecological science assessment of
releases of radio-nuclides from nuclear facilities and concluded “that releases of uranium
and uranium compounds contained in the effluent from the uranium mines and mills are
entering the environment22 in quantities or concentrations that may have a harmful effect
on the environment and its biological diversity”.
22
Environment Canada Website. Existing substances Evaluation. 2006.
http://www.ec.gc.ca/substances/ese/eng/PSAP/final/radionuclides.cfm
Nuclear power is also a major consumer of water. Uranium mining operations
involve extensive dewatering (groundwater), in the range of 16-17 billion litres per year,
which may have implications on the surrounding groundwater and surface water storage
and flows. The generating facilities also require large amounts of cooling water. Two
nuclear facilities in Ontario are estimated to use approximately 8.9 trillion litres of water
for cooling purposes per year.23
4.2.3
Waste Management
Waste management is the largest environmental challenge for the nuclear
industry. Part of the challenge is the management of the public’s perception of
radioactive waste and how it is managed.
All parts of the nuclear fuel cycle produce some level of radioactive waste. There
are several different types of radioactive wastes24;
Mine Tailings - Traditional uranium mining generates fine, sandy tailings, which contain
virtually all of the naturally occurring radioactive elements found in uranium ore. An
estimated 575,000 tonnes of tailings per year can be attributed to uranium production.
Uranium tailings are acidic and potentially acid generating and contain a range of lonlived radio-nuclides, heavy metals and other contaminants.
Low-Level Wastes (LLW) – Low-level wastes contain very small amounts of short-lived
radioactivity. It does not require shielding during handling and transport and is suitable
for shallow land burial. Approximately 6,000 cubic metres of lower level radioactive
wastes are generated each year in Ontario as a result of nuclear power plant operations,
maintenance and refurbishment.
23
The Pembina Institute. Nuclear Power in Canada: Key Environmental Impacts
http://pembina.org/pdf/publications/Nuclear_backgrounder.pdf
24
World Nuclear Association. Waste Management in the Nuclear Cycle. http://www.worldnuclear.org/info/inf04.html
Intermediate-Level Waste (ILW) – Intermediate-level waste contains higher amounts of
radioactivity and requires shielding. It typically comprises resins, chemical sludges and
metal fuel cladding, as well as contaminated materials from reactor decommissioning
activities.
High-Level Wastes (HLW) – High-level wastes arise from the use of uranium fuel in a
nuclear reactor. It contains the fission and transuric elements generated in the reactor
core. It is highly radioactive and hot, so it requires cooling and shielding. Used fuel
from a reactor gives rise to HLW, which may be either the used fuel itself in fuel rods or
the principle waste arising from reprocessing of the fuel. Both need to be isolated,
handled and stored safely for very long-term periods. Approximately 85,000 waste fuel
bundles are generated by Canadian nuclear reactors each year.25
High-level wastes are stable in a water environment, so interim storage is a fairly
straight-forward process. Used fuel from each reactor is stored on-site in deep water
pools used for cooling and shielding. Once a few years have passed, the used fuel may be
moved to above-ground dry storage in concrete canisters, with passive cooling provided
by air flow.26 Long-term storage of high-level radioactive waste is more of a challenge
and Canada has put significant research and development into long-term storage
technology. Deep Geological Disposal (DGD) is the most preferred option in the
international nuclear industry and the focus of most research and development in Canada.
25
The Pembina Institute. Nuclear Power in Canada: Key Environmental Impacts
http://pembina.org/pdf/publications/Nuclear_backgrounder.pdf
26
Canadian Nuclear FAQ. http://www.nuclearfaq.ca/cnf_sectionE.htm
The government of Canada is responsible for ensuring the long-term management
and disposal of radioactive waste is carried out in a safe, cost-effective and integrated
manner. Canada’s approach to radioactive waste management is that the producers and
owners of radioactive waste are responsible for the funding, organization, management
and operation of disposal and other facilities required for their wastes.
5
Regulation of Nuclear Technology
The Canadian Nuclear Safety Commission (CNSC) is the independent federal
nuclear regulator in Canada under Natural Resources Canada. It was established under
the Nuclear Safety and Control Act (NSCA), which has been in effect since May-2000.
The CNSC was formerly known as the Atomic Energy Control Board (AECB), under the
Atomic Energy Control Act of 1946.27
The CNSC regulations apply to power and research reactors, nuclear research
facilities, uranium mines and mills, uranium refining and conversion facilities, nuclear
fuel fabrication facilities, heavy water production plants, radioisotope production and
processing facilities, particle accelerators, radioactive waste management facilities,
packaging and transportation of radioactive substances, and any handling and storage of
radioactive substances.
Licenses are granted by the CNSC for all aspects of operation involving the above
facilities and activities. Licensees are required to prove to the CNSC that their facility or
activity is acceptably safe, under the requirements of the NSCA, before a license is
granted or renewed. The approach to safety assumes that nothing is 100% risk-free, but
27
Canadian Nuclear Safety Commission. http://www.cnsc-ccsn.gc.ca/eng/
that risk can be minimized through multiple layers of verifiable protection. This approach
includes external risks from both natural and man-made causes. For example, the CNSC
specifies the levels and type of security that are required at nuclear facilities.
In Canada nuclear power plants are defined as "Class I" nuclear facilities under the
NSCA, and require CNSC licenses prior to each of the five phases of a nuclear plant's
lifecycle: site preparation, plant construction, plant operation, site decommissioning, and
site abandonment. The process followed at each of these licensing steps includes a public
hearing with opportunity for public input. 28
In addition, the licensing process for a nuclear power plant in Canada proceeds
only after approval is granted through the federal Environmental Assessment (EA)
process under the Canadian Environmental Assessment Act (CEAA), involving the
convening of an EA Panel and further public hearings. The EA process identifies whether
a specific project is likely to cause significant environmental effects, determines whether
potentially significant adverse effects are identified and mitigates to the extent possible.
28
Canadian Nuclear FAQ. http://www.nuclearfaq.ca/
6
Conclusion
The use of natural-gas fired facilities for steam, electricity and hydrogen
production to support oil sands development in Alberta is not sustainable given the high
expected growth of production from the oil sands. The forecasted demand of natural gas
is expected to exceed supply in the long-term and the GHG emissions associated with
natural gas operations are not aligned with Canada’s commitment to the Kyoto Protocol.
Canada’s CANDU nuclear technology is proven around the world and could
provide a source of steam, electricity and hydrogen for future SAGD operations in
Alberta with significantly less GHG emissions than natural gas fuelled operations.
SAGD is a developing industry and the opportunity for incorporating nuclear technology
into the design of the SAGD process is available today.
The uranium supply to support nuclear technology development and operations in
Alberta is readily available in Saskatchewan, which has the third largest proven reserves
in the world. However, long-term supply and distribution of uranium would need to be
considered because uranium reserves may still be limited relative to the forecasted longterm production of oil from the oil sands. If uranium demand increased significantly in
order to support oil sands development in Alberta, one option to consider may be to
export less than the current 80% of total uranium mined being exported from Canada
today.
The environmental impacts associated with nuclear technology development are
significant. The environmental implications of uranium mining operations and the longterm storage of radioactive wastes are the two most significant challenges to the nuclear
industry.
Nuclear technology is fairly well regulated in Canada, although the process of
introducing nuclear technology to the oil sands in Alberta would very likely take at least
several years in terms of the application process.
The potential advantages of using nuclear technology to support oil sands
development are significant. The federal and provincial governments (Alberta and
Saskatchewan) should work with both the oil sands industry and the nuclear industry
(including uranium mining) to advance the research and development in order to
completely understand the environmental and societal impacts of nuclear technology in
Alberta.
Cover Page Pictures
http://www.bevex.ch/bilder/bevex-nuclear-power-plant.jpg
http://www.woodbuffalo.ab.ca/visitors/attractions/oil_sands.asp
Tables and Figures
Table 2.0
Alberta Chamber of Resources. Oil Sands Technology Roadmap. 2004.
http://www.acr-alberta.com/ostr.htm
Table 3.1
Potential for Nuclear Energy in Alberta’s Oil Sands. 2003. Robert
Dunbar.
http://www.strategywest.com/downloads/choa20031118.pdf
Table 4.1
Nuclear Energy Institute. Life Cycle emissions analysis.
http://www.nei.org/index.asp?catnum=2&catid=260
Figure 2.0
Alberta Chamber of Resources. Oil Sands Technology Roadmap. 2004.
http://www.acr-alberta.com/ostr.htm
Figure 3.1
Wikipedia Commons.
http://commons.wikimedia.org
Figure 3.2
Potential for Nuclear Energy in Alberta’s Oil Sands. 2003. Robert
Dunbar.
http://www.strategywest.com/downloads/choa20031118.pdf