The Nuclear Energy Option in Alberta
submitted by
Alberta Research Council and Idaho National Laboratory
to the
Government of Alberta Nuclear Expert Panel
on
October 1, 2008
The Alberta Research Council Inc. (―ARC‖) and Idaho National Laboratory (―INL‖) submit the following paper in confidence to the Government of Alberta Nuclear Expert Panel (―Expert Panel‖). This paper was prepared as an account of work conducted at the ARC and INL. All reasonable efforts were made to ensure that the work conforms to accepted scientific, engineering, and environmental practices, but ARC and INL make no other representation and give no other warranty with respect to the reliability, accuracy, validity, or fitness of the information, analysis, and conclusions contained in this paper. Any and all implied or statutory warranties of merchantability or fitness for any purpose are expressly excluded. Any use or interpretation of the information, analysis, or conclusions contained in this paper is at the user’s risk. Reference herein to any specified commercial product, process, or service by trade-name, trademark, manufacturer, or otherwise does not constitute or imply an endorsement or recommendation by ARC or INL.
EXECUTIVE SUMMARY
A range of new generation options is being considered by Albertans to meet future power demand caused by rapid economic and population growth. One option is the construction of one or more nuclear power plants that produce no carbon dioxide (CO2) and require no hydrocarbon-based fuel. Such an installation would be the first in western Canada. Although there are a number of nuclear plants successfully operating in eastern Canada, Alberta’s citizens and government have had little experience with this technology. Albertans need a better understanding of the safety of nuclear power and the long-term disposition of the radioactive waste products associated with nuclear fuels, among other topics.
This background paper was commissioned by the Government of Alberta nuclear expert panel to provide an overview of the scientific facts and issues concerning nuclear power plants. It introduces the technical, economic, environmental, and social issues of which Albertans need to be aware. This paper does not provide either technical or policy recommendations to address those issues, nor does it cover the use of nuclear technology for making process heat or for co-generating both heat and power, which are possible applications in the oil sands region.
A nuclear power plant would only be built in Alberta if the project owner believes there is a demand for the electricity produced. The power demand is independent of the production technology. Hence, the decision is not just whether to build a nuclear plant, but also between satisfying the power demand by building a nuclear plant or by building equivalently sized power generation facilities based on some other technology. The ability to import power from outside Alberta is limited. Because of the large size of nuclear plants, the most comparable alternative is a coal-fired power plant. As a standard example to illustrate the inputs or outputs of a nuclear reactor system, this paper uses data for a single 800-MWe unit, although some power plants consist of multiple independent units at one site. While a nuclear power plant attracts attention because of the nature of its energy source, many of the systems and local impacts are similar to those of an equally large fossil-fired power plant. Although these plants generate heat in different ways, the way that that heat is used to make steam and then electricity is the same. Once it enters the electrical grid, the electricity from both kinds of plant is indistinguishable.
This paper describes the current electricity market and that projected by 2024. It also describes the supply and demand by energy source and the distribution of generation, including a regional evaluation of the transmission system. The current load is characterized by strong growth rate, substantial demand from the industrial and the commercial sectors, and a statistical relationship to gross domestic product (GDP) or population growth. The current generation capacity is characterized by a prevalence of coal-fired and natural gas-fired plants, a high degree of geographic concentration, and an increasing market concentration. Rapidly increasing demand is exerting pressure on the generation system. The 2024 projections indicate substantial demand increases over current levels for both generation and load. Of Alberta’s generating capacity, 88% is fossil-fuelled; 94% of the actual electricity generation in 2007 was from fossil fuel. The generation system is already operating at or near its safe operating limits more often and for longer durations. The transmission system requires upgrading and new lines. Peak demand projections are expected to increase 21%–78% over current levels by 2024, or 1.3%–3.2% per year. Oil sands will contribute significantly to the increased energy demand in Alberta. A dedicated and reliable source of electricity is important to oil sands operation, but this is subject to growing concerns surrounding greenhouse gas (GHG) emissions.
The Nuclear Energy Option in Alberta, October 1, 2008 i Three categories of energy technology (fossil fuel, renewable, and nuclear energy) might be used to meet Alberta’s electricity needs. The technology comparison is based upon underlying parameters such as costs, environmental footprint, sustainability, reliability, and capacity. Coal-based electricity production is well established in Alberta. Supercritical pulverized coal technology is currently the technology of choice due to its efficiency. Coal-fired power plants are large scale (400 MW or greater) and are better-suited for base load power. Natural gas-fired power is also common in Alberta. However, uncertainty surrounding natural gas availability and price have an impact on its long term potential, and make it better suited for peak power production. Increasing concern surrounding GHG raises the future importance of carbon capture technology. Three main options are post-combustion capture, oxyfuel combustion, and pre-combustion capture in an integrated gasification combined cycle. All three result in a significant increase in the power production cost. Different alternatives for renewable energy are present in Alberta. Their inherent intermittency, availability, capacity, and cost currently limit the extent of their energy contribution to, and integration in, the Alberta grid system. Four basic types of commercial nuclear power plants are identified as having potential applicability to the province. These have different characteristics such as technology availability, reactor size, requirements for enrichment, heavy-water production, applicability to heat applications, and reactor efficiency. All of these reactors could be available within the next 20 years. The cost of power from a large scale nuclear power plant is similar to that from a coal power plant equipped with CO2 capture.
This paper covers the issues surrounding the integration of nuclear power plants in Alberta. The infrastructure needed to establish and operate a nuclear power plant is extensive and will require significant planning. A large portion of the required physical resources can be obtained in Canada but certain components will have to be imported. The needs extend beyond the nuclear reactor itself to waste fuel storage as well as ancillary infrastructure. Additional infrastructure requirements to distribute these resources to the chosen site should also be considered. The deployment of a nuclear power plant is subject to a number of risks involving the technology itself, licensing, cost of construction, financing, construction time, supply infrastructure, cost of fuel, waste disposal, and risks of accident or terrorism. Another major risk to consider is the current uncertainty surrounding future policies and penalties involving GHG emissions since these will significantly affect the economic comparison of nuclear and fossil fuel-based electricity. The integration of any new large-scale power plant may require substantial reinforcement of the transmission system, a consideration that poses a major challenge especially if there is stakeholder opposition. However, this issue is a function of the size of the new generator and is not specific to nuclear units. As a new generator, the nuclear plant operator will have to pay some costs associated with integration into the transmission grid as well as a potentially refundable system contribution fee.
The operational and decommissioning phases of a nuclear plant life cycle primarily affect the reliability and the cost of power production. All owners would insist on reliable operation because nuclear power plants are relatively large and costly. The more capital intensive the plant, the more economically harmful will be its unnecessary shutdown. Nuclear plant operation worldwide has improved over the past several decades, in part because of increased sharing of information within the industry. Regulators routinely make it clear that the primary responsibility for safety and operation falls on the plant owner. It is appropriate to inquire into the relevant nuclear industrial experience of any entity undertaking the construction, operation, and eventual decommissioning of nuclear power plants. It is also appropriate to inquire about the support network a new plant would have. If the plant were not a CANDU, there would be foreign expertise, but no significant existing Canadian nuclear industrial infrastructure. Regulatory control of nuclear plant siting, construction, and operation is a federal responsibility delegated to the Canadian Nuclear Safety Commission (CNSC). Regulatory control of nuclear plant decommissioning is a federal responsibility, also delegated to the CNSC.
The Nuclear Energy Option in Alberta, October 1, 2008 ii The supply and eventual disposition of nuclear fuel is a public concern. The commercial availability of fuels for potential new reactor types remains unknown unless they are designed to use currently available fuels. The plant operator would have to establish working relationships with the Canadian Nuclear Waste Organization for high-level and used nuclear fuel, as well as with the Low- Level Radioactive Waste Management Office. Nuclear waste disposal is the responsibility of the owner of the nuclear power plant, who must pay all disposal costs. As with decommissioning, Canada requires trust funds established during reactor operation for eventual disposal costs. Low-level waste from a nuclear reactor in Alberta would have to be shipped to one of the 11 current facilities in Manitoba, New Brunswick, Quebec, or Ontario, or sent to a new facility to be built in Alberta. Used nuclear fuel from a nuclear reactor in Alberta would be stored at the reactor site until Canada identifies a specific permanent disposal option or centralized interim storage. The Canadian used nuclear fuel program has focused on used CANDU reactor fuel and small amounts of fuel from test and university reactors. Use of any new type of fuel in Alberta would presumably lead to some alteration of the Canadian program. Control of transportation of nuclear materials is a federal responsibility given to the CNSC. Building a nuclear power plant in Alberta does not require the construction of other nuclear infrastructure in the province, even if the plant is not of CANDU technology.
Nuclear plant supervision and control occurs at three levels: national, international, and provincial. The industry and its regulators recognize that the safety of nuclear plants is a major public concern, and in the last three decades have moved toward greater interactions among all levels of government (including international agreements), better analysis of and response to safety issues by designers, and much greater attention to preventing the use of nuclear power systems or products for weapons production. There are a number of regulatory and technical approaches to addressing nuclear safety and security of nuclear power plants. If a nuclear power plant is built in Alberta, the province would establish nuclear power relationships with the Canadian Environmental Assessment Agency, and with other provinces with nuclear technology or waste. Regulation of nuclear plant safety is a federal responsibility given to the CNSC. Past nuclear technology failures have been well publicized and well analyzed by the industry; reactor designs and operation have improved and information is now shared more quickly and more widely. Safety and security have become increasingly internationalized without loss of national sovereignty. The international market is inducing reactor vendors to seek regulatory approval in multiple countries as a competitive advantage. The International Atomic Energy Agency has a set of standards and guides that continue to grow and improve. Canada participates in a new international regulatory initiative for regulators to collaborate in analyzing new reactor designs. Non-proliferation safeguards and physical security are recognized concerns. Canada’s obligations would grant the International Atomic Energy Agency access to nuclear facilities in Alberta as is the case in other provinces.
The paper covers several aspects of nuclear power plant water usage. The primary use of water in a nuclear reactor is for cooling systems used to reject low temperature heat to the environment through transfer to a water body or the atmosphere in amounts and manner similar to a like-sized fossil-fired power plant. The largest consumptive uses of water in Alberta are agricultural, thermal power (fossil-fired power plants), municipal, industrial, and enhanced oil recovery (oilfield injection). The majority of allocation is for surface water with only 3% coming from groundwater. The south- eastern portion of the province is closed to new water allocation applications and is an area where water shortages are likely. It is likely that water supplies will decline in the province over the next 25 years while water demand increases due to population growth, expansion of oil sands-related activities, and larger extractions by irrigators to their maximum allocations. In Alberta, water has been traditionally allocated on the first-in-time, first-in-right principle for both surface and ground water by Alberta Environment. The requirements of a potential nuclear power water diversion
The Nuclear Energy Option in Alberta, October 1, 2008 iii application would have to be assessed in the context of existing licenses, their status, longevity, and potential for reallocation or transfer.
Nuclear power plants do not emit regulated pollutants or GHG during operation. However, emissions from a nuclear power plant can occur during construction, maintenance, and refuelling. They can also occur during the preparation of the nuclear fuel from ore, and during plant maintenance or demolition. The lifetime CO2 equivalent emissions of a nuclear power plant, calculated by a life cycle analysis, are comparable to those of wind, solar, or hydro power, and are about a factor of 100 lower than for coal-, gas-, or oil-fired power plants. Tritium (a radioactive isotope of hydrogen) may be produced in heavy-water reactors, but its build-up can be controlled by a tritium removal facility. The tritium releases from CANDU plants are well below regulatory limits.
A nuclear plant, with its long construction period, capital-intensity, and need for skilled labour during both construction and operation, would have significant socioeconomic impacts on the province and the rural region in which it was located. It would also likely create some public concern and controversy since Alberta has never had a nuclear power plant. Based on recent Canadian and U.S. studies, about 2300 new full-time workers would be required onsite during construction, with an additional 1000 jobs created indirectly in each of the manufacturing and retail sectors. Skilled labour shortages may occur, particularly of ironworkers, boilermakers, and pipefitters. Plant operation could create about 1000 new permanent on-site jobs and about 300 new permanent jobs in Alberta’s manufacturing sector. GDP could rise on the order of $400 million annually; combined federal, provincial, and local taxes could increase by $100–200 million per year. Locating in a rural area would raise issues similar to those seen in Fort McMurray arising from oil sands development. Of particular concern is the ability of a rural community to expand housing, infrastructure, and public sector labour to accommodate a rapid rise in population during construction. The provincial government will likely have to deal with public concerns about safety (both accidents and long term storage of radioactive wastes), decommissioning, land reclamation, water use, and reliability (given Ontario’s problems with its nuclear fleet).
In conclusion, the paper reviews the regulatory framework that applies to the construction and operation of nuclear power plants as well as the infrastructure for interconnecting nuclear power. Federal jurisdiction, delegated to the CNSC, covers regulations specific to nuclear projects. Regulations related to the siting and interconnection of new power and transmission are subject to provincial legislation. The combination of new regulations since 2000 and the fact that no nuclear power plants have been built in Canada in the last 25 years make it difficult to assess the actual performance of the regulatory approval process for new facilities.
The Nuclear Energy Option in Alberta, October 1, 2008 iv
TABLE OF CONTENTS
EXECUTIVE SUMMARY ...... i TABLE OF CONTENTS ...... v ACKNOWLEDGEMENT ...... viii CHAPTER 1: INTRODUCTION ...... 1 CHAPTER 2: ELECTRICITY SUPPLY AND DEMAND IN ALBERTA ...... 3 Summary ...... 3 Overview of Current State of the System ...... 3 Projected State of the System ...... 7 Discussion of Forecast Scenarios ...... 11 References ...... 12 CHAPTER 3: FUTURE ENERGY TECHNOLOGIES ...... 13 Summary ...... 13 Fossil Fuel-based Energy ...... 13 Renewable Energy ...... 16 Nuclear Energy ...... 19 Energy Efficiency, Conservation and Management ...... 22 Meeting Alberta’s Energy Needs ...... 22 References ...... 23 CHAPTER 4: INTEGRATION OF NUCLEAR POWER PLANTS INTO ALBERTA’S ELECTRICITY GENERATION MIX ...... 25 Summary ...... 25 Infrastructure and Resources Required for a Nuclear Power Plant ...... 25 Nuclear Power Plant Deployment and Power Transmission in Alberta...... 28 References ...... 33 CHAPTER 5: OPERATIONS, MAINTENANCE, AND DECOMMISSIONING ...... 35 Summary ...... 35 History ...... 35 Reactor Operation and Maintenance ...... 37 Reactor Lifetime ...... 38 As Low As Reasonably Achievable (ALARA) ...... 40 Reactor Decommissioning ...... 41 References ...... 44 CHAPTER 6: NUCLEAR FUEL HANDLING AND DISPOSITION ...... 46 Summary ...... 46 Nuclear Fuel Cycle ...... 46
The Nuclear Energy Option in Alberta, October 1, 2008 v Candidate Fuels ...... 51 Fuel Handing and Operational Considerations ...... 52 Potential for Recycling Used Fuel ...... 53 Low-level Waste Management ...... 54 High-level Waste Management ...... 54 References ...... 56 CHAPTER 7: SAFETY AND SECURITY ...... 57 Summary ...... 57 Supervision and Control Levels ...... 57 Reactor Safety Approaches ...... 58 Lessons Learned from Past Reactor Events ...... 67 Physical Security ...... 68 Other Risks ...... 68 References ...... 69 CHAPTER 8: WATER USAGE AND SOURCING...... 71 Summary ...... 71 Water Used in Reactor Operation ...... 72 Provincial Water Supplies in Alberta ...... 73 Projected or Possible Changes to Water Supply ...... 77 Water Permit Application Process ...... 79 References ...... 83 CHAPTER 9: ENVIRONMENTAL AND OTHER IMPACTS ...... 86 Summary ...... 86 Environmental factors ...... 87 Socioeconomic Factors ...... 89 References ...... 99 CHAPTER 10: REGULATORY PROCESS ...... 102 Summary ...... 102 Regulatory Process and Review of Recent Changes ...... 102 Sequence of Regulatory Requirements ...... 104 Evaluation of the Regulatory Process ...... 108 References ...... 109 APPENDIX A: SURVEY OF NUCLEAR REACTOR OPTIONS ...... 110 Summary ...... 110 Overview ...... 110 Heavy-water Reactors (Table A-1) ...... 112 Light-water Reactors (Table A-2) ...... 114
The Nuclear Energy Option in Alberta, October 1, 2008 vi Helium-cooled High-temperature Reactors (Table A-3) ...... 116 Small–medium Reactors (Tables A-4a and A-4b) ...... 118 References ...... 123 APPENDIX B: SYNOPSYS OF THE ACCIDENT AT CHERNOBYL-4 ...... 126 References ...... 127 APPENDIX C: OVERVIEW OF THE ALBERTA RESEARCH COUNCIL AND IDAHO NATIONAL LABORATORY ...... 128 Alberta Research Council...... 128 Idaho National Laboratory ...... 129 APPENDIX D: ACRONYMS AND ABBREVIATIONS ...... 130
The Nuclear Energy Option in Alberta, October 1, 2008 vii ACKNOWLEDGEMENT
As co-project managers for the preparation of The Nuclear Option in Alberta, Quinn Goretzky (Alberta Research Council) and Robert Cherry (Idaho National Laboratory) acknowledge and appreciate the participation of the following people, without whom this paper would not have been possible:
Alec Blyth (ARC) James Brydie (ARC) Allan Chambers (ARC) Marius Cutlac (ARC) Jon Paul Jones (ARC) Guillermo Ordorica-Garcia (ARC) Stephanie Trottier (ARC) Marian Weber (ARC) Steve Piet (INL) David Shropshire (INL) Sid Carlson (consultant) Timothy Green (consultant) Wayne Taylor (consultant)
The Nuclear Energy Option in Alberta, October 1, 2008 viii CHAPTER 1: INTRODUCTION
The rapid growth of Alberta’s economy and population underscores the need for both new private sector power generation and the corresponding expansion of electricity transmission and distribution. Increased oil sands production in northern Alberta has geographically shifted both future demand and, because of the availability of by-product fuel gases, power production. The prospects of declining conventional natural gas supplies in the region and the imposition of penalties or limits on large carbon dioxide emitters in Canada complicate the planning for any new power plants.
A range of new generation options is being considered to meet future power demand in Alberta. One is the construction of nuclear power plant(s) that produce no carbon dioxide emissions and require no hydrocarbon-based fuel. Such an installation would be the first nuclear power plant in western Canada. Although there are a number of nuclear plants successfully operating in eastern Canada, Alberta’s citizens and government have had little experience with this technology. The public needs a better understanding of the safety of nuclear power and the long-term disposition of the radioactive waste products associated with nuclear fuels, among other topics.
To examine these and other issues, an expert panel chaired by Dr. Harvie Andre was appointed by the Government of Alberta with the charter to prepare a report that will be a basis for future public discussion about nuclear power in the province. This background paper was commissioned by the expert panel to support writing that report by providing an overview of the scientific facts and issues concerning nuclear power plants. It introduces the technical, economic, environmental, and social issues of which Albertans need to be aware for their dialogue. This paper does not provide either technical or policy recommendations to address those issues, nor does it cover the use of nuclear technology for making process heat or for co-generating both heat and power, which are possible applications in the oil sands region. Its authors are relevant experts from the Alberta Research Council and the Idaho National Laboratory, a U.S. Department of Energy national laboratory whose primary mission is the development and assessment of nuclear power systems. Appendix C includes more information on these two organizations.
This paper begins with overviews of the current electricity supply and demand situation in Alberta, the alternatives for future production, and the way that nuclear systems might integrate with the existing electric grid. Following that are discussions of several topics of general public interest concerning nuclear plants and their associated facilities: operations and maintenance, handling and disposal of nuclear fuel, and safety and security. The discussion then turns to Alberta-specific concerns of water usage and sourcing; environmental, socioeconomic, and other impacts; and finally a review of the Canadian and Albertan regulatory approval process for these plants. Appendix A provides additional details on the types of nuclear power reactors commercially available now and in the future. Because this paper attempts only to survey these issues, these topics will require more in- depth analysis as part of further consideration of nuclear power plant proposals in Alberta.
In places, the discussion provides data for a single 800-MWe unit (some power plants consist of multiple independent units at one site) as a standard example to illustrate the inputs or outputs of a nuclear reactor system. The size and number of nuclear units at any site is uncertain and is up to the project developer; there is no intention of suggesting what might work best for a generator or the grid operator. This arbitrary 800 MWe is about the capacity of a power plant using a current-generation CANDU, a smaller-than-typical current light-water reactor, or two or three next-generation high- temperature gas reactors. This can be compared to the 450 MWe capacity of the largest (coal-fired) plant currently on the Alberta grid, and to the two 600-MWe gas-fired plants heading the list of
The Nuclear Energy Option in Alberta, October 1, 2008 1 proposed new or expanded plants. In general, a larger unit can have better financial performance because of economies of scale, but it is harder for the system operator to provide coverage of that unit’s output in the event that it goes off-line unexpectedly.
A nuclear power plant would only be built in Alberta if the project owner believes there is a demand for the electricity produced. The power demand is independent of the production technology. Hence, the decision is not just whether to build a nuclear plant, but also between satisfying the power demand by building a nuclear plant or by building equivalently sized power generation facilities based on some other technology. The ability to import power from outside Alberta is limited. Because of the large size of nuclear plants, the most comparable alternative is a coal-fired power plant. While a nuclear power plant attracts attention because of the nature of the energy source, many of the systems and local impacts are similar to those of an equally large fossil-fired power plant. Although these plants generate heat in different ways, the way that that heat is used to make steam and then electricity is the same. Once it enters the electrical grid, the electricity from each kind of plant is indistinguishable. Table 1-1 provides details of the local effects of each type of plant. Owners’ concerns such as construction delays or capital cost are not considered here.
Table 1-1. Local impacts of nuclear and fossil-fired power plants Factor Comparison Roughly similar land requirement. Typical facility footprint can accommodate Facility size multiple nuclear reactors with shared infrastructure. Coal and nuclear plants are used for continuous base load power production. Operating mode Natural gas is used for base load or peaking power. New plants are projected to have similar costs under the current regulatory Cost of electricity environment. Nuclear power cost is less sensitive to fuel price fluctuations and would not be affected by the imposition of CO2 emission penalties. No CO2, SOx, NOx, mercury, or haze from operating nuclear plants. Moderate CO2 Air emissions from natural gas-fired plants. High levels of CO2 and other regulated pollutants from coal plants. Physically small volumes of used nuclear fuel are stored at the power plant for several years before being sent to a long term depository elsewhere. Coal ash is Solid emissions shipped out by train. Gypsum from (coal) flue gas desulfurization is shipped out or stored in piles at the power plant. All are similar for the same electrical production capacity. All need to reduce rates or Water usage shut down when water availability is limited as in a drought. Nuclear plants require more construction personnel and for a longer duration. Employment Operations, maintenance, and administration are similar. Nuclear plants require radiation-trained workers and more security staff. Coal plants require near-daily trainload deliveries of fuel, natural gas-fired plants Traffic and require pipeline connections, and nuclear plants receive fuel at intervals of 1–2 transportation years. Nuclear plants will require eventual (decade timescale) transport of used fuel from the power plant site.
For the best representation of the systems that might be built, the alternatives should include the additional systems now under development to address perceived needs in each major power generation option. For nuclear power, this would include an off-site facility for eventual long-term disposal of high-level radioactive waste, or at least a feasible plan for such a facility. Future fossil- fuelled systems, either coal or natural gas, will likely require capture and sequestration of the CO2 produced by combustion. Renewable energy technologies other than hydro and geothermal, including solar and wind in particular, require some sort of large-scale energy storage system so they can provide base load power despite their intermittency. Alternatively, the analysis of the renewable option should include the costs of providing both backup generation capacity and spinning reserves of non-intermittent power generation. The evaluation of all these additional technologies and a full comparison of nuclear power generation to the other alternatives are outside the scope of this paper.
The Nuclear Energy Option in Alberta, October 1, 2008 2 CHAPTER 2: ELECTRICITY SUPPLY AND DEMAND IN ALBERTA
Summary
This chapter presents an overview of the current electricity market and that projected by 2024,1 as well as the supply and demand by energy source and the distribution of generation. The chapter also provides a regional evaluation of the transmission system, and briefly discusses the power demand from oil sands with its implications for nuclear power.
The key points in this chapter are summarized below:
The current load is characterized by strong growth rate, substantial demand from the industrial and the commercial sectors, and a statistical relationship to gross domestic product (GDP) or population growth. The current generation capacity is characterized by a prevalence of coal-fired and natural gas-fired plants, a high degree of geographic concentration, and an increasing market concentration. Rapidly increasing demand is exerting pressure on the generation system. The 2024 projections indicate substantial demand increases over current levels for both generation and load. Of Alberta’s generating capacity, 88% is fossil-fuelled; 94% of the electricity consumption in 2007 was generated by fossil fuel. Investment in new generation capacity is a private unregulated decision. Greenhouse gas (GHG) emissions could be an issue for current and new fossil-based generation. The generation system is already operating at or near its safe operating limits more often and for longer durations. The transmission system requires upgrading and new lines (AESO, 2008). Peak demand projections are expected to increase 21%–78% over current levels by 2024, or 1.3%–3.2% per year. Oil sands will contribute significantly to the increased energy demand in Alberta. A dedicated and reliable source of electricity is important to oil sands operation, but this is subject to growing concerns surrounding CO2 emissions.
Overview of Current State of the System
Market Structure
Alberta started restructuring its electricity market in 1996. It first created a wholesale market for electricity by removing regulatory barriers to entry by independent power producers, and eliminating regulatory requirements that new generation be approved on the basis of need. There has recently been a trend towards concentration in the wholesale market, but that concentration is still below its 2000 level (MSA, 2006). In 2001, Alberta moved to a competitive retail market by
1 This chapter is based predominantly on the Alberta Electricity System Operator’s transmission outlook through 2024 (AESO, 2005).
The Nuclear Energy Option in Alberta, October 1, 2008 3 providing regulated retail option customers (up to 250 MWh per year) with the option to purchase power through contracts. More than 20 companies are currently competing to sell power to the commercial and industrial users, defined as those who use more than 250 MWh per year.
The wholesale market is managed by the Alberta Electric System Operator (AESO) to facilitate fair, efficient, and open competition. The AESO receives electricity supply offers and demand bids from market participants, establishes an hourly pool price based on real-time supply and demand, and then manages the financial settlement of the spot market. Energy retailers purchase electricity through a combination of long-term contracts with generation companies and short-term purchases on the spot market. Investment in new generation capacity is a private unregulated decision with no guaranteed rate of return, and independent power producers will often require long-term financial contracts with buyers to obtain financing. However, potential regulatory delays may make it difficult for a nuclear plant to establish long-term contracts prior to construction.
Load
In 2006–2007, the peak demand for the Alberta internal load2 was 9661 MWe3 (AESO, 2007a). Between 2000 and 2007, the peak demand increased on average 3.7%, within the 0.8%–8% per year range (AESO, 2005; Energy, 2008). The distribution of demand by sector is shown in Figure 2-1 with industrial (55%) and commercial (25%) consumers representing the majority.
Agriculture 3% Residential 17%
Industrial 55%
Commercial 25%
Figure 2-1. Structure of electricity consumption by sector in 2007 (ERCB, 2008)
Industrial and commercial demands fluctuate with the provincial GDP. AESO (2007a) estimates that the relationship between industrial and commercial energy consumption and GDP is
2 The Alberta internal load is the total domestic consumption including behind-the-fence (industrial loads supplied by on-site generation) and the City of Medicine Hat load (own-generation), values that are excluded by the alternative measure, the Alberta Interconnected Electric System load. 3 Estimates for 2007–08 indicate a peak demand of 9710 MW (Alberta Energy, 2008).
The Nuclear Energy Option in Alberta, October 1, 2008 4 350–390 MWh per $million GDP. The residential sector consumes approximately 17% of the electricity. The AESO calculates an average annual energy requirement of 6.9 MWh per residential customer. The balance of 3% is consumed by the agricultural sector at a ratio of 500–900 MWh per $million agricultural GDP (AESO, 2007a).
Generation Capacity
Alberta’s power is generated by over 280 units with a combined capacity of about 12,143 MWe (ERCB, 2008). During 2000–2007, generation capacity expanded at an average annual rate of 3.4%, with extreme values being 9% in 2000–2001 and -4% in 2005–2006 (ERCB, 2008). The distribution of generation capacity by energy source has implications for GHG emissions, which are an issue for fossil-fuelled plants. Figure 2-2 shows that most of Alberta’s generation installed capacity is derived from coal (50%) or natural gas (38%) with the remainder from sources that do not generate net GHG emissions (ECRB, 2008). Note that in 2007, coal-fired power plants generated 62% of the province’s electricity, while natural gas accounted for 32% (ERCB, 2008).
Generation Installed Capacities, 2007
7,000
6,000
5,000
4,000
MW 3,000
2,000
1,000
- Coal-fired Natural gas-fired Hydro Wind Biomass and other
Figure 2-2. Generation installed capacities in 2007 (ERCB, 2008)
The distribution of generation capacity is concentrated in three geographic areas: Lake Wabamun/Edmonton (5900 MWe, mainly coal-fired), Fort McMurray (1100 MWe, mainly natural gas-fired), and southern Alberta (3000 MWe, mainly coal-fired).
Transmission System
The operation, access and planning of the transmission system is managed by the AESO, an organization independent of all other electricity market participants. The AESO operates mainly 240- kV AC lines for its transmission system. Generally, the 240-kV AC lines are oriented north-east to south, from Fort McMurray to Calgary via Edmonton, with branches to northwest Alberta (to Wesley Creek), to east-central Alberta (to Metiskow, east of Red Deer, and to Jenner, east of Calgary), and to southeast Alberta (to Lethbridge). Parallel circuits connect Fort McMurray to Edmonton, Edmonton to Calgary, and Cordel to Ware Junction (east-central Alberta). Several 138-kV AC lines are located
The Nuclear Energy Option in Alberta, October 1, 2008 5 in southern Alberta. Figure 2-3 is a diagram of the transmission system showing the location of major generation facilities.
Figure 2-3. Existing bulk system transmission (AESO, 2007c)
The Nuclear Energy Option in Alberta, October 1, 2008 6 Alberta has limited connections to other jurisdictions, with connections to British Columbia and Saskatchewan, both in the south of the province. The tie to British Columbia has a design capacity of 1200 MWe import to Alberta and 1000 MWe export to British Columbia (ERCB, 2008). In 2007 the maximum available transfer capability values were 675 MWe import and 735 MWe export (AESO, 2007b). The tie to Saskatchewan has a design capacity of 150 MWe both ways (ERCB, 2008). In 2007, the maximum available transfer capability was 153 MWe import and 60 MWe export (AESO, 2007b). These ties connect Alberta to export markets. Typically, Alberta exports energy during the evening and imports energy during the day. Since 2000, with the exception of the year 2001, Alberta was a net importer of electricity.
Projected State of the System
Load Forecast
Alberta’s load is growing at one of the fastest rates in North America (AESO, 2008). The AESO provides forecasts for demand by sector, and Table 2-1 provides a summary of recent AESO forecasts. The 2005 forecasts are ranked in terms of likelihood. For example, the AESO (2005) most- likely scenario for the year 2024 peak load considers a growth rate of 2.1% per year. Low and high growth scenarios are developed using peak demand growth rates of 1.3% and 2.8%, respectively. A more recent report (AESO, 2007a) revises the annual growth rate for the peak demand to 3.1%.4
Table 2-1. Peak demand forecast for 2024 (AESO projections) Estimated Annual Load Projected Peak Increase in Peak Reference Growth Rate (%) Demand (MW) Demand over 2007 level (%) 1.3 (low) 11,520 21 AESO, 2005 2.1 (most likely) 14,123 37 2.8 (high) 16,175 45 AESO, 2007 3.1 14,556 78
ERCB (2008) provides alternative load forecasts up to 2017 assuming an average growth rate of 4% per year in total energy demand for each of the industrial, commercial, and residential sectors.
The projected demands can be broken down by sector based on the relationship between GDP, population, and sector demand. AESO (2007a) bases its load forecast on a projected GDP growth rate of 3.4% per year until 2020. Expanding the 2020 AESO projection (AESO, 2007a) to 2024, the industrial consumption will grow by about 36,000 GWh, while the commercial consumption will grow by about 9000 GWh. This represents a 91% increase for the industrial sector and a 71% increase for the commercial sector over 2007 levels. For residential forecasts, Alberta’s population is assumed to increase at an average annual rate of 1.6% to 2020 (AESO, 2007a)5. This is the equivalent of an average addition of 25,000 residential customers per year, or about 3150 GWh more by 2024 (35% above the 2007 level).
4 AESO (2007) employs one scenario only. 5 This rate is similar to the population growth rates of 1.5% per year projected by Alberta Health and Wellness (Health, 2007).
The Nuclear Energy Option in Alberta, October 1, 2008 7 Generation Expansion Forecast
Alberta’s electricity generation capacity is continuously expanding. While supply is considered adequate in the near term, 3800 more MWe will be required by 2016 (AESO, 2007a). For 2024, a total additional installed generation capacity requirement of 4600–9500 MWe is projected.
The AESO (2005) provides two main generation scenarios: coal and southern generation (predominantly coal-fired plants located in southern part of the province), and cogeneration and northern generation (predominantly cogeneration plants located in the northern part of the province).6 The distribution of generation capacity by energy source may have implications for GHG emissions. Figure 2-4 shows the new capacities or upgrades forecast by generation capacity type for each new scenario.
Generation Scenarios for 2024: Additional Installed Capacities Coal-fired
6,000 Natural gas-fired Hydro 5,000 Wind Biomass and other 4,000
3,000 MW
2,000
1,000
- Coal and Cogen and Coal and Cogen and Coal and Cogen and Southern Gen. Northern Gen. Southern Gen. Northern Gen. Southern Gen. Northern Gen.
Low Load M ost Likely Load High Load
Figure 2-4. Generation scenarios for 2024 showing additional installed capacities by load scenario (AESO, 2005)
The coal and southern generation scenario has new or upgraded coal-fuelled plants at Bow City near Brooks, Wabamun, or Battle River sites as well as peaking units near Calgary. The cogeneration and northern generation scenario has new or upgraded cogeneration at Fort McMurray. Each scenario would produce additional generating capacity of 4600–9500 MWe, depending on the demand projection.7 Note that although the planned capacities for wind and hydro will have installed capacities of 2000 and 200 MWe, respectively, their net capacities are only 300 and 100 MWe, respectively. No information on the timing of these projects is included. Table 2-2 presents the generation location by region and scenario.
6 Cogeneration is defined as the simultaneous generation of electric power and thermal energy. 7 Coal additions fluctuate between 15%–53%, with those for natural gas between 13%–40%.
The Nuclear Energy Option in Alberta, October 1, 2008 8 Table 2-2. Generation location by region and scenario, as of 2024 (AESO, 2005) Generation Location North North West Edmonton Central and South by Region and East and North Calgary Scenario (MW) Central Low Load: Coal and Southern 4211 800 5435 2295 3419 Cogen and Northern 5011 800 4935 1995 3419 Most Likely Load: Coal and Southern 5959 725 5960 2520 4444 Cogen and Northern 7459 725 5960 2020 3444 High Load: Coal and Southern 7507 900 6535 3895 4519 Cogen and Northern 9807 900 7035 2095 3519
For comparison, ERCB (2008) presents a list of power plant additions until 2017 where preference is shown for natural gas-fuelled power plants. This is more in line with recent history; about 74% of incremental capacity was natural gas fired in the period 1998–2007. By 2017, plans call for an additional 4118 MWe of which 65% will be natural gas-fuelled, 21% wind-powered, and 12% coal-fired. In terms of timing, this means about 449 MWe will be added to the generation mix by 2008, 724 MWe in 2009, 675 MWe in 2010, and 2270 MWe in the 2011–2017 period.
In terms of size of new projects, 80% of the proposed capacity additions are larger than 100 MWe and 38% are larger than 300 MWe (Energy, 2008). Two capacity additions larger than 600 MWe are proposed for 2012 and 2015.
Transmission System Development
Transmission system development is required to link generation capacity to demand. Since both generation and demand are subject to market decisions, the transmission must be built in anticipation of their developments. One driver of the transmission development plan is the need to replace or upgrade some of the existing 240-kV lines and 240-kV substation equipment, which are reaching an advanced age. While power demand has doubled over the last 20 years, the transmission system has not seen major upgrades. In addition, the need to provide new links between the projected generation and load will require new transmission infrastructure.
The AESO summarizes transmission development to 2024 for a number of alternative scenarios. These scenarios attempt to capture possible generation capacities and load spatial distribution and levels. Some common elements of the transmission system development include the following (AESO, 2005):
Fort McMurray. Expansion of 240-kV lines, new 5000-kV lines (Dover–Wesley Creek then on to BC, and Dover–Cordel–Ware Junction–Langdon) Grand Prairie. 240-kV line (Wesley Creek–Grande Prairie–Little Smoky) Edmonton–Calgary corridor. A second 500-kV line or HVDC Lloydminster. 240-kV line (Bigstone–Lloydminster–Metiskow) Calgary. 240-kV line (Langdon–Calgary and Lochend–Sarcee) Lethbridge–Medicine Hat–Empress. 240-kV line (Lethbridge–Medicine Hat– Empress), replacement of old 138-kV with 240 kV line (Bow City–Medicine Hat) Southern Alberta. 500-kV circuit Pincher Creek–Langdon, expansion of 138-kV and 240-kV from wind farms; upgrade of 138-kV to 240-kV from Pincher Creek to BC
The Nuclear Energy Option in Alberta, October 1, 2008 9
Power Demands from Oil Sands and Implications for Nuclear Power
A large contributor to the increased energy demand in Alberta will be the growth of the oil sands operations. The extent of this growth depends on the cumulative production, including mined and/or thermally-extracted bitumen, which can be upgraded to synthetic crude oil (SCO). The energy required in each case depends on the extraction and upgrading processes used. As a reference, the estimated unitary power demands of mined SCO, thermal SCO, and thermal bitumen are 21–27, 7– 15, and 3–5 kWh/barrel, respectively (Ordorica, 2007).
The power demands of oil sands operations (Figure 2-5) are anticipated to more than double during 2003–2012 and reach 3200 MW by 2030. These increases are closely tied to the dramatic growth in oil sands production forecast for this period, climbing to 5 million barrels per day (ACR, 2004). Figure 2-5 shows that the total power demands for oil sands operations in 2012 will be the equivalent to two 800-MWe nuclear power plants.
Mined SCO Thermal SCO Bitumen Oil Sands Production 5,000 5,000,000 4,500 4,000 4,000,000 3,500 3,000 3,000,000 2,500 2,000 2,000,000 1,500 1,000 1,000,000
Electricity demands(MWe) Electricity 500 - - Sands(barrels/d) Production Oil 2003 2012 2030
Figure 2-5. Electricity demands of oil sands operations 2003–2030 (Ordorica, 2007)
Due to their dependence on natural gas-based energy, oil sands operations have been impacted by the rising cost of this fossil fuel, and will likely continue to be so in the future. In addition, there have been growing concerns surrounding climate change and CO2 emission restrictions that may lead to the increased attractiveness of alternate sources of energy such as nuclear.
A recent study (Bersak, 2007) explored the suitability of various nuclear reactor technologies in supplying dedicated energy for oil sands operations. The analysis suggests that a commercially available nuclear power plant with a net output of 700 MWe could supply enough power to produce approximately 600,000 barrels of mined bitumen per day. A next-generation 1150-MWe reactor has the potential to sustain approximately 1.1 million barrels of mined bitumen per day while an 800 MWth nuclear power plant can produce enough power to support 250,000 barrels of mined bitumen per day. Thermal bitumen extraction has significantly lower power demands than mined bitumen production. Thus, the power outputs of all technologies are deemed incompatible with the power loads of even very large thermal bitumen operations, resulting in excess power production. However, the suitability of nuclear plants improves if co-production of electricity and steam is considered, for thermal bitumen extraction operations using steam assisted gravity drainage (SAGD) in excess of 50,000 barrels of bitumen per day. To meet this demand, the location of the nuclear power units in
The Nuclear Energy Option in Alberta, October 1, 2008 10 relation to the location of the oil sands operations is a key issue. Usually, the power demands of mined SCO projects are located in a relatively small area, which is the opposite of thermal SCO production. Most of the future thermal SCO production will involve extracting bitumen on-site with upgrading taking place in the Industrial Heartland Area east of Edmonton. Thus, depending on upgrading technology and its location, 40%–70% of the increase in electrical demand would be near Ft. Saskatchewan, with the balance located at the SAGD sites farther north.
Discussion of Forecast Scenarios
The AESO scenarios are based on the following critical assumptions, which should be evaluated:
Coal-fired plants will be able to buy CO2 offsets in the short run (up to 2015) and capture the CO2 emissions in the long run (up to 2024). No implications on costs or generation capacity are discussed. Because of assumptions about the availability and price of natural gas, natural gas will continue to be a fuel source for base load generation in the short run, but not in the long run. This implies that coal could be still preferred for base load generation in the long run. There is a time lag between adding new generation and new transmission; although some generation may be built in the next 1.5–2 years, transmission construction may take 5–8 years. Development of transmission lines may be constrained by the requirement to obtain the appropriate rights-of-way.
The Nuclear Energy Option in Alberta, October 1, 2008 11 References
ACR, 2004 Alberta Chamber of Resources (2004). Oil Sands Technology Roadmap: Unlocking the Potential.
AESO, 2005 Alberta Electric System Operator (2005). 20-Year Outlook Document (2005– 2024) [Electronic version].
AESO, 2007a Alberta Electric System Operator (2007). Future Demand and Energy Outlook (2007–2027) [Electronic version].
AESO, 2007b Alberta Electric System Operator (2007). Powering Alberta. 2007Annual Report [Electronic version].
AESO, 2007c Alberta Electric System Operator (2007). 10-Year Transmission System Plan (2007–2016) [Electronic version].
AESO, 2008 Alberta Electric System Operator (2008). Powering Alberta. Presented at Calgary Chamber of Commerce by Dale Master. Retrieved August 11, 2008, from http://www.aeso.ca/downloads/ Calgary_Chamber_of_Commerce_April_24_2008__final.pdf
Bersak, 2007 Bersak, A.F., & Kadak, A.C. (2007). Integration of Nuclear Energy with Oil Sands Projects For Reduced Greenhouse Gas Emissions and Natural Gas Consumption. MIT Center for Advanced Nuclear Systems, MIT-NES-TR-009.
Energy, 2008 Alberta Energy (2008). Electricity Statistics. Retrieved August 25, 2008 from http://www.energy.gov.ab.ca/Electricity/682.asp.
ERCB, 2008 Energy Resources Conservation Board (2008). Alberta’s Energy Reserves 2007 and Supply/ Demand Outlook 2008–2017 ST98-2008 [Electronic version].
Health, 2007 Alberta Health and Wellness (2007). Population Projections for Alberta and its Health Regions 2006–2035. Health Surveillance and Environmental Health Branch [Electronic version].
MSA, 2006 Market Surveillance Administrator (2006). Market Concentration Metrics [Electronic version].
Ordorica, 2007 Ordorica-Garcia, G., Croiset, E., Douglas, P. L., Elkamel, A., & Gupta, M. (2007). Modelling the energy demands and greenhouse gas emissions of the Canadian oil sands industry. Energy Fuels 2007, 21, 2098–2111.
The Nuclear Energy Option in Alberta, October 1, 2008 12 CHAPTER 3: FUTURE ENERGY TECHNOLOGIES
Summary
This chapter provides an overview of different energy alternatives to meet Alberta’s electricity needs. These technologies are subdivided into three main categories: fossil fuel, renewable, and nuclear energy. There are numerous options for meeting Alberta’s energy needs. In comparing these different technologies, it is important to understand the underlying parameters such as costs, environmental footprint, sustainability, reliability, and capacity. The issue of greenhouse gas emissions should also figure in the analysis of different energy sources. Items of note in this chapter are as follows:
Coal based electricity production is well-established in Alberta. Supercritical pulverized coal technology is currently the technology of choice due to its efficiency. Coal-fired power plants are large scale (400 MW or greater) and are better-suited for base load power. Natural gas-fired power is also very common in Alberta. Uncertainty surrounding natural gas availability and price have an impact on its long term potential, and make it better suited for peak power production. Increasing concern surrounding greenhouse gases pushes forward carbon capture technology. Three main options are currently at the forefront: post-combustion capture, oxyfuel combustion, and pre-combustion capture in an integrated gasification combined cycle (IGCC). All three result in a significant increase in the power production cost. Different alternatives for renewable energy are present in Alberta. Their inherent intermittency, availability, capacity, and cost currently limit the extent of their energy contribution to, and integration in, the Alberta grid system. Four basic types of commercial nuclear power plants were identified as having potential applicability in the province. These have different characteristics such as technology availability, reactor size, requirements for enrichment, heavy-water production, applicability to heat applications, and reactor efficiency. All of these reactors could be available within the next 20 years. The cost of large scale nuclear power production is similar to a coal power plant equipped with CO2 capture.
Fossil Fuel-based Energy
The abundance and low cost of coal in Alberta make it an attractive energy source. Different types of coal-based power plants can be considered. Although well-established, subcritical pulverized coal (16 MPa steam) power plants are not considered an advantageous option due to their lower efficiency compared to supercritical pulverized coal (>22 MPa steam) units, which are widely available. Supercritical technology is more expensive but features a higher efficiency that yields comparable electricity costs because of lower fuel consumption and emissions level than subcritical plants.
Ultra-supercritical pulverized coal (>27 MPa steam) technology is the subject of ongoing research and has not yet been demonstrated commercially. The high temperature and pressure involved mean that specialized materials that can sustain the severe process conditions must be
The Nuclear Energy Option in Alberta, October 1, 2008 13 developed. This is the last major hurdle before commercial implementation of this technology becomes feasible, which is likely to take place within the next 10–15 years. Ultra-supercritical coal combustion would yield an additional efficiency gain over supercritical coal that may warrant the anticipated higher capital cost of this technology.
All of these pulverized coal plants are best suited for large-scale (400 MW and greater) base load generation because they are capital-intensive, with capital requirements proportional to steam pressure. Their availability factors are high, typically ranging between 85% and 90% for the latest generation of plants. Table 3-1 provides a comparison summary of the techno-economics of fossil- based power plants. To set the cost of the different technologies assessed in context, the current consumer cost of electricity is $0.08/kWh in Alberta.
The greenhouse gas emissions are a noteworthy factor when the environmental performance of these plants is considered. The impact of implementing CO2 capture in subcritical and supercritical pulverized coal plants on a price, emission, and efficiency basis is significant. As shown in Table 3-1, the levelized cost of electricity from a subcritical coal plant almost doubles with the addition of CO2 capture. There are a number of different technologies that allow CO2 capture from a fossil fuel power plant; the three main approaches are post-combustion capture, oxyfuel combustion, and pre- combustion capture. Post-combustion capture removes CO2 from flue gas downstream of the combustion stage using chemical absorption. Pre-combustion capture scrubs CO2 from gasification- derived synthetic fuel gas prior to its combustion, via physical absorption.
Oxyfuel combustion uses purified oxygen to burn the fossil fuel, resulting in a flue gas primarily composed of CO2 and water vapour, without any nitrogen. This technology is in the advanced demonstration phase, and its commercial implementation is anticipated about 2015. Oxyfuel combustion has the advantage of producing a highly concentrated CO2 stream, which could be injected underground as part of CO2 storage projects following dehydration. Also, air-fired coal plants have the potential to be retrofitted to oxyfuel operation, if CO2 capture is required. The main challenge for oxyfuel is the large amount of energy currently required to produce the required oxygen, and the added cost of an oxygen separation plant. A study (NETL, 2007a) has found that the efficiency of oxyfuel plants is slightly better than that of a supercritical coal plant with CO2 capture. Capital costs of the former are slightly higher than the latter, but the levelized cost of electricity is lower for oxyfuel combustion as shown in Table 3-1.
The Nuclear Energy Option in Alberta, October 1, 2008 14 Table 3-1. Summary of techno-economics of fossil fuel plants (NETL, 2007, 2007a) a,g b,g Ultra- d,g f,h e,g Subcritical Supercritical c,g IGCC NGCC Oxyfuel supercritical CO2 capture No Yes No Yes No Yes No Yes No Yes Yes Gross output (MW) 583 680 580 663 583 650 770 745 570 520 792 Net output (MW) 550 549 550 546 556 545 640 555 560 482 546 Heat rate, HHV (MJ/kWh) 9.78 14.47 9.20 13.22 8.07 11.21 9.41 11.08 7.08 8.24 12.73 Efficiency, HHV (%) 36.8 24.9 39.1 27.2 44.6 32.1 38.2 32.5 50.8 43.7 28.3 i Plant cost ($/kWNet capacity) 1549 2895 1575 2870 1641 2867 1813 2390 554 1172 2930 Power cost i ($/MWh) 64.0 118.8 63.3 114.8 64.5 106.0 78.0 102.9 68.4 97.4 109.0
Table 3-2. Summary of environmental impacts of fossil fuel plants (NETL, 2007, 2007a) a,g b,g Ultra- d,g f,h e,g Subcritical Supercritical c,g IGCC NGCC Oxyfuel supercritical CO2 capture No Yes No Yes No Yes No Yes No Yes Yes CO2 emissions (kg/MWhNet) 855 126 804 115 706 98 796 93 361 42 65 j j SO2 emissions (kg/MWhNet) 0.35 Nil 0.33 Nil 0.29 Nil 0.05 0.04 Nil Nil 0.04 NOx emissions (kg/MWhNet) 0.29 0.43 0.27 0.39 0.24 0.33 0.22 0.22 0.02 0.03 0.38 Particulate emissions 0.05 0.08 0.05 0.07 0.04 0.05 0.03 0.03 Nil Nil 0.009 (kg/MWhNet) Hg emissions -6 4.77 7.09 4.53 6.47 3.94 5.53 2.33 2.69 Nil Nil 0.82 (×10 kg/MWhNet) Raw water usage 2566 5042 2248 4338 1817 4088 1420 1862 1022 1840 2952 (L/MWhNet)
a Steam cycle: 16.5 MPa/565°C/565°C, includes flue gas desulphurization (FGD) and selective catalytic reduction (SCR) flue gas treatment, 90% CO2 capture via monoethanolamine (MEA) scrubbing b Steam cycle: 24.1 MPa/593°C/593°C, includes FGD and SCR flue gas treatment, 90% CO2 capture via MEA scrubbing c Steam cycle: 27.6 MPa/732°C/760°C, includes FGD and SCR flue gas treatment, 90% CO2 capture via MEA scrubbing d GE quench gasifier, 2 GE 7FA turbines, 3 pressure reheat heat recovery steam generator (HRSG), Claus sulphur removal, 90% CO2 capture via Selexol scrubbing e Steam cycle: 24.1 MPa/599°C/621°C, includes FGD flue gas treatment, 95% CO2 capture via oxyfuel combustion with 95% mol O2 f 2 GE 7FA turbines, 3 pressure reheat HRSG, includes SCR flue gas treatment, 90% CO2 capture via MEA scrubbing g Dry coal properties are: 10.91% ash, 39.4% volatile matter, 49.7 carbon, 2.5% sulphur and 30.5 MJ/kg (higher heating value, HHV), cost = $1.80/MMBTU (HHV) h Natural gas HHV = 52.9 MJ/kg, cost = $6.75/MMBTU (HHV) i All costs in 2007 USD j SO2 emissions will occur at the natural gas processing plant.
The Nuclear Energy Option in Alberta, October 1, 2008 15 IGCC power plants have the advantage of allowing CO2 capture with a smaller incremental impact on capital and operating costs. Therefore, although IGCC costs without capture are higher than those of pulverized coal plants, both capital and electricity costs are lower than those of pulverized coal plants when CO2 capture is implemented. In addition, the removal of other criteria pollutants such as SOx, NOx, particulates, and mercury is higher in IGCC units, yielding an improved environmental performance over coal-fired plants. There are only a few IGCC plants in the world at this point, although many new units have been announced. Improved plant availability and efficiency are the main challenges of this technology. IGCC plants are better suited as base load systems and benefit from economies of scale, favouring implementation in the range of hundreds of megawatts.
Natural gas combined cycle (NGCC) is a mature technology. Unlike the coal technologies previously described, NGCC power plants are well-suited for peak load operation because they are less complex and can be put into operation more quickly. Due to the higher energy content of natural gas, the lower carbon content of the fuel, and the higher efficiency of the process, the CO2 emissions from NGCC plants are lower than those of coal-fired systems. Because of this, as well as its lower sulphur content and the absence of mercury, natural gas is considered a cleaner-burning fuel than coal. However, although SO2 is not emitted at the NGCC site, these occur at the natural gas processing stage. The electricity cost of NGCC plants is largely a function of natural gas prices, with fuel accounting for 60%–85% of NGCC operating costs. Thus, the cost volatility and shrinking reserves of natural gas worldwide make the long-term potential of NGCC technology in Alberta uncertain.
Chemical looping combustion is in the very early stages of development, and commercial implementation is not expected to be feasible before 2020. Chemical looping consists of using a metal oxide to supply the oxygen to burn the fuel, forming carbon dioxide and water vapour, with molten metal as the residue of the metal oxide. This molten metal then reacts with air in a separate vessel, releasing a large amount of heat and forming the metal oxide again. The fuel, which can be solid or gas, never comes in direct contact with the combustion air. The flue gas from the fuel-oxide reactor, which is used to drive a turbine, has a high concentration of CO2 that can be recovered at high pressure. This process has mostly been proven with natural gas or syngas fuel, and its adaptability to sulphur-bearing fuels such as coal has not been fully demonstrated. The large-scale feasibility of this process has yet to be fully demonstrated and it is not considered a likely alternative for Alberta within the next twenty years.
Renewable Energy
Renewable energy may take different forms such as wind, solar, bio-derived, hydro, and geothermal. Most renewable energies are commonly considered CO2 neutral (not adding to net CO2 production), and sustainable (not depleting resources). An inherent property of most renewable energy systems is intermittency, which refers to the unsteady nature of the energy produced due to its opportunistic nature. This applies to wind, solar, and even bioenergy, where the supply is seasonal and/or limited. An important limiting factor to consider with an intermittent electricity production system is the capacity of the grid to handle variable loads. Therefore, deployment of this type of energy in the Alberta electricity system would likely require the co-deployment of supplementary energy sources such as natural gas-fired peaking plants to compensate for the intermittency of renewable power.
The current amount of wind energy connected to the grid in Alberta is 500 MW, with 900 MW of projects in the process of approval (GOA, 2008). Most planned or active wind projects target
The Nuclear Energy Option in Alberta, October 1, 2008 16 southern Alberta where wind energy is the highest. Due to the issue of wind variability, it is expected that a 1-MW wind turbine will likely produce an average of 300–400 kW due to periods of no energy production. The intermittent nature of wind energy means that a considerable amount of planning is required to incorporate the contribution of wind energy into the grid in a reliable fashion. The grid itself must be flexible enough to balance the variable supply from wind power with fluctuating demands.
Solar power is another renewable technology. There are two different types of solar energy systems. Photovoltaic technology, which produces electricity directly from sunlight, currently enjoys the most advanced development status. Concentrating solar power plants use reflectors to focus a large amount of sunlight in a small area to produce heat. These systems have seen a dramatic increase in development and popularity worldwide. Unlike photovoltaic technology, concentrating solar power facilities are suitable for large-scale electricity generation, using solar energy to produce steam to drive power turbines. MSP-1, a solar project under construction in California, is set to produce 553 MWe by 2011 (Abengoa, 2008). The cost of photovoltaic and concentrating solar systems has followed a continuously decreasing trend, making them progressively more attractive on an economic basis while fossil fuel costs are increasing. However, material demands and labour availability have caused price stabilization or increases in different countries in the recent years as illustrated in Figure 3-1.
Figure 3-1. Evolution of price of photovoltaic modules and systems (ancillary equipment) in selected reporting countries accounting for inflation effects during 1996–2006 (IEA, 2007)
The current use of solar energy in Canada is mainly for small off-grid applications. In Alberta, there is a large potential for photovoltaic-based distributed energy for residential and small commercial applications. Also, as concentrating solar power plants are deployed globally, the resulting cost decreases will make large solar power plants in Alberta more attractive, especially under rising CO2 emissions constraints. The amount of solar energy available in Alberta has a wide spatial and seasonal range. The mean daily global (direct and diffuse) insolation in Alberta (averaged on an annual basis) is in the range 4.2–5.0 kWh/m2 for a stationary south-facing photovoltaic system but could be as high as 5.8–8.5 kWh/m2 for a two-axis sun tracking system (NRCAN, 2007). The
The Nuclear Energy Option in Alberta, October 1, 2008 17 latter figure is higher than insolation values for Germany and France, countries where solar power applications have risen in recent years. Widespread deployment of local solar power will require reliable proven energy storage systems with the potential to extend operations beyond daylight hours. Alternatively, backup power plants may be required to ensure a stable power supply.
Biomass-based electricity is fuelled by wood, agricultural residue, waste, or dedicated energy crops. Although biomass-fuelled electricity may be considered CO2 neutral based on the life cycle analysis of the feedstock, other emissions such as particulates and sulphur compounds are of concern. In addition, feedstock used in bio-electricity production is usually located in farmlands or forests far from load centers. This highlights the requirement for new transmission lines if large-scale deployment of this type of energy were to occur. Alternatively, biomass could be transported to plants located in the vicinity of load centres, but the low value and low bulk density of these materials make transportation relatively expensive. Stable feedstock availability is another potentially limiting factor. Increasing competition for feedstock and the environmental strain of large-scale biomass-based electricity production challenges the sustainability of large-scale implementation. The current cost of biomass-fuelled electricity production is greatly dependent on numerous factors such as the proximity and cost of the feedstock source, scale, and grid accessibility. An attractive implementation of biomass-based electricity is in industries where the feedstock is readily available as waste of the process and where residual heat can be recovered and used in the process, such as the pulp and paper industry. There has also been increasing interest in energy production from municipal solid waste, however, issues surrounding pollutant emissions and public perception are important to consider.
Geothermal energy is available in Alberta, and research has demonstrated the presence of moderate hydrogeothermal sources of energy in the Western Canada Sedimentary Basin. This basin has a temperature ranging from 50°–125°C (Jessop, 1991) and is therefore not directly suitable for electricity production using a steam cycle. However, electricity production may be possible using a binary-cycle plant.8 A number of binary-cycle geothermal plants are currently in operation in the U.S. The advantages of geothermal energy include the stability of the energy source, making this suitable for base power. Binary-cycle geothermal plants are built in a modular fashion and can span the range 1–100 MW. Economies of scale are achieved as plant sizes increase due to the exploration and well drilling costs.
Recent research has also identified the presence of geothermal energy in the northwest portion of the province (Majorowitcz, 2008). Unlike hydrogeothermal energy, this source is located at greater depths (5 km) in a limited permeability formation where a reservoir needs to be engineered, such as by fracing and water injection. This technology is still at the demonstration stage. In addition, the location of the identified promising sources is remote from any current demand for power or grid transmission lines.
Hydroelectricity is currently contributing 900 MW to the grid in Alberta. Predictions for power development in the province have allowed for moderate addition to this contribution within the next 20 years. The AESO predicts an addition of 200 MW of small hydro capacity before 2024 (AESO, 2005). Two significant projects are currently being discussed; a 100-MW project at the Dunvegan site on the Peace River is being proposed and a large project on the Slave River is currently under consideration. This latter project could provide 1200–1300 MW of electricity. However, both of these will have long lead times and are unlikely to be implemented within the next 20 years. The costs of hydroelectricity generation facilities are highly variable based on site condition and scale.
8 Binary-cycle geothermal plants use a heat exchanger to transfer heat from the hot water to a secondary working fluid with a lower boiling point. The working fluid is then used to drive a turbine.
The Nuclear Energy Option in Alberta, October 1, 2008 18 The International Energy Agency has surveyed international experts to compile techno- economic details of state-of-the-art power generation technologies (IEA, 2005). The information concentrates on recently commissioned or planned power plants. Results from this study relating to the cost of renewable energy production are summarized in Table 3-3. It is important to note that the levelized costs were calculated based on the reported project lifetime, which varied across different projects and technologies, usually spanning 20–40 years, and that a discount rate of 10% was applied.
Table 3-3. Summary of techno-economics of renewable energy (IEA, 2005) Solar Biomass Geothermal Wind (photovoltaic) (binary-cycle) Reported Plant Size 1–100a < 5 10–100 1–100b Power Output (MWe) Plant costc ($/kWe) 976–1634 3363–5239d 1700–2178 2160 Power costc ($/MWh) 46–144 209–743d 50–100 42 Availability/ Capacity (%) 17–38 9–24 85 - a Individual wind turbine sizes range from 30 kWe to 2 MWe, b Cost cited was for a 50-MWe plant. c Costs are in 2003 USD. d Reported value from Czech Republic for photovoltaic-based solar power was omitted from this table; estimates plant cost was $10,000/kWe and levelized cost was $2000/MWh.
This study notes a substantial potential for renewable energy in Alberta, especially relating to wind power. However, the issue of intermittency of wind and solar power will lead to the need for significant planning and flexibility relating to grid management. This can be somewhat mitigated with adequate wind forecasting and will be highly dependent on the existent power generation portfolio.
Nuclear Energy
This study identifies four basic types of commercial nuclear power plants that have potential applicability to electricity production in Alberta. These technologies include pressurized heavy-water reactors (e.g., CANDU), light-water reactors, high-temperature reactors, and small–medium reactors (Chicago, 2004). This categorization by reactor technology emphasizes the primary differences between systems in terms of availability of the technology, application-specific reactor size, requirements for enrichment and heavy-water production, applicability to heat applications, and reactor efficiency.
The four types of reactor technologies shown in Table 3-4 could all be available within the next 20 years. System performance data is provided under each reactor type. The key differences between the reactor technologies are summarized below.
Technology Availability. Reactor technology is constantly evolving as research and development results in improved designs. The technology may be subdivided into three categories according to the state of development. Near-term technology reactors (0–5 years) will have new certified designs and are based on the current proven nuclear power plants being used around the world today (337 light-water and 41 heavy-water reactors). According to the Canadian Energy Research Institute (CERI, 2008), approximately 11% of Canada’s electricity comes from 18 nuclear power plants producing nuclear power using heavy-water technology. New technology reactors are being designed to have enhanced safety, improved operation, performance, and economics. Mid-term (5–10 years) and future generation systems (10–20 years) will have further technology improvements that hold the promise of higher reactor efficiencies, lower costs, and systems sized and adapted to support distributed energy and non-electricity applications. These future systems include the very
The Nuclear Energy Option in Alberta, October 1, 2008 19 high-temperature reactor and the super-critical water-cooled reactor. Canada has signed arrangements to cooperate in the Generation IV International Forum (GenIV, 2007) that is developing these systems.
Table 3-4. Comparison of four reactor types and representative performance data Reactor Technology Size Fuel Moderator/ Reactor Reactor Type9 Availability Range Enrichment Coolant Outlet Efficiency (MWe) (fissile Temp (°C) (%) portion) Heavy-Water CANDU medium natural U HW low 35 Reactor reactors 700–935 0.7% U-235 (both) avg 300 near-term large slight HW/LW low 37 0–5 yr 1200 2.0% U-235 (hybrid) 319 Light-Water near-term medium– moderate LW low 35 Reactor 0–5 yr large 3.0%–5.0% (both) 328–343 650–1700 U-235 future large moderate LW/ medium 44 10–20 yr 1000– 5.0% U-235 supercritical 500–650 1700 water Small– mid-term small– moderate– 4S-Na cooled, medium 25–35 Medium 5–10 yr medium high HPG-H2/Po, 500–575 Reactor 10–300 5.0%– NuScale & IRIS- 20.0% U- LW/LW 235 High- mid-term dmall– high graphite/ medium- 42 Temperature 5–10 yr medium 10%–20% helium high Reactor 165–300 U-235 500–950 future small– high graphite/ high 50 10–20 yr medium 14%–20% helium 850–1000 250–300 U-235
Reactor Size. The heavy-water and light-water reactors support large distributed base-load energy production. Most nuclear power plants currently deployed world-wide are large compared to the average size of the non-nuclear power plants in Alberta. High-temperature reactors and small– medium reactors best match smaller decentralized electricity and heat applications, and are suited for locations where the electrical transmission capacity is limited.
Fuel Enrichment. The current generation of heavy-water reactors in Canada uses natural uranium containing 0.711% fissile U-235, however, new systems use slightly enriched fissile fuel (2.0%). Light-water reactors and most small–medium reactors use moderately enriched uranium- oxide fuel (3%–5%). The high-temperature and future generation systems require the most enriched fissile fuel (up to 20%). Enriched fuel requires additional processing that is not currently available in Canada. Enriched fuel can be purchased through international markets, or local capabilities could be developed. However, the enrichment process is expensive and could create proliferation concerns. None of these enrichment levels are defined by international safeguard standards as highly enriched uranium10, i.e., suitable for weapons use without significant further enrichment.
Reactor Coolant/ Moderator. Nuclear reactors utilize a range of different moderators and coolants, with the most common being light water and heavy water. The reactors currently operated in
9 Table 3-4 is expanded in Appendix A with additional details (specific reactor systems and vendors, fuels, target markets, design certification status, etc.) and reference sources. The reactor system data are also referenced in Chapters 5, 6, and 7. 10 Uranium containing in excess of 20% of the isotope U-235
The Nuclear Energy Option in Alberta, October 1, 2008 20 Canada use deuterium-oxide (heavy water) as the coolant to remove the heat from the nuclear reaction and as the moderator to slow the neutrons so that they can be captured by a U-235 nucleus and result in nuclear fission. Conventional light-water reactors use ordinary water as the moderator and in the coolant loops. However, hybrid mid-term systems will be light-water cooled and heavy- water moderated. Canada currently lacks heavy-water production capability, and no new heavy-water plants have been announced. Heavy water may be available from sources outside of Canada, principally India. Future reactor designs may incorporate other materials such as graphite for neutron moderation, and molten sodium or potassium metal, or helium or CO2 gases as coolants. These new moderators and coolants will need to be thoroughly tested and evaluated for safety prior to commercial deployment.
Reactor Outlet Temperature and Reactor Efficiency. Heavy- and light-water reactors have relatively low outlet temperatures of about 320°C. High-temperature reactors and future generation systems are being designed for higher temperatures of up to 1000°C to enhance thermodynamic efficiency and to support non-electrical applications such as the production of hydrogen and/or high- pressure steam. As a rule of thumb, the higher the reactor output temperature is, the higher the overall system efficiency will be. New technology reactors are being designed with fuels and reactor internal materials that can withstand high temperatures; however these components will likely be more costly than those of conventional designs. The effects of high temperature on the reactor’s long-term structural integrity must also be determined before a reactor can be licensed.
From an environmental perspective, nuclear plants emit no CO2, SO2, NOx, or particulates, unlike fossil-fuelled plants and some bio-plants. This is desirable, especially in a CO2-constrained environment, if CO2 credits could be claimed. The consumption of raw water by nuclear power plants is in line with that of coal plants without CO2 capture, because both types of plants use similar systems to make steam and cycle it through turbines to make electricity; only the manner of heating the water is different. The amount of water required varies based on the cooling system deployed. Chapter 8 covers the water management in nuclear plants in depth.
Table 3-5. Summary of techno-economics of nuclear power plants11 (CERI 2005, 2008; Shropshire, 2008) Heavy- High- 12 Light-Water Small–Medium Water Temperature Net output (MW) 703–1121 650–1700 10–300 165–300 Efficiency (MWeNet/MWth, %) 35–37 35–44 25–35 42–50 13 Plant cost ($/kWNet capacity) 2000–3000 2300–3500 TBD 2900–4100 Power cost ($/MWh) 38–70 42–80 TBD 60–100
Table 3-5 provides a general comparison of the four nuclear designs previously covered to summarize the techno-economics of nuclear power. Nuclear power plants are capital-intensive. Their capital costs, however, are comparable to those of fossil plants with CO2 capture, for large plants. The electricity costs of nuclear plants are generally competitive with fossil plants. However, nuclear plants are largely insensitive to changes in fuel costs, unlike NGCC plants, for example.
11 All costs are preliminary estimates based on nth-of-a-kind units, and no cost premium for Canadian location. 12 Heavy-water reactor (ACR 700, ACR 1000) costs were extrapolated to 2008 to account for recent plant and equipment increases. 13 Plant costs are assumed to be overnight capital costs with no interest during construction.
The Nuclear Energy Option in Alberta, October 1, 2008 21 Energy Efficiency, Conservation and Management
Energy efficiency improvement can be implemented in the power generation sector in the form of retrofits and new technology aimed to increased energy production. As well, residential and industrial end users can adopt efficiency and conservation programs to reduce energy demands. In addition, strategies to manage existing and forecast energy usage patterns are attractive options for achieving an optimal balance between load supply and demand. An example approach would be to implement dynamic energy pricing combined with real-time metering, with peak demand periods associated with higher energy cost. While this may not always result in reduced energy usage, it would improve energy availability and system performance. To achieve maximum outcomes, energy demand management, conservation, and energy efficiency efforts must focus on specific high-impact sectors. A thorough cost-benefit analysis can highlight the best opportunities, which can in turn become the basis for a solid energy management program.
Energy efficiency, conservation and management measures may yield modest economical benefits for residential and industrial users. The potential impact that such measures could have on the future energy demand growth profile in Alberta must be established, as it is currently uncertain. However, it is anticipated that these measures alone would not counter the need for additional capacity. It is thus important to consider implementing energy efficiency, conservation, and management programs in combination with new generation capacity, to ensure adequate supply.
Meeting Alberta’s Energy Needs
As described in Chapter 2, Alberta’s energy demand will increase significantly within the next 20 years. An estimated additional required capacity of 4600–9500 MW is projected for 2025 (AESO, 2005). Different technological options to address this need for added capacity were described earlier. Additionally, energy demand management, conservation, and efficiency improvement measures must also be considered within a comprehensive energy development strategy for Alberta.
This review of different energy source alternatives indicates there is potential for renewable energy to contribute to Alberta’s energy portfolio. However, the issues of availability and capacity must be considered in the planning and integration of renewable based power plants into the existing system. The uncertainty surrounding natural gas availability and costs make this fuel an unlikely long-term contributor to base load power. Fossil fuel-based power will also be notably impacted by concerns surrounding greenhouse gas emissions. As described, post-combustion carbon capture, IGCC, or oxyfuel technologies could provide alternatives to address greenhouse gas emission concerns but will result in significant increases in the cost of power production.
Nuclear plants have the advantage of producing no greenhouse gas emissions and are economically competitive with fossil fuel plants featuring carbon capture. However, most nuclear plants will be larger in capacity than coal power plants currently operating in Alberta, imposing added demands on the transmission grid. In addition, issues surrounding implementation of nuclear power, such as construction time and waste disposal, must also to be considered. The following chapters provide an overview of the different issues and the impact of nuclear energy in Alberta in view of informing discussions surrounding the use of nuclear energy to meet Alberta’s energy needs.
The Nuclear Energy Option in Alberta, October 1, 2008 22 References
Abengoa, 2008 Abengoa Solar (2008). Concentrating Solar Power. Web presentation. Retrieved August 2008 from http://www.iian.ibeam.com/events/penn001/ 26826
AESO, 2005 Alberta Electric System Operator (2005). 20-Year Outlook Document (2005– 2024) [Electronic version].
CERI, 2005 Canadian Energy Research Institute (2005). Electricity Generation Technologies: Performance and Cost Characteristics. Prepared for the Ontario Power Authority.
CERI, 2008 Canadian Energy Research Institute (2008). The Canadian Nuclear Industry: Contributions to the Canadian Economy, Canadian Nuclear Association, Ottawa, Ontario.
Chicago, 2004 University of Chicago (2004). The Economic Future of Nuclear Power.
GenIV, 2007 GenIV International Forum (2007). 2007 Annual Report. Printed by the OECD Nuclear Energy Agency for the Generation IV International Forum.
GOA, 2008 Government of Alberta (2008). Talk About Wind Power. Retrieved August 2008 from www.energy.gov.ab.ca/Electricity/pdfs/FactSheet_Wind_Power.pdf
IEA, 2005 International Energy Agency (2005). Projected Costs of Generating Electricity 2005 Update. Nuclear Energy Agency and Organisation for Economic Co- operation and Development.
IEA, 2007 International Energy Agency (2007). Trends in Photovoaltaic Application Survey report of selected IEA countries between 1992 and 2006. Report IEA- PVPS T1-16:2007.
Jessop, 1991 Jessop, A. M., Ghomshei, M. M., & Drury, M. J. (1991), Geothermal Energy in Canada, Geothermics, 20, 369–385.
Majorowitcz, 2008 Majorowitcz, J. & Moore, M. C (2008). Enhanced Geothermal Systems (EGS) Potential in the Alberta Basin. Retrieved August 2008 from http://www.aeri.ab.ca/sec/new_res/docs/Enhanced_Geothermal_Systems.pdf
NRCAN, 2007 Natural Resources Canada (2007). Photovoltaic potential and solar resource maps of Canada. Retrieved August 2008 from https://glfc.cfsnet.nfis.org/ mapserver/pv/index_e.php
NETL, 2007 National Energy Technology Laboratory (2007). Cost and Performance Baseline for Fossil Energy Plants. DOE/NETL-2007/1281.
NETL, 2007a Energy Technology Laboratory (2007), Pulverized Coal Oxycombustion Power Plants. DOE/NETL-2007/1291.
The Nuclear Energy Option in Alberta, October 1, 2008 23 Shropshire 2008 Shropshire, D., et al. (2008). 2008 Advanced Fuel Cycle Cost Basis, INL/EXT- 06-11536.
The Nuclear Energy Option in Alberta, October 1, 2008 24 CHAPTER 4: INTEGRATION OF NUCLEAR POWER PLANTS INTO ALBERTA’S ELECTRICITY GENERATION MIX
Summary
This chapter addresses the issues surrounding the integration of nuclear power plants in Alberta. The highlights of this chapter are as follows:
The infrastructure needed to establish and operate a nuclear power plant is extensive and will require significant planning. A large portion of the required physical resources can be obtained in Canada but certain components will have to be imported. The needs extend beyond the nuclear reactor itself to waste fuel storage as well as ancillary infrastructure. Additional infrastructure requirements to distribute these resources to the chosen site should also be considered. The deployment of a nuclear power plant is subject to a number of risks involving the technology itself, licensing, cost of construction, financing, construction time, supply infrastructure, cost of fuel, waste disposal, and risks of accident or terrorism. Measures to mitigate these risks should be taken. Another major risk to consider is the current uncertainty surrounding future policies and penalties involving greenhouse gas emissions since these will significantly affect the economical comparison of nuclear and fossil fuel- based electricity. The integration of a large-scale nuclear power plant may require a substantial reinforcement of the transmission system, which can pose a major challenge, especially if there is stakeholder opposition. However, this issue is a function of the size of the new generator and hence is not specific to nuclear units. As a new generator, the nuclear plant operator will have to pay some costs associated with integration into the transmission grid as well as a potentially refundable system contribution fee.
Infrastructure and Resources Required for a Nuclear Power Plant
The introduction and successful execution of a nuclear power program in Alberta is dependent on a wide range of activities and capabilities. The International Atomic Energy Agency (IAEA) has accumulated world-wide experience on this topic (IAEA, 2004, 2006a, 2006b, 2007a, 2007b). A basic infrastructure is required to plan, construct, and operate nuclear power plants. The infrastructure includes safety standards (Chapter 7), a knowledge base and human resources (Chapter 9), national laws and regulations and a nuclear regulatory body (Chapter 10), and physical resources. This section describes the required physical resources and siting considerations.
The siting process is an important stage in the development of a nuclear power plant. During this stage, potential sites are surveyed to determine the definitive site. The evaluation criteria for assessing the site must consider the effects from ionizing radiation and other factors arising from nuclear installations. The selection of the suitable site is the result of a process in which the cost, the impact to the environment, and the risk to the population are minimized (IAEA 2006b). The activities related to siting a nuclear power plant consist of a site survey and site evaluation. A site survey may include a regional analysis and identification of potential sites, screening of potential sites, and selection and comparison of the candidate sites. The purpose of this survey and evaluation is to ensure
The Nuclear Energy Option in Alberta, October 1, 2008 25 that all preferred sites are acceptable from all aspects, and in particular from the safety point of view. Site-related design bases are evaluated before the start of plant design. After the start of construction but prior to operations, additional studies are conducted to refine the assessment of site characteristics for the purpose of developing emergency plans.
Siting considerations must include the following factors:
Water supply. There must be sources of water to support construction, and cooling water must be of sufficient quantity and temperature during operations for heat removal. Power supply. Proximity to regional grids and transmission corridors, technical integration into the grid, and availability of standby and emergency power supply systems must be considered. Ease of access. Transportation and facility access to technological, community, and service support must be adequate. Roads and railways must be capable of receiving and handling very large and heavy loads for delivery of reactor components and equipment. Earthquake monitoring stations. Monitoring stations must be set up in the region of the site in advance of construction to provide data on geologic and seismic stability. Meteorological14 and hydrological monitoring stations. Prior to plant siting approvals, a significant amount of monitoring data must be collected, including wind speed and direction, atmospheric pressure, dispersion patterns, rainfall, ground water, and surface flooding. Land uses. The site needs to have minimal conflict with other land uses such as indigenous, cultural, archaeological, heritage, or economic impacts; Availability of local infrastructure. There must be administrative facilities for project management and for living accommodations for workers if the site is remotely located. Environmental/Regulatory. The site must meet all environmental and ecological regulatory requirements determined by the environmental assessment process. This process also determines if more than one plant can be constructed at the same site in the future.
The nuclear power plant physical facility includes the site, interconnection between the grid and the nuclear power plant, physical protection facilities, component manufacturing and material supply, calibration laboratory, low- and medium-level radioactive waste storage and disposal, spent fuel storage and disposal, safeguards, emergency response facilities, and emergency notification capability.
Planning for the manufacture of components and material for the project should be started early so the facilities, local manufacture of equipment, and supply of material are ready when required in the project schedule. Table 4-1 shows three estimates of the quantities of common construction materials and manufactured components required for a typical nuclear power plant, to illustrate the material needs to be integrated into the planning process.
To place these figures into context, it is useful to consider the portion of each major component type that would likely be met by imports versus domestic production. In a recent study (CERI, 2008), the Canadian Energy Research Institute (CERI) compiled this data for construction of a CANDU-6 reactor (a Canadian design). Components that CERI estimates would be substantially (greater than 10%) supplied by imports include iron and steel pipes and fittings (37% import content by value),
14 The site weather is not a primary concern; nuclear power plants have already been installed in northern latitudes (e.g., Finland), which are known for harsh climatic conditions.
The Nuclear Energy Option in Alberta, October 1, 2008 26 metal tanks (45%), valves (42%), pumps and compressors (68%), electrical generators and motors (75%), and measuring and controlling instruments (22%). Most other components would be supplied domestically, including boilers, prefabricated metal structures, trucks and material handling equipment, and power generation equipment. Overall, CERI estimates that about 7.5% of the cost of building a CANDU-6 would be for the purchase of imported items.
Table 4-1. Nuclear power plant construction and manufactured component requirements Material requirements15 (DOE, 2005) (Kenley, 2004) (NEI, 2008) Carbon steel (tonne) 64,400 17,100 59,900 Concrete (m3) 351,000 325,300 305,900 Large-bore pipe (m) 79,200 112,600 70,800 Small-bore pipe (m) 131,000 - - Cable trays (m) 67,000 - - Conduit (m) 365,000 62,900 - Power cable (m) 430,000 - 482,000 Control wire (m) 1,650,000 2,130,000 - Process and instrument tubing (m) 225,552 - - Electrical components (units) - - 130,000
The required nuclear infrastructure is impacted by the potential location of the nuclear power plant. Access to the site should accommodate the transportation of large reactor components by road, rail, or barge. Mismatches between the grid electrical capacity and the nuclear power plant output may require upgrades, including the need for additional spinning reserve (should the power plant have an unexpected shut-down), transmission lines, and interconnect equipment.
Designing for radioactive waste and used fuel storage must provide space for storing the fuel on-site in water-filled pools for 3–5 years until it is sufficiently cool to move into dry storage, and to facilitate transferring the waste to disposal sites in the future. Used fuel could be returned to fuel suppliers for reprocessing (i.e., to extract the fuel’s unused fissile fuel for reuse) or moved to interim storage facilities on the plant’s controlled property, which is often designed for over 100 years of operational life. Ultimate disposal of spent fuel would be subject to national laws and specific agreements with the Canadian federal government.
Additional facilities are required to ensure that special nuclear materials as well as services, equipment, facilities, and information, are not used for purposes other than the intended purpose of power production. These include facilities and plans for physical protection, safeguards, and emergency response and notification in case of emergency situations.
15 All of these plants are 1–1.4 GWe in size, but each source addressed a different type. DOE (2005) considered the average of requirements for three different sizes of reactors. The evaluation by Kenley (2004) was for ―a generic 1200–1500-MWe unit.‖ NEI (2008) considered ―a single new plant of around 1 GWe.‖
The Nuclear Energy Option in Alberta, October 1, 2008 27 Nuclear Power Plant Deployment and Power Transmission in Alberta
Nuclear Power Plant Deployment Risks
A major factor affecting the decision to build a nuclear power plant in Alberta is how the economics compare to conventional fossil fuel-based technologies before or after the imposition of CO2 emission penalties. The magnitude and timing of such penalties are impossible to forecast accurately now. This difficulty is compounded by other uncertainties such as the volatility of natural gas prices and the increasing construction costs for all types of power plants. This uncertainty suggests a wide range of plausible costs for future electricity deployment, no matter what the choice of the generating technology. Table 4-2 summarizes the primary deployment risks associated with nuclear power along with potential mitigation strategies.
Various government actions can be taken to reduce the nuclear deployment risks. (Bunn, 2008) Such actions could consist of production credits for low-carbon generation, insurance for regulatory risks, and loan guarantees. Investment partners could share the risk of the costs of nuclear projects.
The Nuclear Energy Option in Alberta, October 1, 2008 28 Table 4-2. Nuclear deployment risk areas and potential mitigation strategies Risk Area Risk Mitigation Strategy Construction of these plants in other countries or provinces will reduce the Many new nuclear plants being built in the next construction risk for Alberta. Foreign Technology decade will have designs that have never been experience with first plants will guide built before. investors’ expectations for cost, schedules, and performance. The new streamlined licensing process with the Standardized reactor designs should help Licensing early site permit and the combined license has the streamlined process work. never been exercised. Reactor capital construction costs (including Future plants should benefit from having interest) make up about 60% of the cost of fewer parts. A revised licensing process is Cost of plant electricity. Historically, the actual construction expected to reduce the number of mid- construction costs for nuclear facilities have been roughly construction modifications blamed for the double the initial estimates. earlier cost overruns. The current assumption for new reactor builds is five years based on a streamlined regulatory Recent project performance on reactor Nuclear policy. The influence of construction time on the restarts (e.g., Browns Ferry Unit 1 in May construction total cost of electricity is especially important and 2007) has shown that project completions time has been of particular concern in the investment on schedule and cost are possible. community. The nuclear construction hiatus in the U.S. and Canada has led to aging workforce and The first orders for construction of reactors Nuclear supply atrophied the manufacturing/construction in Asia are expected to spur investments infrastructure infrastructure. For example, the only current by component vendors to ramp up world supplier of large steel forgings is Japan capabilities. Steel Works. The cost of construction financing is substantial for all capital-intensive technologies, making up Uncertainties in other energy sources (e.g., 5%–15% of the total cost of electricity for a Cost of natural gas fuel cost spikes or impact from nuclear plant. Nuclear energy has been viewed financing a carbon tax) have tended to level the by financiers as a riskier investment than playing field for financing. competing alternatives and could be assessed higher financing rates. Fuel costs have historically accounted for only 5%–10% of the cost of nuclear power. Uranium prices have fluctuated widely over the Cost of fuel The cost of nuclear power is largely past few years. insensitive to fuel prices.
The availability of low-cost dry cask Waste There exists no final repository in any country for storage makes this a modest financial disposition used nuclear fuel. factor, though it is politically large. Liabilities can be limited by legislation, A major nuclear accident or nuclear-related such as Canada’s Nuclear Liability Act Accidents/ terrorist incident anywhere in the world could (Canada, 1985) and the Price-Anderson terrorism risk make nuclear power projects very difficult to Act in the U.S. complete.
Nuclear Power Plant Deployment Opportunities
In contrast to the risks already described, nuclear power can also create new opportunities. Alberta could develop a nuclear-centered energy/industrial complex that maximizes the use of domestic resources while supporting infrastructure improvements, human resource skill enhancement, and economic development. The process to achieve this goal involves matching the nuclear power plant input requirements to Alberta’s resources, materials, and services, and the output energy products to localized load centers and secondary industries. Table 4-3 summarizes the primary opportunity areas associated with nuclear power along with examples.
The Nuclear Energy Option in Alberta, October 1, 2008 29
Table 4-3. Nuclear deployment opportunities and examples Opportunity Opportunity Examples Area The uranium needed for nuclear fuel is mined Nuclear power will use raw resources and from the Athabasca basin that extends from processes that are indigenous to Canada. Saskatchewan into Alberta. Several mines Resource Essentially, all the necessary nuclear fuel containing some of the world’s largest Utilization capabilities are available in Canada. resources may be tapped (e.g., McArthur These resources further support energy River, Rabbit Lake, McClean Lake, Cigar independence. Lake, and Midwest). The capabilities required to build nuclear When new capabilities are developed in grade facilities (concrete, rebar, and trained support of the nuclear plant, those skills workers) can be applied to support key and resources can be put to new uses infrastructure and energy projects (oil sands). Capability and after the plant is finished. Alberta’s future This could expand and help retain a pool of Manpower Skill nuclear enterprise will require that skilled workers in Alberta. Enhancements universities and trade schools be fully Nuclear stamp components and specialized engaged in producing the next generation skills (e.g., health physics) developed for of skilled workers that can support the nuclear can be extended to other industries energy sector in the 21st century. (e.g., equipment and services for nuclear medicine). Next-generation nuclear power plants are being designed to operate at high temperatures to improve their efficiency; Heat produced from high temperature gas this allows them to produce high quality reactors could be used in the extraction of oil steam and heat. These products could be from the Alberta tar sands. High quality heat used by process industries as an Energy Services could also be used to produce hydrogen (in alternative to fossil fuels that produce the near-term by electrolysis and in the future greenhouse gases. The reactors would by advanced processes) that could be used to have flexibility to shift from electricity lighten the heavy crude. production to producing hydrogen during off-peak load periods, to maximize economics. Nuclear could enable significant Heat and hydrogen produced by nuclear could expansion of renewable energy in Alberta, Renewable be combined with biomass (such as logging through the production of liquid (carbon- Energy residues from Alberta’s timber industry) to neutral) transportation fuels and produce ethanol and biodiesel. renewable electricity. Other nuclear products that are either derived from used nuclear fuel or Radioisotopes (e.g., produced in Chalk River) produced through secondary industries can be created to support public heath care Medical and spawned by the expansion of nuclear (medical isotopes, lasers, pharmaceuticals, Industrial expertise in Alberta, can improve the lives therapeutic administration of radiation), in Products of Canadians by helping save lives, manufacturing and construction (welding, increasing crop yields, strengthening lighting), and food industries (food materials, and serving in many other preservation). beneficial applications.
This list of opportunities builds on the nuclear capabilities identified by the Canadian nuclear industry (CERI 2008). Although not comprehensive, this list reflects the range of benefits that may be attributed to the deployment of nuclear energy in Alberta.
Nuclear Power Interconnection and Transmission
The Alberta Electric System Operator (AESO) is responsible for assessing the current and future needs of all electricity market participants and planning the capability of the transmission system to meet those needs. Specifically, the AESO is responsible for planning a transmission system
The Nuclear Energy Option in Alberta, October 1, 2008 30 that is sufficiently robust so that transmission of all anticipated in-merit electric energy can occur 100% of the time when all transmission facilities are in service and 95% of the time (on an annual basis) when operating under abnormal operating conditions (Alberta, 2003).
The AESO prepares and publishes the technical requirements for connecting generators to the transmission system (AESO, 1999). From the perspective of transmission development and electric system operations, the interconnection of a nuclear generation unit would have the same impacts and face the same issues as the interconnection of a new coal generation unit of similar size in the same location.
The lead time to build some new generation facilities such as wind turbines can be much shorter than the typical five- to eight-year lead time required to define and select routes, obtain approvals, acquire new rights-of-way, and construct a new transmission line and substation facilities. Therefore, the AESO’s transmission planning must lead load growth and generation development.
However, the lead time required for a new nuclear generation unit or a new green field coal generation unit may be similar to or longer than the lead time for any associated transmission facilities. These longer lead times would allow the AESO sufficient notice to incorporate any associated transmission facilities into its planning process and therefore reduce the risk that timely transmission access may not be available for the new generation unit. On the other hand, the generation development may need to begin prior to the development of any required transmission facilities. If significant reinforcement of the regional or even the bulk transmission system (such as between Calgary and Edmonton) is required, stakeholder opposition to the transmission development may pose a significant risk to the timely availability of transmission access for the new generation unit.
In Alberta, the largest single generation unit is currently 450 MWe. The development of any type of generation unit (not just nuclear) larger than 450 MWe could therefore impact system stability since the unexpected loss of the new generation unit would become the largest single unexpected loss of generation that the electric system would need to accommodate. Therefore, increased operating reserves or even additional transmission interconnections with neighbouring jurisdictions would be required. However, in Alberta’s deregulated generation market, any such impact on system operations or transmission interconnections would be the responsibility of the AESO, and any related costs would be recovered by the AESO from all market participants. In addition to increased system stability, additional transmission interconnections would also provide greater access to potential future markets for surplus generation, particularly in off-peak periods.
All new generators must pay for the costs of the radial extension of the transmission system to interconnect the new generator. Such costs would normally include the point of interconnection, a new transmission line, communications at the point of interconnection back to the existing system, and a new breaker at an existing substation if required (AESO, 2008c, Article 9.3(b)).
In addition, all new generators of 1 MW or greater must pay a system contribution equal to $10,000 per MW of the generator’s capacity, plus a further contribution of up to $40,000 per MW of the generator’s capacity depending on the location of the new generator. For 2008 and 2009, the AESO has determined area contribution amounts as follows: $40,000 per MW in the northeast area of the province including Fort McMurray, $22,500 per MW in the Edmonton area, $18,100 per MW in the southern area of the province, and zero in the Calgary and northwest areas of the province (AESO, 2008c, Article 9.12).
The Nuclear Energy Option in Alberta, October 1, 2008 31 This system contribution is potentially refundable without interest, over a period of nine years beginning on January 1 following the new generator’s commercial operation date. The potential refunds begin at 5.6% of the system contribution in the first year of the refund period, and increase in three stages to 16.6% per year, with the total potential refund being 100%. The refunds in each calendar year are contingent upon meeting the target commercial operation date and maintaining minimum annual capacity factors. Minimum annual capacity factors have not been established for nuclear generation plants, but for the sake of comparison, the minimum annual capacity factor for new base load coal generation plants is 75% (AESO, 2008).
The AESO recovers the cost of transmission losses from generators, importers, exporters, and opportunity (non-firm) load customers. Each generator pays a losses charge or receives a losses credit equal to the hourly pool price multiplied by the generator’s metered energy delivered to the transmission system that hour, and further multiplied by a location-specific loss factor. The AESO determines and publishes the location-specific loss factors for each generator at least once every five years. Beginning in 2009, the location-specific loss factors associated with either a charge or a credit cannot exceed 12%. In 2008, loss charges are generally the highest in the Wabamun area (e.g., 6.64% for the Genesee units and 6.52% for the Keephills units), followed by the Fort McMurray area (e.g., 5.55% for Suncor and 5.68% for Syncrude). Loss factors are generally the lowest in the northwest, west, Calgary, and southeast areas of the province, and actually become credits in some locations (AESO, 2008b).
The Nuclear Energy Option in Alberta, October 1, 2008 32 References
AESO, 1999 Alberta Electric System Operator (1999). Technical Requirements for Connecting Generators to the Alberta Interconnected Electric System, Revision 1.0.
AESO, 2008 Alberta Electric System Operator (2008). Generator System Contribution Policy, System Contribution Values for 2008 and 2009.
AESO, 2008b Alberta Electric System Operator (2008). Loss Factors Re-calculation, March 20, 2008.
AESO, 2008c Alberta Electric System Operator (2008). Terms and Conditions, as approved by AUC Order U2008-217.
Alberta, 2003 Government of Alberta (2003). Transmission Regulation to the Electric Utilities Act, S.A. 2003, c. E-5.1, Section 15(1).
Bunn, 2008 Bunn, M. (2008), Allocation of Risk in Building Capital-Intensive Electricity Generation: What Role for Government? Harvard Electricity Policy Group, Boulder, Colorado. Retrieved 2 September from http://belfercenter.ksg.harvard.edu/files/ Matthew_Bunn_risk_nuclear_financing_08.pdf
Canada, 1985 Department of Justice Canada (1985). Nuclear Liability Act R.S., 1985, c.N-28. Retrieved August 8, 2008 from http://laws.justice.gc.ca/en/showdoc/cs/ N-28///en?page=1
CERI, 2008 Canadian Energy Research Institute (2008). The Canadian Nuclear Industry: Contributions to the Canadian Economy, Canadian Nuclear Association, Ottawa, Ontario.
DOE, 2005 U.S. Department of Energy (2005). DOE NP2010 Nuclear Power Plant Construction Infrastructure Assessment. MPR-2776, Rev. 0.
IAEA, 2004 International Atomic Energy Agency (2004). Construction and Commissioning Experience of Evolutionary Water Cooled Nuclear Power Plants. IAEA- TECDOC-1390.
IAEA, 2006a International Atomic Energy Agency (2006). Basic Infrastructure for a Nuclear Power Project. IAEA-TECDOC-1513.
IAEA, 2006b International Atomic Energy Agency (2006). Potential for Sharing Nuclear Power Infrastructure between Countries. IAEA-TECDOC-1522.
IAEA, 2007a International Atomic Energy Agency (2007). Considerations to Launch a Nuclear Power Programme.
IAEA, 2007b International Atomic Energy Agency (2007). Milestones in the Development of a National Infrastructure for Nuclear Power. NG-G-3.1.
The Nuclear Energy Option in Alberta, October 1, 2008 33
Kenley, 2004 Kenley, C.R. et al. (2004). U.S. Job Creation Due to Nuclear Power Resurgence in the United States. INEEL/EXT-04-02384, Idaho National Engineering and Environmental Laboratory.
NEI, 2008 Nuclear Energy Institute (2008). Nuclear Power Plant Contributions to State and Local Economies, retrieved August 5, 2008 from http://www.nei.org/keyissues/reliableandaffordableenergy/factsheets/ nuclearpowerplantcontributionspage2
The Nuclear Energy Option in Alberta, October 1, 2008 34 CHAPTER 5: OPERATIONS, MAINTENANCE, AND DECOMMISSIONING
Summary
This chapter addresses the operational and decommissioning phases of nuclear plant life cycles. Specific topics such as fuel handling, safety, and security are discussed in later chapters. The key findings are as follows:
Because nuclear power plants are relatively large and capital expensive, any owner will insist on reliable operation. The larger the plant is, the greater the impact to the grid will be if it is unavailable, regardless of whether the plant is nuclear, coal, or some other type. The more capital intensive the plant is, the more economically harmful will be its unnecessary shutdown. Nuclear plant operation worldwide has improved over the past several decades, in part because of increased sharing of information within the industry. Regulators routinely make it clear that the primary responsibility for safety and operation falls on the plant owner. It is appropriate to inquire into the relevant nuclear industrial experience of any entity undertaking the construction, operation, and eventual decommissioning of nuclear power plants. There is no reason to relearn past lessons. It is also appropriate to inquire about what support network a new plant would have. If the plant were not a CANDU, there would be foreign expertise, but no significant existing Canadian nuclear industrial infrastructure. Regulatory control of nuclear plant siting, construction, and operation is a federal responsibility delegated to the Canadian Nuclear Safety Commission. Regulatory control of nuclear plant decommissioning is a federal responsibility, also delegated to the Canadian Nuclear Safety Commission.
History
The operation and maintenance of nuclear power plants has been a major force shaping the industry in Canada and elsewhere. By current standards, the need for strict operation and maintenance was not appreciated early in the industry. Over time, three trends emerged. All three can be observed in most countries with nuclear power plants, but the following examples and details are Canadian.
First, plants have become bigger. The first electricity generated by nuclear power in Canada was the Nuclear Power Demonstration plant in 1962, rated at about 20 MWe (CNS, 2002). The first commercial nuclear power plant was Douglas Point in 1968 at about 200 MWe (AECL, 1984). These two plants are best described as prototypes.
These were followed by the first four Pickering-A units at 515 MWe-net each in 1971–197216 and then the four Bruce-A units at 750 MWe-net each (1976–1978), Point LePreau at 635 MWe-net
16 The 250-MWe Gentilly-1 also started in 1971. It was a different design and was ultimately unsuccessful, operating only 180 days over 7 years.
The Nuclear Energy Option in Alberta, October 1, 2008 35 in 1982, four Pickering-B units at 516 MWe-net each (1982–1986), the four Bruce-B units at 822 MWe-net each (1984–1987), and four Darlington units at 881 MWe-net each (1990–1993) (WNA, 2008). Thus, in 30 years, individual plants have become 44 times larger.
Second, plant operation has improved. The capacity factor (the fraction of time a plant produces power) of the first Canadian plant rose from 54% to 82% over its lifetime (AECL, 1984). Average Canadian nuclear capacity factors are now approaching 90%. The need to shut down reactors for maintenance prevents plants from ever reaching 100%. Good plant operation is inseparable from good safety. A good picture of the evolution of safety-related aspects, and therefore improved plant operation, of the Canadian nuclear industry can be found in the series of formal national reports to review meetings on the International Atomic Energy Agency Convention of Nuclear Safety (Canada 1998, Canada, 2001; Canada 2004; Canada 2007).
Power capacity of Canada's current nuclear power plants, pending additional refurbishment or new construction 16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
Installed nuclear capacity (MWe net) 0 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040
Figure 5-1. Installed Canadian nuclear power plant capacity based on data assembled from WNA (2008), AECL (1984), and Canada (1998)
Third, some plants have required significant refurbishment. In 1997, the Canadian regulatory agency at the time, the Atomic Energy Control Board (Canada, 1998), took actions that eventually led to the shutdown of seven nuclear power plants because of poor maintenance and lack of an enhanced emergency shutdown system. The Board identified the problems and the plant owners decided which plants should be refurbished (sometimes with temporary shutdowns) and which should be permanently shut down.
In response, some owners chose to update while others chose to shut down. This caused a large drop in the Canadian nuclear power capacity; see Figure 5-1. Pickering A4 and A1 were refurbished in 2003 and 2005 (WNA, 2008). The four Bruce-A plants are being refurbished, as is Point Lepreau. Decisions on the refurbishment of the four Bruce-B plants, the four Darlington plants, the four Pickering-B plants, and Gentilly 2 are pending. A combination of plant aging and inadequate maintenance led to these required refurbishments.
The Nuclear Energy Option in Alberta, October 1, 2008 36 ―The management of nuclear power stations, for some utilities, has not been given adequate attention by the owners over the last decade. This lack of management has resulted in declining standards of operation and maintenance to the extent that operation and maintenance are now only marginally acceptable. Configuration control has become poor. To date, programs to compensate for the effects of aging degradation have not been fully successful. Large remedial programs are being put in place to correct these deficiencies and to achieve the necessary standards of excellence (Canada, 1998).‖
Reactor Operation and Maintenance
Several objectives impact the operation and maintenance of nuclear power stations:
Protect plant workers from industrial injuries and radiation exposure. Protect public from radiation exposure. Minimize the time required for maintenance to keep the plant in operation and make money. Minimize the cost of maintenance. Minimize the cost of future refurbishments. Maximize the lifetime of the investment. Meet regulatory obligations.
When plant owners take a longer-term view, operation and maintenance are often given higher priority. However, plant owners can take a shorter-term view because of the lack of foresight, the approaching end of a plant’s planned operation, or an excessive drive to reduce near-term costs. The regulator ensures that sufficient maintenance and safe operation occur to protect the public and workers. When inadequate maintenance occurs, the regulator steps in, as the Atomic Energy Control Board did in 1997.
The nuclear industry itself now expects such safety and operational information to be shared among reactor operators through groups such as the World Association of Nuclear Operators (WANO, web). The accidents at Three Mile Island and Chernobyl (see Chapter 7) have made it clear that an accident anywhere impacts nuclear power plants everywhere.
In addition to international organizations, there are reactor-type-specific organizations such as the CANDU Owners Group (COG, web), which includes CANDU owners from around the world. These types of organizations address all issues associated with that reactor type, including safety and economic issues.
There are also national organizations such as the Canadian Nuclear Association (CNA, web), which address all types of issues (e.g., safety and economic) for the nuclear industry in each country. The Canadian Nuclear Association represents the broad interests of nuclear industrial operations. In the case of Canada, national organizations only have experience with CANDU reactors so far.
In other words, in addition to the international organizations like the World Nuclear Association, World Association of Nuclear Operators, and the International Atomic Energy Agency, there are reactor-type organizations (like the CANDU Owners Group), industry trade organizations (like the Canadian Nuclear Association), and professional scientific/technical society organizations (like the Canadian Nuclear Society).
The Nuclear Energy Option in Alberta, October 1, 2008 37
Some countries with multiple reactor types have found it helpful to have an organization spanning those reactor types focused solely on safety and reliability, including sharing information among all reactor types as well as setting standards and best practices. For example, the mission of the Institute of Nuclear Power Operations is ―to promote the highest levels of safety and reliability— to promote excellence—in the operation of nuclear electric generating plants (INPO, web).‖ Canadian plants are involved with the Institute of Nuclear Power Operations. They are also involved in the U.S. Electric Power Research Institute because the CANDU Owners Group is a member.
A CANDU owner in Alberta would presumably join both the Canadian Nuclear Association and the CANDU Owners Group, if not already a member. An owner of a different reactor type in Alberta would presumably join the Canadian Nuclear Association and the corresponding reactor-type organization. The owner would have to determine if those associations were adequate. If a new type of reactor were built in Alberta, presumably this would be part of a new industrial effort worldwide to share experiences with the new technology, as well as with the Canadian Nuclear Association. The basic point is that Canada has nuclear expertise that would assist any new CANDU owner in Alberta, but it does not have a support network for other reactor types.
Regulators in all countries require extensive reporting of routine operation and of any abnormal situations. In Canada and many other countries, full-time regulatory inspectors are located at each nuclear power plant. They have access to the plant, staff, and documentation; they have authority to force a plant shutdown if they deem it appropriate.
All costs of operation and maintenance are borne by the reactor operator. Chapter 4 contains information on the workforce for both construction and operation.
Reactor Lifetime
The reactor lifetime is ultimately controlled by the condition of the equipment and systems, and can be influenced by regulatory authorities; nuclear power plants can only operate if licensed, and the license has a specified time period of operation. The regulator assesses the condition of each plant and decides if its continued operation is acceptable from a safety perspective.
In parallel, the plant operator must decide periodically if the plant continues to be economically viable. This includes deciding if the next set of major maintenance activities or refurbishment is warranted from a business perspective.
The plant designer can address many factors that determine the lifetime of a reactor, including the following five.
First, plants that are easier to maintain are likely to be kept in operation longer provided that their continued operation remains economically justified. Plants that are well maintained will likely achieve higher lifetimes. Newer reactor designs generally have fewer pumps, valves, and other mechanical parts to maintain. Equipment is now laid out with more attention to maintenance. Computer-aided design is commonplace so that designers can arrange equipment while checking maintenance accessibility.
The Nuclear Energy Option in Alberta, October 1, 2008 38 Second, worldwide experience suggests the requirement for extreme vigilance over the water chemistry conditions of the coolant and moderator during operation, and design of the system to minimize corrosion rates and the accumulation of corrosion products.17
Third, steam generators worldwide have proven to require maintenance and often replacement because of corrosion and vibration of internal coolant tubes. This is the place where the primary coolant (heated while in contact with radioactive fuel tubes) transfers heat to the system that then produces steam to drive turbines. The primary side of steam generators become radioactively contaminated because of corrosion products migrating into and out of the reactor itself. The radiation fields and the large size of steam generators make their replacement complex and expensive. Steam generator replacement in any type of reactor, for example during CANDU and light-water reactor refurbishments, requires reactor shutdown for several months. Designs using alternative materials and careful control of water chemistry have improved to reduce these material degradation problems.
Fourth, CANDU reactors are unique in having individual fuel channels containing a number of fuel bundles. This allows online refuelling in which each fuel coolant channel can be accessed, cooling flow can be maintained, and a number of fuel bundles can be removed from the channel and replaced with new fuel bundles. This is a key feature that allows the use of natural uranium fuel. CANDU refurbishments involving replacement of the fuel channels have been refined into efficient standard operations.
Fifth, one component that has never been replaced in light-water reactors is the large pressure vessel in which all the fuel assemblies reside. However, there have been extensive replacements of the large upper vessel closure heads and a lesser number of replacements of internal structures in the vessel. The materials and welds in these vessels suffer damage from neutrons leaving the fuel zone. Thus, the ultimate limit on reactor lifetime is the acceptable total radiation dose to these materials and the rate at which this dose is delivered. This rate depends on the shielding between the fuel zone and the vessel.
The components that receive the highest radiation damage are the fuel pellets, fuel tubes, and fuel assemblies themselves. These are not plant lifetime issues because these components are routinely replaced during refuelling.
Except for material radiation damage, the other lifetime issues are similar to those in many other industries: corrosion, vibration, temperature, and proper maintenance.
The outlook for nuclear power plant lifetimes was generally poorly understood when most of the current world nuclear power plants were built. Based on the information, standards, and regulations of the time, each was licensed for some period, trending up to 30 years for CANDUs built in the 1980s and 1990s, i.e., Bruce-B, Darlington, and Pickering-B. For comparison, most light-water reactors (both pressurized and boiling water reactors) in the U.S. were licensed for 40 years.
In several countries, the prospect has arisen of extending the original reactor licensed lifetime. The motivation is economic (to get more energy from the original investment) and timeliness (it is likely faster to provide power in future years by extending what already exists than locating and constructing new plants). The Canadian Nuclear Safety Commission has recently issued a regulatory document (CNSC, 2008) that addresses the potential for extending the lifetime of nuclear power plants of any type.
17 A classic example is the elimination of cobalt-seated valves. Early plant operators discovered radiation fields accumulating unexpectedly around coolant system components. Some of this was traced to valves incorporating a cobalt alloy, giving rise to radioactive cobalt when minute amounts would migrate into and out of the reactor itself. Such materials are no longer used.
The Nuclear Energy Option in Alberta, October 1, 2008 39
Several CANDU owners have assessed whether to shut down reactors prior to their original planned lifetimes or to refurbish the plant and obtain an extended lifetime. Analysis of the data for existing Canadian plants suggests that refurbishment has pushed lifetimes to 40 years (Pickering-A4) or 50 years (Point Lepreau). For comparison, many U.S. plants have been relicensed from the original 40 years to 60. It is expected that most of the current U.S. plants will eventually be extended. Lifetime extension in other countries is being considered.
The regulatory guidance from the Canadian Nuclear Safety Commission indicates that the ―technical scope of the project is adequately determined through an Integrated Implementation Plan that takes into account the results of an Environmental Assessment (EA), where required, and an Integrated Safety Review (ISR) (CNSC, 2008).‖ The EA portion of the process allows for public and provincial input. The EA is a harmonized process between the federal government and the provinces; there is one assessment that covers both, including nuclear matters (solely federal) and water matters (province).
―Performed by the licensee, the ISR involves an assessment of the current state of the plant and plant performance to determine the extent to which the plant conforms to modern standards and practices, and to identify any factors that would limit safe long- term operation. Operating experience in Canada and around the world, new knowledge from research and development activities, and advances in technology, are taken into account. This enables determination of reasonable and practical modifications that should be made to systems, structures, and components, and to management arrangements, to enhance the safety of the facility to a level approaching that of modern nuclear power plants, and to allow for long term operation (CNSC, 2008).‖
The plant owner has the burden to determine how to show to the Canadian Nuclear Safety Commission that any updates to the plant required for lifetime extension have been completed satisfactorily. The details depend on the plant, how it has aged, and what updates are required.
As Low As Reasonably Achievable (ALARA)
A key feature in all nuclear operations is to minimize exposure of the public and employees to radiation. All countries recognize the ALARA principle: keeping radiation exposures as low as reasonably achievable (IAEA, 1996). The exact implementation of this principle can vary by country, but the basic concept articulated internationally is that those who are involved with radiation sources must remain vigilant for ways to reduce exposure to workers or the public, and take all reasonable actions to keep exposures low.
The Canadian Nuclear Safety Commission has issued regulatory guidance (CNSC, 2004) on implementation of the ALARA principle. Most notably, the Commission states:
―ALARA incorporates the notion that the magnitude of effort that should be applied to control doses depends on the magnitude of projected or historical doses. Managers should review dose levels on a continuous basis to ensure they are ALARA.
Licensees are expected to reduce doses where this can be done without significant expenditures. To minimize the commitment of resources that are likely to have a poor
The Nuclear Energy Option in Alberta, October 1, 2008 40 return in safety improvement, the CNSC may consider that an ALARA assessment, beyond the initial analysis, is not required in the following circumstances:
1. individual occupational doses are unlikely to exceed 1 mSv/yr.
2. dose to individual members of the public is unlikely to exceed 50 μSv/yr,18 and
3. the annual collective dose (both occupational and public) is unlikely to exceed 1 person-Sv.
Considering doses to members of the public addresses situations where a limited number of people may receive significant fractions of the individual dose limit even if the collective dose is low (i.e., less than 1 person-Sv). In such situations, additional radiation protection measures may still be required.
In some situations, a decision is required on whether it is economically justifiable to take action to reduce dose levels. Safety literature widely discusses expenditures that can be justified economically. A discussion of the monetary value of the unit collective dose can be found in the International Atomic Energy Agency’s Safety Reports Series No. 21, Optimization of Radiation Protection in the Control of Occupational Exposure, which provides guidance when such decisions must be made.‖
Reactor Decommissioning
When nuclear power plants reach the end of their lifetimes, they are shut down permanently. The plant is then decommissioned to minimize risks to workers and the public. When nuclear power plants and other nuclear fuel cycle facilities are decommissioned, three options are observed internationally:
Safe storage. Remove the easier structures, partially decontaminate the site, await final decisions on the final components such as the reactor pressure vessel, and monitor and maintain residual structures. Permanent institutional control. Same as safe storage, except leave some structures permanently in place, typically encased in concrete and capped to prevent water ingress. Greenfield. Remove everything, demonstrate that the area meets some cleanliness standard, and release it for any potential new use.
The safe storage option is typically used when the reactor is at a location at which there are other commercial nuclear power plants still in operation. This is less disruptive and less hazardous to ongoing operations. Thus, for example, the four commercial nuclear power plants permanently shut down in Canada (Douglas Point, Gentilly-1, and possibly Pickering-A2 and Pickering-A3) are all co- located with operating nuclear power plants and are in various stages of safe storage (NEA, 2007, updated to account for Pickering-A2 and -A3). Canada also has decommissioning experience at Chalk
18 For those more familiar with older units of dose, note that 1 mSv (millisievert) is 100 mrem, so that 1 mSv/yr is 100 mSv/yr and 50 μSv/yr is 5 mrem/yr. These are common values internationally so it is incorrect, as some have charged (Mehta, 2005), that Canadian regulations are looser than those of other countries. The fraction of operational Canadian doses that arise from tritium can be higher than the fraction of doses in other countries because of the accumulation of tritium in the heavy water coolant, but the total dose limit is the same or lower. In any case, the use of light water as the primary coolant in the proposed advanced CANDU reactor (ACR) would substantially reduce tritium leakages.
The Nuclear Energy Option in Alberta, October 1, 2008 41 River Laboratories and Whiteshell Laboratories. Chalk River remains operational while Whiteshell has been shut down and is in the stage of active decommissioning. The first Canadian research reactor, National Research eXperimental, was at Chalk River and it is being decommissioned. The Canadian prototype Nuclear Power Demonstration reactor was near Chalk River Laboratories, and it is also being decommissioned.
The permanent institutional control option is typically used for locations at which it is impractical or impossible to remove radioactivity. Such sites can be released for other uses, with various restrictions associated with whatever level of residual contamination exists. This is called release for restricted use. There are four types of facilities for which permanent institutional control is sometimes used: uranium mines, high-level waste disposal sites, some early reactors, and some early nuclear processing facilities. For example, in the U.S. there are three small early commercial power reactors and several federal facilities that have been cleaned as much as practical before being partially encased in concrete. Some are in use for other purposes. For example, part of the reactor building at the Piqua Nuclear Power Facility is used by the City of Piqua as general offices, meeting rooms, and warehouse space.
The greenfield option is used when it is practical to clean up the entire site so that it may be released for some other purpose. This is called release for unrestricted use. Several facilities are in this condition in other countries, such as former power plant sites in the U.S. including Big Rock Point in Michigan. Some are completely greenfield, while some only house used fuel in dry storage casks (USNRC, 2008).
In decommissioning nuclear power plants, the three most difficult steps are often the following:
demolition of the radioactivity confinement/containment, disposition of the pressure vessel, and removal of used nuclear fuel from the site, either to continued storage or permanent disposal.
The confinement/containment is generally a very robust and stout structure, typically made of steel reinforced concrete. While these can be demolished using conventional techniques, site owners and regulators must decide if this is warranted in each instance.
The issues with the pressure vessel are its size, robustness, and radioactivity. The inside of the pressure vessel becomes radioactive because of surface contamination with corrosion products and activation products. Corrosion products are materials that corrode on the water side of the water system and become radioactive due to the time they spend in the pressure vessel. Corrosion products are surface contamination and they do not penetrate deep into the walls of the pressure vessel or coolant system piping. Activation products are radioactive materials created inside structures that are inside the reactor; these are not just on the surface, but are spread throughout such structural materials.
The surface contamination is generally removed prior to the safe storage phase. However, some radioactivity persists because of the activation of the elements in steel alloys to their radioactive counterparts. For example, non-radioactive cobalt isotope Co-59 becomes radioactive Co-60. It has a half-life of 5.27 years so that in 52.7 years after the reactor stops, the amount of Co-60 has decreased by 1000 times (actually a factor of 0.510). Therefore, the decision is sometimes to wait for several decades before cutting the pressure vessel into parts and shipping it away. Such demolition operations are possible and have been done, but they are expensive and expose workers to radiation. In the UK for example, the approach for several large gas-cooled pressure vessels is to clean up the site except
The Nuclear Energy Option in Alberta, October 1, 2008 42 for the pressure vessel. A trust fund will be established, and in 100 years the local community can decide either to use the trust fund to remove the pressure vessel and other residual components to attain greenfield status, or leave these components are they are and use the money for something else.
The issue with the removal of used nuclear fuel is where to send it. The options are a recycling facility (in relevant countries), eventual permanent geological disposal, another nuclear power plant, or interim storage. In Canada, used fuel is kept for now where it was produced.
The nuclear power plant owner is responsible for decommissioning, including all associated costs. Like the plants in other countries such as the UK and U.S., all Canadian nuclear power plants are required by law to have decommissioning funds that accumulate during reactor operation (CNSC, 2000). These funds are not accessible by the plant owners and ensure that funds exist to decommission the plant when appropriate. Canadian reactors are required to have approved decommissioning plans.
There is now significant international experience in decommissioning reactors. Costs can be reasonably estimated, regulators require that decommissioning be planned, and trust funds must be accumulated and set aside for decommissioning later. Low-level radioactive waste goes to appropriate low-level disposal facilities. High-level waste and used nuclear fuel go to storage until eventual permanent disposition.
The Nuclear Energy Option in Alberta, October 1, 2008 43 References
AECL, 1984 Atomic Energy of Canada Limited (1984). CANDU Operations, the Douglas Point Story, Power Projections, Special Edition, June 1984. Text available at http://www.cns-snc.ca/history/DouglasPoint/ DouglasPoint.html
Canada,1998 Atomic Energy Control Board on behalf of the Government of Canada (1998). Canadian National Report for the Convention on Nuclear Safety. Canadian government catalogue number CC2-0690E, text available at http://www.nuclearsafety.gc.ca/eng/readingroom/reports/cns
Canada, 2001 Canadian Nuclear Safety Commission on behalf of the Government of Canada (2001). Canadian National Report for the Convention on Nuclear Safety, Second Review Meeting, October 2001. CNSC catalogue number INFO-0723, also Canadian government catalogue number CC172-18/200E. Text available at http://www.nuclearsafety.gc.ca/eng/readingroom/reports/cns
Canada, 2004 Canadian Nuclear Safety Commission on behalf of the Government of Canada (2004). Canadian National Report for the Convention on Nuclear Safety, Third Review Meeting, September 2004. CNSC catalogue number INFO-0750 also Canadian government catalogue number CC172-18/2004E. Text available at http://www.nuclearsafety.gc.ca/eng/readingroom/reports/cns
Canada, 2007 Canadian Nuclear Safety Commission on behalf of the Government of Canada (2007). Canadian National Report for the Convention on Nuclear Safety, Fourth Review Meeting, September 2007. CNSC catalogue number INFO- 0763, also Canadian government catalogue number CC172-18/2007E. Text available at http://www.nuclearsafety.gc.ca/eng/readingroom/reports/cns
CNA, web Canadian Nuclear Association (n.d.). Website, http://www.cna.ca/english/about.asp, accessed August 2008.
CNS, 2002 Canadian Nuclear Society (2002). NPD Historical Plaque: Background Essay. Text available at http://www.cns-snc.ca/events/npd/npd_bckgnd.htm.
CNSC, 2000 Canadian Nuclear Safety Commission (2002). Financial Guarantees for the Decommissioning of Licensed Facilities, Regulatory Guide G-206.
CNSC, 2004 Canadian Nuclear Safety Commission (2004). Keeping Radiation Exposures and Doses As Low As Reasonably Achievable, Regulatory Guide G-129, Revision 1.
CNSC, 2008 Canadian Nuclear Safety Commission (2008). Life Extension of Nuclear Power Plants. Regulatory Document RD-360.
COG, web CANDU Owners Group (n.d.). Private website http://www.cogonline.org and public website http://www.candu.org, accessed August 2008.
IAEA, 1996 International Atomic Energy Agency et al. (1996). International Basic Safety Standards for Protection against Ionizing Radiation and for the Safety of
The Nuclear Energy Option in Alberta, October 1, 2008 44 Radiation Sources. Safety Series No. 115. Text available at http://www- pub.iaea.org/MTCD/publications/PDF/SS-115-Web/Pub996_web-1a.pdf
INPO, web Institute of Nuclear Power Operations (n.d.). Website http://www.inpo.info accessed August 2008.
Mehta, 2005 Mehta, M.D. (2005). Risky Business: Nuclear Power and Public Protest in Canada, Lexington Books, Toronto, 2005.
NEA, 2007 Nuclear Energy Agency (2007). Decommissioning in Canada—Current Status. The Decommissioning and Dismantling of Nuclear Facilities in NEA Member Countries—A Compilation of National Fact Sheets. Retrieved August 2008 from http://www.nea.fr/html/rwm/wpdd/canada.pdf
USNRC, 2008 United States Nuclear Regulatory Commission (2008). Fact Sheet on Decommissioning Nuclear Power Plants. Updated January 2008. Retrieved August 20, 2008 from http://www.nrc.gov/reading-rm/doc-collections/ fact-sheets/decommissioning.html
WANO, web World Association of Nuclear Operators (n.d.). Website http://www.wano.org.uk accessed August 2008.
WNA, 2008 World Nuclear Association (2008). Canada’s Uranium Production and Nuclear Power, Country Briefings, Last update July 2008. http://www.world- nuclear.org/info/inf49.html accessed August 19, 2008.
The Nuclear Energy Option in Alberta, October 1, 2008 45 CHAPTER 6: NUCLEAR FUEL HANDLING AND DISPOSITION
Summary
This chapter describes the handling and eventual disposition of nuclear fuel. The key findings are as follows:
Nuclear power plants that use existing uranium oxide fuels used in light- or heavy-water reactors) have many potential fuel sources so fuel availability is unlikely to be a problem. The commercial availability of fuels for potential new reactor types remains unknown unless they are designed to use fuels that are currently available. The operating utility would have to establish working relationships with the Canadian Nuclear Waste Organization (CNWO) for high-level and used nuclear fuel, as well as with the Low-Level Radioactive Waste Management Office (LLRWMO). Nuclear waste disposal is the responsibility of the owner of the nuclear power plant, who must pay all disposal costs. As with decommissioning, Canada requires trust funds established during reactor operation for eventual disposal costs. Low-level waste from a nuclear reactor in Alberta would have to be shipped to one of the 11 current facilities in Manitoba, New Brunswick, Quebec, or Ontario, or sent to a new facility to be built in Alberta. Used nuclear fuel from a nuclear reactor in Alberta would be stored at that reactor until Canada identifies a specific permanent disposal option or centralized interim storage. The Canadian used nuclear fuel program has focused on used CANDU reactor fuel and small amounts of fuel from test and university reactors. Use of any new type of fuel in Alberta would presumably lead to some alteration of the Canadian program. Control of transportation of nuclear materials is a federal responsibility given to the Canadian Nuclear Safety Commission.
Building a nuclear power plant in Alberta does not require building other nuclear infrastructure in the province, even if the plant is not of CANDU technology. Fuels are international commodities. The one exception is that low-level waste from a nuclear reactor in Alberta would either have to be shipped outside the province or sent to a new private facility constructed in Alberta. This is not an obligation of the province but one to be assumed by the utility.
Nuclear Fuel Cycle
A nuclear power plant exists as part of an integrated nuclear fuel cycle that starts with raw material and ends with waste disposal. Although this report focuses on the potential use of nuclear power plants in Alberta, the entire fuel cycle must be considered. Indeed, a commercial power plant may lead to other fuel cycle facilities in Alberta, the most likely of which would be a low-level waste facility.
The Nuclear Energy Option in Alberta, October 1, 2008 46 Parts of the Nuclear Fuel Cycle
Figure 6-1 illustrates the nuclear fuel cycle, starting with natural uranium ore from locations such as Saskatchewan. After mining and milling to make pure uranium oxide, fuel is made with or without uranium enrichment to increase the potency of the mix of uranium isotopes in the fuel. Fresh fuel is shipped to nuclear power plants, where it spends several years in the reactor making electricity and is then removed. In Canada, used fuel is stored at nuclear power plant sites pending eventual geological disposal. This approach is called the once-through or open fuel cycle.
Figure 6-1. Nuclear fuel cycle
There are two optional mass flows shown in the figure. The first is uranium enrichment, which is not required for heavy-water reactors but is required for all other types.
The second optional flow is recycling of the used fuel instead of relying on the once-through approach. In France, used fuel is sent to a facility that separates the useful uranium, plutonium, and other transuranic19 elements, which constitute at least 95% of the fuel mass, from the fission products, which are less than 5% of the light-water reactor fuel mass. The split for used CANDU fuel is about 99%/1% because it has lower burnup. Plutonium and some of the uranium is recycled to make more fuel for use in reactors; this approach is called a closed fuel cycle. Countries evaluate recycling differently. For example, Japan is starting up a separation facility to recover the energy in used fuel; the United Kingdom plans to close theirs due to economics and an aging facility. Recycling does reduce the amount of used fuel and high-level waste, but also produces some other waste in the process.
19 ―Transuranic‖ elements are those elements beyond uranium in the periodic table: neptunium, plutonium, americium, curium, etc.
The Nuclear Energy Option in Alberta, October 1, 2008 47 It may be of interest to note that there have been three nuclear facilities in Alberta, but only one is still in operation today. (LLRWMO, 2004)
Earth Science Extraction Company in Calgary has an operating licence to recover high- grade uranium from fertilizer-grade phosphoric acid. However, the company’s plant was shut down in 1987, partially decommissioned, and no longer produces uranium. The University of Alberta in Edmonton has a 20-kW SLOWPOKE research reactor. There is a low-level waste disposal and uranium processing facility in Ft. McMurray; it is not operating but is licensed as a standby facility.
Uranium Supply
The International Atomic Energy Agency has concluded that ―Uranium resources sufficient to meet projected nuclear energy requirements long into the future. There is enough uranium known to exist to fuel the world's fleet of nuclear reactors at current consumption rates for at least a century, according to the latest edition of the world reference on uranium published today (IAEA, 2008).‖ Increased demand and the prospects for new nuclear power plants have recently increased the price of uranium. This in turn has led to more exploration and reassessment of known resources. ―Given the long lead time typically required to bring new resources into production, uranium supply shortfalls could develop if production facilities are not implemented in a timely manner (IAEA, 2008).‖
―World nuclear energy capacity is expected to grow from 372 GWe in 2007 to between 509 GWe (+38%) and 663 GWe (+80%) by 2030. To fuel this expansion, annual uranium requirements are anticipated to rise to between 94 000 tonnes and 122 000 tonnes, based on the type of reactors in use today. The currently identified resources are adequate to meet this expansion. Deployment of advanced reactor and fuel cycle technologies could increase the long-term availability of nuclear energy from a century to thousands of years (IAEA, 2008).‖ The use of unconventional resources could expand uranium availability beyond that.
Uranium Enrichment
The first parameter that determines how much fuel must be provided to the power plant and how often it must be refuelled is uranium enrichment. The enrichment determines how much uranium ore must be mined to produce uranium fuel.
There are two significant isotopes of uranium in nature, U-235 and U-238, distinguished by the number of neutrons in each atom (143 for U-235 and 146 for U-238). All isotopes of uranium have 92 protons. U-235 is only 0.7% of uranium in nature; the other 99.3% is U-238. All nuclear reactors currently marketed are thermal reactors, in which U-235 will readily react or fission whereas U-238 will only react slightly. The low reactivity of U-238 means that uranium with the isotopic composition found in nature generally cannot sustain a nuclear fission reaction. Uranium with this natural composition is called unenriched uranium. Because of the low reaction rate of unenriched uranium, about 90% of the power plants in the world use uranium enriched in U-235, typically to 3%–5% U-235.
About 10% of the power plants do use unenriched uranium; they accomplish this by reducing the absorption of neutrons in water using heavy water instead of light water. Water, or more specifically the hydrogen in water, is commonly used as a moderator to reduce the energy of the neutrons in a reactor to increase their likelihood of being captured by a uranium atom and causing it
The Nuclear Energy Option in Alberta, October 1, 2008 48 to fission. There are two significant isotopes of hydrogen in nature, H-1 (called protium) and H-2 (deuterium). About 0.015% of hydrogen atoms in nature are H-2 (0.030% by weight). Both of these isotopes are stable and will not break down radioactively. There is also one radioactive isotope of hydrogen, H-3 (tritium). Water made of H-1 is called light water or simply water if there is no possibility of confusion. Water made of H-2 is called heavy water. Light water absorbs more neutrons (rather than just slowing them) than does heavy water. Therefore, reactors that use heavy water are more efficient in their use of neutrons than light water. This has three implications.
Heavy-water reactors can use unenriched uranium. Heavy-water reactors require a source of heavy water, which is made by processes such as cryogenic distillation or gaseous diffusion of H-2 from H-1. Heavy-water reactors generally have more H-3 than light-water reactors, because when H-2 absorbs a neutron, it creates radioactive H-3 (tritium). When H-1 absorbs a neutron, it creates H-2.20
Another type of reactor uses graphite, which has different properties as a moderator. Gas- cooled graphite reactors tend to use higher uranium enrichment levels of 5%–20%.
Enrichment concentrates U-235 in the fuel and produces a uranium enrichment by-product called tails in which U-238 is concentrated and U-235 is at a reduced concentration. This depleted uranium is a low-level radioactive waste, routinely disposed of in countries that use uranium enrichment. As Canada currently uses heavy-water reactors with unenriched uranium, it does not have depleted uranium to dispose of. The proposed advanced Canadian reactor, the ACR-700, uses slightly enriched uranium (2% U-235). If new reactors of this type are built in Canada, the fuel supplier (wherever it is located) will need to dispose of depleted uranium if enrichment facilities are established in Canada. The alternative would be to buy enrichment services from sources outside Canada.
Consider how much uranium ore is required to make uranium fuel as a function of uranium enrichment and uranium tails. The mass of fuel in this chapter refers only to the mass of heavy metal; other elements such as oxygen are not included.
For heavy-water reactors with unenriched uranium, the ratio is 1 tonne-uranium-ore per tonne-uranium-fuel. For advanced heavy-water reactors that are light-water cooled using 2% enriched uranium fuel, the ratio is 3.5–4.0 tonnes-uranium-ore per tonne-uranium-fuel, for tails of 0.2%–0.3% U-235. For light-water reactors using 3%–5% enriched uranium fuel, the ratio is 5.4–11.2, for tails of 0.2%–0.3% U-235. For gas-cooled/graphite reactors with 5%–20% enriched uranium fuel, the ratio ranges from 9.2–46.9, for tails of 0.2%–0.3% U-235.
Nuclear Fuel Burnup
The second key parameter is called burnup; it is the amount of energy obtained from nuclear fuel per mass of that fuel. Burnup determines how much fuel must be shipped to the nuclear power plant and therefore how much used fuel must be disposed of.
20 The deuterium content in light-water reactors does not become significant. Slight amounts of tritium are generated in light-water reactors from use of the lithium isotope Li-7 hydroxide additive for water chemistry control.
The Nuclear Energy Option in Alberta, October 1, 2008 49
Burnup is typically expressed in units such as GWth-day/tonne of the uranium in the initial fuel, so that energy is expressed as thermal power production times the number of days the fuel is in use. Heavy-water reactors using unenriched fuel achieve about 7.5 GWth-day/tonne (Rouben, 2003). Light-water reactors approach 50 GWth-day/tonne. Newer reactor fuels for gas-cooled reactors are projected to reach 200 GWth-day/tonne and hence require more U-235 and higher U-235 enrichment. Counterbalancing this, they can be designed either to contain less fuel in the reactor or to operate longer on a similar amount of fuel before refuelling.
Assuming a 33% thermal efficiency for water-cooled and 50% for gas-cooled reactors operating 90% of the time, an 800-MWe nuclear power plant would therefore have fuelling rates as follows:
heavy water, 106 tonnes-uranium-fuel/yr; heavy-water moderated, light-water cooled, 15–40 tonnes-uranium-fuel/yr; light water, 16–27 tonnes-uranium-fuel/yr; and gas-cooled, 3–11 tonnes-uranium-fuel/yr.
Table 6-1. Summary of fuel types Uranium Uranium Uranium Uranium oxide Uranium oxide or Others chemical form oxide with oxide with with 3%–5% oxycarbide with and natural 2% uranium uranium higher uranium enrichment uranium enrichment enrichment enrichment enrichment Reactor types existing advanced light-water helium-cooled varies CANDUs CANDUs reactors Commercial 6 companies none yet 17 companies in UK, others TBD reactor sources in 5 countries 16 countries vendor only Illustrative 7.5 ~20 30–50 50–200 varies burnup (GWth- day/tonne- fuel) Illustrative 106 15–40 16–27 3–11 varies fueling ratea (tonnes/year) Illustrative 106 60–138 143–178 97–123 uranium ore need (tonnes/yr) Physical form Pellet pellet pellet microspheres varies Material zirconium alloy zirconium zirconium alloy carbon/silicon varies containing the tubing alloy tubing tubing carbide coating fuel a Fueling rate for 800-MWe plant with 90% availability. Water-cooled plants assume 33% thermal efficiency; gas-cooled plants assume 50% thermal efficiency.
These numbers have three implications. First, the use of fuel in nuclear power plants is very low compared to fossil fuels. For example, a fossil plant of 39% thermal efficiency requires 2.4 million tonnes of bituminous coal per year or 1.3 million tonnes of natural gas. Second, if one multiplies the uranium fuel demands by the ratio of tonne-uranium-ore/tonne-uranium-fuel, one obtains the amount of uranium ore that must be mined. Table 6-1 shows that this varies modestly among reactor types (uranium tails are in the range 0.2%–0.3% U-235) and is quite low compared to
The Nuclear Energy Option in Alberta, October 1, 2008 50 coal mining numbers. Even allowing for the component of uranium ore that is not uranium, the mass of ore remains low because Saskatchewan’s high grade uranium ore deposits average up to 15% oxide in the bulk ore. Third, because the fuelling rate for heavy-water reactors is several times higher than that for light-water reactors, and since there are several times as many light-water reactors worldwide, the amounts of heavy-water and light-water used fuel are about the same. The radioactivity level in the light-water used fuel is higher.
Candidate Fuels
Table 6-1 summarizes fuel types.21 Water cooled reactors use uranium dioxide pellets in tubes made of a zirconium alloy. The exact zirconium alloy, its physical dimensions, and the design of fuel assemblies that group fuel tubes together depend on the reactor design.
Seventeen companies in 16 countries make light-water reactor fuel.22 Those with capacities greater than 500 tonnes/year are Belgium (750), France (820), Germany (650), Japan (3 companies totalling 1674), Kazakhstan (2000), Russia (2020), Sweden (600), and the U.S. (3 companies totalling 3900) (WISE, 2008). Similarly, commercial uranium enrichment plants operate in 11 countries. Each facility only makes fuel for certain exact reactor designs because the exact fuel used in a reactor must be licensed by the national regulatory agency for each specific reactor design.
Six companies in five countries make heavy-water reactor fuel. The largest are Canada (2 companies totalling 2700 tonnes/year) and South Korea (400), together comprising 87% of the world capacity. (WISE, 2008) Canada’s two companies are Zircatec Precision Industries (Port Hope, Ontario) and General Electric-Hitachi Nuclear Energy Canada (Peterborough, Ontario). As with light- water reactor fuel, a given facility only supplies certain reactors.
The light- and heavy-water reactor fuel industries are mature, widespread, and international. With more reactors in operation, the light-water reactor fuel industry is larger and more widespread. However, even heavy-water reactor fuel is international; a Japanese-American consortium operates the second largest plant in Canada.
The UK makes fuel for its existing gas-cooled reactors. If a new generation of gas-cooled reactors is built, they would likely require somewhat different fuel. In particular, South Africa is eager to enter this market for both reactors and fuel.
If a heavy-water reactor is built in Alberta, a logical fuel source would be the two existing Canadian facilities in Ontario. If a light-water reactor is built, the fastest route to acquire fuel would be purchasing it on the open international market from an approved vendor. If economics warrant them, new enrichment and fuel fabrication facilities could be built in Canada, either by a Canadian company (as CANDU fuel is not dissimilar to light-water fuel) or by a foreign or foreign-Canadian consortium. If a new reactor type were built, its fuel source would be limited to the reactor vendor, at least initially.
21 Unlike analogous tables in Chapters 4 and 7, the table in this chapter focuses on uranium chemical form and enrichment, which is the dominant parameter from the fuel cycle perspective. 22 The number of companies is uncertain as several are consortia. For example, British Nuclear Fuels Limited (BNFL) operates a plant in the UK, and in conjunction with Westinghouse operates plants in Sweden and the U.S. The French company AREVA operates plants in Belgium, France, and the U.S., and operates a plant in Germany in conjunction with Siemens.
The Nuclear Energy Option in Alberta, October 1, 2008 51 Fuel Handing and Operational Considerations
Fresh fuel is easily handled. In fact, uranium oxide pellets are often handled and inspected manually as they generate very little heat or radiation. As fuel is expensive, it is ordered from vendors with as little lead time as possible.
Light-water reactors typically shut down for refuelling every 12 or 18 months. The power plant is taken off-line, cooled down, and opened. A fraction (one-third, one-fourth, or one-fifth) of the fuel is removed. The remaining fuel is repositioned and new fuel added. Various plant maintenance activities take place during refuelling outages, which are kept as short as possible, on the order of weeks.
CANDU heavy-water reactors are unique in that they refuel during reactor operation. Since there are no refuelling outages as in a light-water reactor, there are scheduled maintenance outages for those components that cannot be maintained during reactor operation.
Used fuel from a nuclear reactor generates considerable heat and is intensely radioactive. It is therefore handled remotely and transferred to tanks generally cooled by water, to allow the radioactivity and associated heat release to decrease with time. In countries without recycling, the fuel is currently stored on-site pending eventual geological disposition. Some countries (including Canada) are contemplating centralized interim fuel storage facilities. Some countries allow transfer of used fuel from water tanks to dry storage casks once they have cooled for several years. Light-water fuel at 10 years generates about 1000 times less heat than at reactor discharge (Figure 6-2), so that cooling then is far easier. Dry storage casks are very robust and are cooled by ambient air.
Heat generated by light water fuel (50 MWth-day/tonne) 10,000,000
1,000,000
100,000
10,000
1,000
100 Uranium and transuranic Watts/tonne of fuel of Watts/tonne Fission products 10 Total
1 0.01 0.1 1 10 100 Years after reactor discharge
Figure 6-2. Heat generated by light-water fuel after discharge from a reactor
In addition to unrecycled discharged nuclear fuel, nuclear power plants also generate low-level waste during operation. Much of this stems from the primary coolant system. The zirconium tubing
The Nuclear Energy Option in Alberta, October 1, 2008 52 containing the fuel pellets do not generate significant amounts of mobile corrosion products, but the steel surfaces elsewhere in the cooling system do. These corrosion products migrate throughout the coolant system, spend some time on the tubing within the reactor itself, and thereby become radioactive. The radioactive cobalt, nickel, iron, and manganese are filtered from the water coolant, generating wastes such as the resin beds that capture these materials. Gas-cooled systems are generally less radioactive due to the lack of water corrosion products. Since there is less radioactive material in the coolant, there is also less operational waste generated.
Potential for Recycling Used Fuel
Several countries recycle used fuel to recover energy and reduce residual waste. The two barriers to this are cost and concern that recycling poses a weapon proliferation risk. A key issue in recycling is controlling the potential to obtain the highly enriched uranium or plutonium required for a nuclear weapon. There are four pathways to obtaining such material:
theft; enrich uranium, use it in a light-water reactor, then separate the plutonium produced; obtain heavy water, use unenriched uranium in a heavy-water reactor, then separate the plutonium produced; or use uranium enrichment without any need for production or separation of plutonium.
Thus, used fuel chemical separation, heavy-water production, and uranium enrichment are sensitive technologies. Any chemical separation of plutonium or use of plutonium-containing fuels could only be done if consistent with Canada’s international obligations and policies. Since the mid- 1950’s Canada has actively promoted a Fissile Material Cut-off Treaty that would effectively and verifiably ban the production of fissile material for nuclear weapons and other nuclear explosive devices (Canada, web). This would seem to preclude separation of pure plutonium from used commercial nuclear fuel, similar to the policy in the U.S. (NEPDG, 2001), but unlike France, Japan, and other countries. The U.S. and France are researching advanced fuel separation technologies that do not separate pure plutonium so that plutonium remains mixed with uranium and/or other transuranic elements.
Light-water reactors in several countries use recycled plutonium recovered from separation of used nuclear fuel. Instead of the normal uranium oxide fuel, some or all of the fuel in the reactor is a mixed oxide of uranium and plutonium. The two fuels (uranium oxide versus uranium-plutonium oxide) have slightly different performance; the national regulatory agency must approve the use of any fuel prior to use. Mixed uranium-plutonium fuel could also, in principle, be used in heavy-water reactors or gas-cooled reactors, but there is little or no experience in doing so.
The high neutron efficiency of the heavy-water reactor opens the possibility of a different type of fuel reuse, namely light-water fuel. Used light-water reactor fuel has about the same U-235 enrichment as natural uranium although there are various differences with natural uranium such as the presence of plutonium and neutron-absorbing U-236 in used fuel. This concept is called direct use of spent light-water reactor plutonium in CANDUs (DUPIC). The used fuel is not chemically separated, but inserted in new fuel tubes and placed in a CANDU heavy-water reactor. Variations exist in which the used light-water fuel is either baked to release some of the fission products, or fully chemically separated. Researchers in South Korea and Canada are exploring the DUPIC concept, but it remains far from the stage of practical implementation.
The Nuclear Energy Option in Alberta, October 1, 2008 53
Low-level Waste Management
In Canada, waste is classified as either high level (such as used nuclear fuel) or low level. All nuclear countries make the same distinction while some also define an intermediate waste category.
―Low-level radioactive waste (LLRW) arises from the activities associated with nuclear electricity generation, from nuclear research and development, and from the production and use of radioisotopes in medicine, education, research, agriculture and industry. Examples of LLRW are contaminated materials, rags and protective clothing. … Owners or producers of ongoing waste are responsible for its management (CNSC, web).‖
Canada has 11 waste management facilities (CNSC, web), 1 at the former Whiteshell Laboratories in Manitoba, 1 in New Brunswick for its nuclear power plant, 2 in Quebec, and 7 in Ontario. Low-level waste from a nuclear reactor in Alberta would either have to be shipped to one of those facilities or sent to a new facility constructed in Alberta. Low-level waste is buried near the earth’s surface.
Regulation of low-level waste in Canada involves the Canadian Nuclear Safety Commission that licenses the facilities, the facility owner who is responsible for the facilities themselves (CNSC, web), and the LLRWMO that sets national policy on low-level waste and addresses low-level waste that is the responsibility of the federal government. The LLRWMO was established in 1982 to carry out the responsibilities of the federal government for the management of low-level radioactive waste in Canada. The Office is operated by Atomic Energy of Canada Limited through a cost-recovery agreement with Natural Resources Canada, the federal department that provides the funding and establishes national policy for LLRW management (LLRWMO, web).
High-level Waste Management
There is an international consensus that the proper disposition of high-level waste and used nuclear fuel from operation of nuclear power plants requires use of geological repositories, places in which such waste can be isolated for geological time periods such as 100,000–1,000,000 years. The quantity and duration of isolation from the environment can be improved by recycling usable materials from used nuclear fuel before the residual high-level waste materials are sent to the repository.
No nation yet operates a geological repository for used commercial nuclear power plant fuel. The U.S. does operate the Waste Isolation Pilot Project, which is a geological repository for non- commercial nuclear wastes.
Canada has established the Nuclear Waste Management Organization (NWMO) to determine the appropriate approach for used nuclear fuel. The Nuclear Fuel Waste Act ―required electricity generating companies which produce used nuclear fuel to establish a waste management organization to provide recommendations to the Government of Canada on the long-term management of used nuclear fuel. The legislation also required the nuclear fuel waste owners to establish segregated trust funds to finance the long term management of the used fuel. These funds were established in 2002. Contributions are made annually by the waste owners and audited financial statements are posted on the NWMO website (NWMO, web).‖
The Nuclear Energy Option in Alberta, October 1, 2008 54
―The Nuclear Waste Management Organization (NWMO) was established in 2002 by Ontario Power Generation Inc., Hydro-Québec and New Brunswick Power Corporation in accordance with the Nuclear Fuel Waste Act (NFWA) to assume responsibility for the long-term management of Canada’s used nuclear fuel. On June 14, 2007, the Government of Canada selected the NWMO's recommendation for Adaptive Phased Management (APM). APM moves towards a goal that Canadians themselves identified: safe and secure long-term containment and isolation of used nuclear fuel produced in Canada, with flexibility for future generations to act in their own best interests. The NWMO now has the mandate to implement the recommendation (NWMO, web).‖
The Canadian high-level waste program has focused on heavy-water reactor fuel from its nuclear power plants (NWMO, 2005). The only other used fuel in Canada comes from small test and university reactors such as Chalk River Laboratories in Ontario, Whiteshell Laboratories in Manitoba, Dalhousie University in Nova Scotia, and the University of Alberta. Any new type of reactor in Canada would therefore presumably require an alteration of the federal program to include its fuel types. In addition, the owner of a plant in Alberta would have to join the Nuclear Waste Management Organization.
The Nuclear Energy Option in Alberta, October 1, 2008 55 References
Canada, web Foreign Affairs and International Trade Canada (n.d.). Fissile Material Cut-off Treaty. Website http://www.international.gc.ca/arms-armes/nuclear- nucleaire/fmct.aspx?lang=eng accessed August 18, 2008.
CNSC, web Canadian Nuclear Safety Commission (n.d.). Radioactive Waste and Waste Management Facilities. Website http://www.nuclearsafety.gc.ca/eng/about/ regulated/radioactivewaste/index.cfm accessed August 18, 2008.
IAEA, 2008 International Atomic Energy Agency (2008). Uranium resources sufficient to meet projected nuclear energy requirements long into the future. Press release, 3 June, 2008.
LLRWMO, web Low-Level Radioactive Waste Management Office (n.d.). Website http://www.llrwmo.org, accessed August 18, 2008.
LLRWMO, 2004 Low-Level Radioactive Waste Management Office (2004). Inventory of Radioactive Waste in Canada. LLRWMO-01613-041-10001. Retrieved from http://www.llrwmo.org/en/programs/ongoing/Inventory_Report_2004.pdf
NEPDG, 2001 National Energy Policy Development Group (2001). National Energy Policy— A Report of the National Energy Policy Development Group.
NWMO, web Nuclear Waste Management Organization (n.d.). Website http://www.nwmo.ca accessed August 18, 2008.
NWMO, 2005 Nuclear Waste Management Organization (2005). Choosing a Way Forward— The Future Management of Canada’s Used Nuclear Fuel, Final Study. Retrieved August 2008 from http://www.nwmo.ca/Default.aspx?DN= c7d71751-955a-42b0-897f-8f2a286aa71f
Rouben, 2003 Rouben, B. (2003). CANDU Fuel Management. Presentation at McMaster University, November 10, 2003. Retrieved August 2008 from http://www.nuceng.ca/ep4d3/guests/rouben2003.pdf
WISE, 2008 World Information Service on Energy Uranium Project (2008). World Nuclear Fuel Facilities. Last updated May 14, 2008. Website http://www.wise- uranium.org/efac.html accessed August 2008.
The Nuclear Energy Option in Alberta, October 1, 2008 56 CHAPTER 7: SAFETY AND SECURITY
Summary
This chapter describes the regulatory and technical approaches to nuclear safety and security of nuclear power plants, starting with three levels of levels of supervision and control (national, international, and provincial) and then moving into technical matters.
The safety of nuclear plants is a known major area of public concern. The industry and its regulators recognize this, and in the last three decades have moved toward greater interactions among all levels of government (including international agreements), better analysis of and response to safety issues by designers, and much greater attention to preventing the use of nuclear power systems or products for weapons production.
The key findings are as follows:
If a nuclear power plant is built in Alberta, the province would establish nuclear power relationships with the Canadian Environmental Assessment Agency, and with other provinces with nuclear technology or waste.23 Regulation of nuclear plant safety is a federal responsibility given to the Canadian Nuclear Safety Commission. ―Technology evolves in response to the failings of existing technology (Petroski, 1995).‖ Past nuclear technology failures have been well publicized and well analyzed; reactor designs and operation have been improved and information is now shared more quickly and more widely. Safety and security have become increasingly internationalized, without loss of national sovereignty. The international market is inducing reactor vendors to seek regulatory approval in multiple countries as a competitive advantage. The International Atomic Energy Agency has a set of standards and guides that continue to grow and improve. Canada participates in a new international regulatory initiative for regulators to collaborate in regulating new reactor designs. Non-proliferation safeguards and physical security are recognized concerns. Canada’s obligations grant International Atomic Energy Agency access to nuclear facilities across the country.
Supervision and Control Levels
There are generally at least three levels of government that may be involved with the safety and security of nuclear power plants: national, international, and provincial. The primary level is national; all countries with nuclear power plants, including Canada, have national regulatory agencies with the power to license and regulate plants. The Nuclear Safety and Control Act gives authority to the Canadian Nuclear Safety Commission regarding both the safety and non-proliferation of nuclear weapons (NSCA, 1997). All civilian nuclear facilities are covered, including nuclear power plants,
23 New Brunswick, Ontario, and Quebec have commercial nuclear power plants. Alberta, Nova Scotia, Ontario, Quebec, and Saskatchewan have research reactors. Saskatchewan has uranium mines and mills. Used fuel awaiting permanent disposition resides in Manitoba, New Brunswick, Ontario, and Quebec.
The Nuclear Energy Option in Alberta, October 1, 2008 57 uranium mines, products made from nuclear materials, recycling of used nuclear fuel, and waste management facilities. Many nuclear waste issues such as siting are addressed by other federal agencies as described in Chapter 6. The Commission consists of up to seven members appointed by the Governor in Council.
Canada’s national authorizing legislation acknowledges international obligations. The Canadian Nuclear Safety Commission is charged ―to provide for the limitation, to a reasonable level and in a manner that is consistent with Canada’s international obligations, of the risks to national security, the health and the safety of persons and the environment that are associated with the development, production and use of nuclear energy …‖ (NSCA, 1997, Section 3. Purpose). Not all countries explicitly note international obligations in the authorization of their national agency. Canada is a member of the International Atomic Energy Agency, as are all countries known to have nuclear technologies except for India, Israel, and Pakistan.24 In addition to signing the Nuclear Non- Proliferation Treaty (IAEA NPT, 1970), Canada was one of the first countries to sign the Additional Protocol to the Non-Proliferation Treaty (IAEA AP, 1997), giving the International Atomic Energy Agency enhanced rights of access to nuclear sites and information on nuclear-related activities.
The Nuclear Safety and Control Act authorizes, but does not require, the Canadian Nuclear Safety Commission to make agreements with provinces. Countries vary to the extent that provinces or states participate in licensing decisions, e.g., it is required in Germany but not in Canada. The more levels of government there are involved, the more opportunities there are for hearing diverse viewpoints but also for more conflicts among different parties. The Canadian Nuclear Safety Commission is required to consult with Aboriginal peoples. Although Canada does not appear to give provinces explicit authority in licensing decisions, provinces can participate via the environmental assessment process.
One of the ways that local and provincial governments can be involved with a nuclear power plant is in off-site emergency planning. ―To assure effective interfaces between facility personnel and external stakeholders in such emergencies, the facility emergency plan and any regional, provincial, and national emergency preparedness and response plans and programs dealing with any off-site implications of facility emergencies must be suitably compatible (CNSC, 2001).‖ Conflicts between local/state and federal regulatory authority associated with off-site emergency planning continues to be an issue in the U.S.; it is unknown to what extent this problem has occurred in Canada. Provinces have primary jurisdiction for emergency planning.
Reactor Safety Approaches
All nuclear power plants must provide several fundamental and complementary safety functions throughout the plant’s life, from initial loading of nuclear fuel until final decommissioning of the site. These functions include power control, power shutdown, heat removal, radioactivity containment, and protection against external events. Assurance of these safety functions begins with the power plant design and the selection of the plant location.
24 North Korea and Iran have signed the Nuclear Non-Proliferation Treaty but are in varying degrees of dispute with the International Atomic Energy Agency.
The Nuclear Energy Option in Alberta, October 1, 2008 58
Safety Function: Power Control
Whether nuclear or not, a power plant normally produces a large amount of heat that is used to make steam and thus generate electricity. The power plant is designed to handle this power generation rate; prevention of damage requires the power level to stay below some limit. This is a major objective in the safety design of nuclear power systems. In fossil-fuelled power plants, the power level is controlled by the feed rate of the fuel, the composition of the fuel (which impacts its heating value), the feed rate of oxygen, and/or temperature as chemical combustion rates are a known function of temperature. The power level in a nuclear power plant is controlled by variables analogous to each of these.
A nuclear power plant is provided with a fixed and accurately measured amount of fuel at each refuelling. Unlike a fossil plant, however, there is sufficient fuel present in the plant to run typically for a year without additional refuelling when batch refuelling (such as a light-water reactor) is used. Less fuel is present when online refuelling (such as in a heavy-water reactor) is used. Therefore, fuel availability by itself does not control nuclear power levels.
The fuel purity is also very well known because it is key to operation of the reactor. Two important purity parameters are uranium enrichment and neutron absorption. About 90% of the power plants in the world use uranium enriched in U-235, typically 3%–5%. Unenriched uranium can be used in nuclear plants that use heavy water.
The supply of neutrons in nuclear power plants is perhaps analogous to the supply of oxygen in fossil fuel plants. As the nuclear fuel is consumed, the neutron population needs to be increased slightly to maintain a constant power output. This is accomplished in several ways. The most common is by slowly moving control rods further out of the reactor. These contain materials that absorb neutrons, and removing them causes less neutron absorption. A second way is by the automatic consumption of burnable poisons that are placed in or near the nuclear fuel. These materials also absorb neutrons but automatically disappear via nuclear reactions as the reactor operates.
The importance of control rod operation and designing for only small potential power increases was underscored in a 1961 nuclear accident that occurred at a small military test reactor, the Stationary Low Power Reactor Number One, more commonly referred to as SL-1 (Stacy, 2000). The reactor’s control and safety rods were controlled manually. The control rods were suddenly withdrawn from the reactor when it was shut down for maintenance, causing a rapid power increase that in turn caused a steam explosion. Three operators were killed, but there were no off-site consequences. Lessons learned from this accident include the need to design reactors to limit the maximum rate of control rod withdrawal physically and to reduce the sensitivity of nuclear power output to control rod movement.
Nuclear power plants cannot explode like a bomb. The same physics explains why Chernobyl- type accidents cannot happen with other reactor designs. In reactors, the rate of fission depends on such parameters as the density of fuel and the density of moderating materials that slow neutrons down from their high neutron energies when created by fission to the lower neutron energies at which most fission occurs. The major moderating materials are light water, heavy water, and graphite. As power increases, reactor temperatures increase and thus coolant density decreases—sometimes dramatically as in water boiling to steam—thus reducing the moderation of neutrons and hence their ability to cause more fissions. Therefore, if the reactor tries to overheat, it produces less and less power without any measures or operator action required. This negative power feedback prevents the
The Nuclear Energy Option in Alberta, October 1, 2008 59 system from overheating and experiencing damage. In contrast, a positive power feedback would mean a system with a tendency to go to even higher power in response to an initial slight increase in power.
As required by regulatory authorities everywhere except the former Soviet Union, all properly designed reactors always maintain negative or near-neutral power feedback with regard to the combined effects of power, temperature, coolant density, boiling, and moderation. If for some reason an increase in power has large positive feedback, i.e., causes an increase in the fission rate, the reactor can quickly become uncontrollable. How quickly this occurs depends on yet other parameters such as the average prompt neutron lifetime (generation time).
In light-water reactors, the average prompt neutron lifetime (generation time) is so short that power feedback must always be significantly negative. Safety analyses are simpler if the feedback for each individual effect such as temperature is negative, but the result is acceptable if the combined effects to power feedback are negative, even if one of them is positive. The combined effect is what would happen in the reactor overall, as opposed to the individual effects that are calculated one at a time.
In heavy-water reactors, the average prompt neutron lifetime (generation time) is longer so that the reactor can be controllable even if the power feedback is slightly positive. To compensate for a slightly positive power feedback, regulators require two active shutdown systems.
A positive power feedback occurred at the Chernobyl-4 power plant, which was of the RBMK design,25 water cooled and graphite moderated. While conducting a test (ironically a safety test), the operators withdrew more control rods than allowed by safety regulations. A design flaw then became clear; the operators had inadvertently put the reactor into a condition that led to positive feedback. The power level increased rapidly, causing a steam explosion, and destroying the reactor. The lack of a containment structure around the reactor allowed large amounts of radioactivity to escape. More information on this accident can be found in Appendix B.
Safety Function: Power Shutdown
As part of an efficient design, as much of the reactor’s heat as possible is used to make steam, which then turns a turbine to make electricity. The laws of thermodynamics mean that much of the heat, generally a majority, is rejected to the environment at low temperature. This is also true of fossil-fired power plants, and is the purpose of the large cooling towers emitting clouds of condensed moisture that have become the media symbol of nuclear plants. If the normal cooling methods that transfer the plant heat to steam and to the environment fail to carry their normal heat loads, the power plant must be shut down to prevent damage from overheating. Nuclear power plants have high capital cost, and damage is expensive to repair. Furthermore, damage raises the prospect of release of radioactivity to the environment. Therefore, all regulatory agencies ensure that design and operation of nuclear power plants have reliable methods of detecting loss of cooling and automatically shutting down the plant. These are in addition to the operators’ ability to use the normal control systems to call for reduced power from the system.
One of the typical methods of assuring control of a nuclear power plant involves the use of safety rods made of materials that readily absorb neutrons. These can fit into vertical openings in the
25 RBMK is a Russian acronym for reaktor bolshoy moshchnosti kanalniy, which means ―reactor (of) high power (of the) channel (type).‖ This design has not been used outside the former Soviet Union and Eastern Europe.
The Nuclear Energy Option in Alberta, October 1, 2008 60 reactor and are held at the top by small electromagnets. Normally, these rods are held outside the active part of their reactor where heat is generated. If the electricity to the plant is lost or the operator (either human or computer) turns off power to the electromagnets, the safety rods drop into the core by the simple force of gravity and reduce its power output by absorbing the fission-causing neutrons.
All nuclear power plants also have multiple active safety systems that monitor conditions and reduce power when required. Operator action is not required, but electric power is.
Some reactor types have inherent power shutdown mechanisms that require no operator action, electric power, or any monitoring of the system. The negative temperature feedback mechanism described above works particularly well for metal nuclear fuel as its thermal expansion is higher than other fuels, which are generally ceramic. In one test reactor, the Experimental Breeder Reactor II, it was shown experimentally that the reactor could shut itself down safely when the liquid sodium coolant flow was stopped while the reactor was at full power, without operator intervention or emergency systems of any type (Stacy, 2000). However, metal fuel has other disadvantages if oxygen is present or if very high temperatures are required.
Safety Function: Heat Removal
When a nuclear power plant is shut down, the heat production in the reactor does not fall to zero. The radioactive materials that accumulate during operation continue to decay, producing heat. The fraction of heat at shutdown relative to the operating power level depends primarily on the amount of power generated before shutdown and the length of time it operated at that level. Typical values range from less than 1% to several percent. This residual decay heat decreases rapidly after shutdown.
If normal cooling systems are working, such decay heat is not an issue. The issue arises from accidents involving loss of heat sink (such as loss of coolant water in the steam generator), loss of coolant (such as from coolant leaks), loss of coolant flow (pump failures or flow blockages), or loss of electric power to the pumps. In any of these situations, the loss of cooling means that the small amount of decay heat can still cause the reactor core to reach abnormally high temperatures, possibly above the design conditions.
The temperature increase depends on a number of design factors. Because the thermal efficiency of the plant is proportional to the operational temperature, designers select the highest safe operational temperature. However, this reduces the margin for abnormal temperature increases, which must still be considered in the design. The heat capacity (ability to absorb energy without getting much hotter) of the materials in the reactor is not easily changed. Therefore, to minimize the impact of loss of cooling, designers can do one or more of the following: increase alternative heat removal to the ultimate heat sink, increase solid mass in the reactor so more material absorbs the released energy, and/or increase the tolerable maximum accident temperature.
All current nuclear power plants provide for heat removal in case of an accident by one or more types of emergency coolant systems, ensuring that the heat removal is adequate to limit accident temperatures. The details of such systems depend primarily on the type of coolant.
Water as a coolant is most effective in liquid form. The water is typically stored above the reactor so that it can flow without pumps into the coolant system whenever the coolant system pressure is lower than the pressure in the storage tank. Later in the accident, if needed, water can be pumped from the bottom of the containment building back into the reactor coolant system.
The Nuclear Energy Option in Alberta, October 1, 2008 61
Advanced water-cooled reactors are designed so that the emergency coolant systems are simpler with minimal dependence on active systems that require electricity. Some concepts are totally passive, meaning that the natural circulation of the coolant and the heat conduction from the system are adequate to control the maximum temperature. Operator intervention, electricity, or active systems are not required.
Gas-cooled nuclear power plant systems do not have the complication of the phase change of water to steam. There is a greater mass of moderator in the reactor, and it is solid graphite that cannot leak. The tolerable accident temperatures of these reactors are typically higher because of the material properties of the fuel. Therefore, natural circulation is an accident option in many gas-cooled designs.
Perhaps the most famous accident in which the cooling function was lost was Three Mile Island (Walker, 2004). This event started in the secondary, non-nuclear, part of the plant when the flow of feed water to the steam generators failed. Safety systems operated as designed and the steam turbine and reactor shut down. An automatic pressure release valve in the main reactor coolant system opened as designed but failed to close when the system pressure dropped sufficiently. Thus, cooling water continued to leave the system through the relief valve causing the reactor to overheat. The operators misdiagnosed the system, in part because there was no instrument that showed the level of water remaining in the system. Their subsequent actions made the problem worse by further reducing the water available to remove the decay heat. Later it was realized that about half of the fuel in the reactor core had melted.
An extensive investigation of the Three Mile Island unit 2 (TMI-2) led to the following conclusions, among many others.
―Although the TMI-2 plant suffered a severe core meltdown, the most dangerous kind of nuclear power accident, it did not produce the worst-case consequences that reactor experts had long feared. In a worst-case accident, the melting of nuclear fuel would lead to a breach of the walls of the containment building and release massive quantities of radiation to the environment. But this did not occur as a result of the Three Mile Island accident (USNRC, 2004).‖
―In the months following the accident, although questions were raised about possible adverse effects from radiation on human, animal, and plant life in the TMI area, none could be directly correlated to the accident. Thousands of environmental samples of air, water, milk, vegetation, soil, and foodstuffs were collected by various groups monitoring the area. Very low levels of radionuclides could be attributed to releases from the accident. However, comprehensive investigations and assessments by several well- respected organizations have concluded that in spite of serious damage to the reactor, most of the radiation was contained and that the actual release had negligible effects on the physical health of individuals or the environment (USNRC, 2004).‖
The reactor was damaged beyond repair. The operating utility suffered financially and the nuclear power industry learned that prevention of accidents is surely in their financial interest. Many other lessons were also learned, including increased recognition of the role of human operators and maintenance workers (as opposed to just the hardware itself), the need to enhance operating training and control instrumentation, and the importance of emergency preparedness on-site and off-site. This accident led to the establishment of the Institute of Nuclear Power Operations, through which the nuclear industry polices itself and shares information.
The Nuclear Energy Option in Alberta, October 1, 2008 62 Proper coolant performance is vital to the safety of nuclear power plants. However, some early reactors used coolants that could chemically react with other reactor materials, releasing heat. In those cases, it is possible that adding more coolant during an accident can make the event worse, not better. This happened at the Windscale 1 reactor in the UK.
The Windscale 1 military26 reactor (not of commercial design) was air cooled, yet had uranium metal fuel and graphite moderator. In high radiation fields, there is damage to the crystal structure of graphite, which stores energy in the lattice structure in a process similar to compressing a set of springs (Glasstone, 1963). This energy can be undesirably and suddenly released so the graphite damage is periodically removed by annealing, i.e., heating the graphite under controlled conditions to allow the stored lattice energy to dissipate safely. In 1957, the Windscale accident started during graphite annealing (NRPB, 1997; UKAEA web). The operators misdiagnosed the situation in part because the temperature sensors were located at locations of maximum temperature during normal operation, but not at maximum temperature during annealing. This misdiagnosis led to continuation of the annealing by further heating the fuel, which further increased the unmeasured maximum fuel temperatures. Some of the uranium metal fuel containers failed, allowing metallic uranium to react with oxygen in the coolant air, adding more heat (NRPB, 1997). The heat added to the reactor for annealing led to uranium container failure, then uranium fire, and finally a graphite fire (IAEA, 1993). Normally, graphite by itself is very difficult to ignite (IAEA, 1993). The fire was eventually extinguished by flooding the reactor with water and closing air vents to starve the fire of oxygen (NRPB, 1997; IAEA, 1993).
Though the reactor did not have a containment vessel, ―...a filter on the stack managed to restrict the atmospheric discharge, particularly of [radioactive] iodine-131. This, coupled with countermeasures applied at the time, especially the imposition of restrictions on the consumption of cows' milk, meant that the risks to the most exposed individuals and to the population as a whole were small. It is unlikely that any effects could be seen in the population that could be attributed to the Windscale fire (NRPB, 1997).‖ The lessons from this accident are the importance of radioactivity containment and off-site emergency preparation, and the elimination of air as a reactor coolant.
Safety Function: Radioactivity Confinement
The confinement/containment is the last barrier before accidental release of radioactivity. The term confinement is the more general term; the term containment tends to be used only when there is a pressure-tight, always-sealed confinement.
One of the reasons for the differences in off-site consequences between the water-cooled Three Mile Island and the water-cooled Chernobyl accidents is that the former had a pressure-tight radioactivity containment building. The small amount of radioactivity released to the environment at Three Mile Island was via secondary systems, allowing some to bypass the containment. Except for Soviet-era RBMK reactors, all water-cooled commercial nuclear power plants have a pressure-tight steel-reinforced concrete containment building that remains sealed during all accidents. Most nuclear power plants have a separate building encompassing each reactor. CANDU reactors generally combine the containment volume for several reactors (often four in a cluster), so that a large steam release in a reactor building sends pressure into a dedicated vacuum building. This term is used because the air pressure in the building is maintained at about two-thirds of the outside air pressure so that any steam released in an accident can be condensed, and any leakage is from the outside into the containment. The main reactor building is slightly below atmospheric pressure, again to prevent
26 The key distinction is that the reactor was not of a commercial design. It was used to produce plutonium.
The Nuclear Energy Option in Alberta, October 1, 2008 63 leakage. To minimize pressurization of the containment and the possibility of outward leakage, the containments at many water-cooled plants have provision to condense steam upon water/steam escape into the containment.
All gas-cooled nuclear power plants have a radioactivity confinement. Because these reactors do not use water as a coolant, a leak cannot flash to steam to pressurize the containment, and steam condensation is not relevant to minimizing building pressurization. However, the gas coolant is normally at high pressure and its leakage will pressurize the building. Therefore, gas-cooled reactor buildings vary from filtered vented radiation confinement to pressure-tight containment. Fortunately, the escape of radioactivity from a reactor is generally only possible only after cooling is lost; the exception is if one allows an uncontrolled power increase as at Chernobyl. Therefore, the strategy of handling a large gas leak can be to vent the pressure initially, then to seal the confinement/containment as the reactor heats but before significant radioactivity can escape. This does not necessarily require active safety systems, electricity, or operator action.
The small–medium-sized innovative reactors appear headed toward sealed pressure-tight containments. Some of the designs have no way to generate internal pressures, making design of pressure-tight containers easier.
Safety Function: Protection Against External Events
Any facility containing hazards must be protected against events that occur outside the facility, including earthquakes, tornados, hurricanes, floods, and aircraft impact.
The first step in providing protection is the judicious selection of the location of the nuclear power plant, away from as many of these hazards as possible. The initial site selection can minimize earthquake potential by staying away from known faults and minimize the risk of aircraft crashes by staying away from airports.
The second step is deciding what residual risks at the selected location must be counteracted. For example, the issue is not whether a reactor is designed for protection against accidental aircraft impact, but rather what aircraft, of what size, and at what speed is considered a credible risk for a given power plant location. Similarly, the issue is not whether to design against high winds, but how high a wind speed the design must withstand. Another class of external event includes deliberate aircraft impact and bombs. The details on such terrorist-related design-basis events are not always made public, but they are handled in the same way. The selection of all residual risks must be acceptable to the federal regulator.
Third, engineers design against those risks using standard mechanical and structural engineering techniques. Safety features in the plant design generally include the confinement/containment and an exclusion zone around the reactor from which the public and routine traffic (automobile and sometimes aircraft) is prohibited.
The fourth step of assuring safety is the review and regulatory approval of the design including the safety features, and of the subsequent construction.
The Nuclear Energy Option in Alberta, October 1, 2008 64 Internationalization of Reactor Safety Approaches
The safety of nuclear power plants is now a global enterprise because of international collaboration, data sharing, consultation, and the emergence of international markets. Reactors from Canada, France, Japan, and the U.S. are marketed around the world. As in other industries, there are international consortia. Information is shared through a variety of channels: informally, by user groups (those with a reactor type or part in common), regulator-to-regulator, the Nuclear Energy Agency (NEA) of the Organisation for Economic Cooperation and Development (OECD), the World Association of Nuclear Operators (WANO), and the International Atomic Energy Agency (IAEA). Common elements include consideration of likelihood of event occurrence, continuing dependence on prescriptive regulatory elements, defence in depth, and the as-low-as-reasonably-achievable (ALARA) principle for the reduction of radiation doses.
Although the terminology varies, the regulatory schemes and international practice recognize that events vary in their likelihood of occurrence (IAEA, 2000). In Canada, events are categorized based on probability studies and engineering judgment as follows (CNSC, 2008):
anticipated operational occurrences; frequency equal or greater than 0.01 per year (equivalent to once every 100 years). design basis accidents; frequency equal or greater than 10 per million years. beyond design basis accidents; frequency less than 10 per million years.
Such an approach does not mean that any particular type of event is ignored or downplayed. Rather, it is helpful to recognize that proper design, construction, maintenance, and operation must guard against the full range of possibilities. Even in the absence of large events, a chronic lack of sufficient safety, training, and experience can lead to small releases of radioactivity to the environment or elevated radiation dose rates to workers. These are damaging to health, to economics, and to public trust, and can be harbingers of bigger events to come.
It is emphasized that no country regulates strictly on the basis of probability estimates and classifications. There are always various prescriptive requirements. For example, ―Canadian practice requires that each accident be analyzed assuming complete failure of one shutdown system, no matter how low the frequency. The reason goes back to 1952, when the core of the National Research eXperimental (NRX) reactor in Chalk River, Ontario, was damaged in an accident (Snell, 2006).‖
―In 1952, a loss-of-regulation accident occurred at the Chalk River NRX research reactor. Following the accident, an in-depth assessment of safety shutdown was performed. The single most important technical lesson was that a reactor should always have a fast shutdown capacity available and that this capacity should be independent of any control system (AECB, 1998).‖
All countries follow the guiding principle of defence in depth (IAEA, 1996), which means that no system should depend on only one design feature or on one operator action to protect against bad consequences. The designer must assume equipment will fail, must include alternative ways of addressing the problem, must assume operators will do the wrong thing, and then provide subsequent additional protective features. Another common principle that all countries recognize is ALARA, keeping radiation exposures as low as reasonably achievable (IAEA, 1996a).
The international similarities in safety approaches, guidelines, and regulations (IAEA, 1996a, 2006) tend to mean that a reactor design acceptable in one country is (or can be made to be) acceptable in another. However, this is not always a simple process. Prescriptive regulations such as
The Nuclear Energy Option in Alberta, October 1, 2008 65 the Canadian shutdown rule noted above can require significant design modifications as a reactor design is introduced into each country.
Indeed, national regulators have launched the Multinational Design Evaluation Program to ―exchange worldwide nuclear regulatory knowledge and experience in a cooperative effort to establish common regulatory standards for new reactor design, to identify diverse regulatory perspectives, and to share resources in completing the necessary regulatory reviews (Lyons, 2008).‖ This international effort is supported by the NEA of the OECD. Ten countries are participating, including Canada (NEA, 2006, 2008).
Summary of Reactor Safety Approaches
Table 7-1 summarizes reactor safety approaches. Unlike the analogous tables in Chapters 4 and 6, the table in this chapter classifies reactor types by coolant as that is the dominant determinant of the reactor safety approach. The next most important determinant is current water-cooled designs versus advanced innovative water-cooled designs that have more emphasis on passive safety features. As with any other technology, innovation works two ways with regard to safety. There is more experience with existing or older technology; lessons have been learned. New technology offers improved performance, such as less dependence on active safety systems or electricity, but with less or no operating experience.
Table 7-1. Safety comparison of different coolant approaches Current water- Advanced Category Helium-cooled Other cooled water-cooled Size large varies small–medium small pressurized light water Type pressurized heavy water helium battery-type boiling light water Need for electric power in severe required not required not required not required accident management Safety function: inherent feedback mechanisms that create power stability against power control temperature increase, boiling in the core, etc. Safety function: diverse and redundant methods to shut down power when needed power shutdown Safety function: heat emergency natural natural natural circulation removal if normal cooling system circulation circulation and convection cooling lost Safety function: pressure-tight concrete steel- approach to handle reinforced containment building, pressure-tight or low pressure pressurization if condensation of steam to reduce vented building coolant escapes pressure Safety function: protection against concrete steel-reinforced containment building, underground external impacts proper siting of power plant structure (aircraft, etc.)
The Nuclear Energy Option in Alberta, October 1, 2008 66 Lessons Learned from Past Reactor Events
Table 7-2 summarizes lessons learned from past reactor events. There are several common elements that are not included in the table, including the following:
Human performance plays a significant, often dominant, role. Improving the performance of operators and maintenance workers is a complex undertaking involving instrumentation, human factors, and sociological/physiological science. Many of the challenges are akin to piloting aircraft, which has been described as long periods of boredom interspersed with a few minutes of panic. Thus, reactor operators and aircraft pilots routinely undergo simulator training to stay fresh in handling abnormal and emergency situations. Coordination and planning for abnormal events is required among plant operators, regulators, local/provincial/national officials, and the news media. Safety-related operating information needs to be prompt, accurate, and correctly interpreted. Radiological confinement/containment provides important protection. Information on equipment performance, operator performance, maintenance, and minor abnormal events must be shared among interested parties.
Table 7-2. Summary of major reactor accidents Accident Location When Consequences Lessons Learned Chalk River, 1952 test reactor damaged safety shutdown must National Research Canada then repaired and always be available and be eXperimental restarted, no off-site (NRX) independent of other consequences systems UK 1957 small but significant provide better radioactivity release to instrumentation; avoid Windscale fire the environment, coolant chemical reactions destroyed the military with fuel and moderator reactor Idaho, U.S. 1961 killed three operators, design plants to control the Stationary Low- destroyed the non- rate of withdrawal of control Power Reactor commercial test reactor, Number One rods; minimize the insignificant off-site excessive reactivity upon (SL-1) consequences control rod movement Pennsylvania, 1979 damaged the reactor events that start in non- U.S. beyond repair, nuclear systems can Three Mile Island, insignificant off-site propagate to nuclear- unit 2 consequences related systems; improper (TMI-2) diagnosis of the situation can lead to actions that worsen it. Ukraine, 1986 56 people have died as prevent uncontrolled power U.S.S.R. a result of the accident. excursions by design; use The Chernobyl Forum radioactivity projects a total of 4000 confinement/containment. deaths may occur over Chernobyl unit 4 time. There is long-term evacuation and relocation of population, and power plant was destroyed (Chernobyl, 2005).
The Nuclear Energy Option in Alberta, October 1, 2008 67
Physical Security
All countries with nuclear power plants have strict requirements for the physical protection of such plants and transportation of all radioactive materials. These risks are perceived by the public as high, but there has never been any release of radioactivity from plants due to a lapse of physical security (e.g., internal sabotage or external assault) or during transportation.
Plant containments are extremely robust and are designed against those threats deemed appropriate by national regulatory authorities. Similarly, transportation casks for used nuclear fuel and other highly radioactive materials are very rugged, designed and tested against severe accidental and deliberate assaults. Note that fresh nuclear fuel is only slightly radioactive (it is generally handled manually) and is not a proliferation threat.
Some have observed that the transportation risk of energy sources may be dominated by the mass of material transported and/or the number of shipments. Rail and truck accidents do happen. In this regard, nuclear has an advantage over fossil fuel as the mass of nuclear fuel to be transported is more than 100,000 times lower. Thus, the potential risk of common industrial accidents, which is proportional to the number of shipments, will be higher for fossil than for nuclear. Of course, shipments of used nuclear fuel involve material that is orders of magnitude more hazardous (per mass) than coal and therefore pose potential risk beyond that of common industrial transportation accidents. Transport of nuclear material has not harmed the public. Used nuclear fuel will not be shipped in Canada until either a final disposition site is identified or a centralized interim storage location established.
In general, anti-terrorist, counter-intelligence, and police activities are outside the scope of this report. Publicly available information is often limited in scope and detail. However, nuclear power plants themselves can maintain a substantial security force.
Other Risks
This chapter has only covered nuclear-related accidents at nuclear power plants. Other safety risks exist. First are non-nuclear risks at nuclear power plants. Such plants are large industrial facilities. Plant personnel must guard against a wide range of industrial facility hazards such as electricity and steam. During major construction, equipment replacement, or decommissioning, additional hazards exist from overhead loads, equipment movement, etc.
Beyond the nuclear power plant, there are risks in the other parts of the nuclear fuel cycle mentioned in Chapter 6: uranium mining and milling, uranium enrichment (if used), fuel fabrication, and waste processing and storage. Like other industries, each of these steps entails risks to workers, the public, and the environment. Examples include construction accidents, breaks in steam lines, and vehicle accidents. Discussion of such risks is beyond the scope of this document.
The Nuclear Energy Option in Alberta, October 1, 2008 68 References
AECB, 1998 Atomic Energy Control Board (1998). Canadian National Report for the Convention on Nuclear Safety, Retrieved August 2008 from http://www.suretenucleaire.gc.ca/pubs_catalogue/ uploads/i690e.pdf
Chernobyl, 2005 The Chernobyl Forum (2005). Chernobyl’s Legacy: Health, Environmental and Socio-economic Impacts and Recommendations to the Governments of Belarus, the Russian Federation and Ukraine. International Atomic Energy Agency.
CNSC, 2001 Canadian Nuclear Safety Commission (2001). Emergency Planning at Class I Nuclear Facilities and Uranium Mines and Mills (2001). Regulatory Guide G- 225.
CNSC, 2008 Canadian Nuclear Safety Commission (2008). Safety Analysis for Nuclear Power Plants. Regulatory Document RD-310.
Glasstone, 1963 Glasstone, S. & Sesonske, A. (1963). Nuclear Reactor Engineering, D. Van Nostrand Company, Inc., Princeton New Jersey, USA, 420.
IAEA, 1993 International Atomic Energy Agency (1993). Response of fuel, fuel elements and gas cooled reactor cores under accidental air or water ingress conditions. Summary of the Technical Committee Meeting, Proceedings of a Technical Committee meeting held in Beijing, China, 24–27 October 1993. IAEA TECDOC-784.
IAEA, 1996 International Atomic Energy Agency (1996). Defence in Depth in Nuclear Safety, A report by the International Nuclear Safety Advisory Group. Retrieved August 2008 from http://www-pub.iaea.org/MTCD/publications/PDF/ Pub1013e_web.pdf
IAEA, 1996a International Atomic Energy Agency et al. (1996). International Basic Safety Standards for Protection against Ionizing Radiation and for the Safety of Radiation Sources. Retrieved August 2008 from http://www- pub.iaea.org/MTCD/publications/PDF/SS-115-Web/Pub996_web-1a.pdf
IAEA, 2000 International Atomic Energy Agency (2000). Safety of Nuclear Power Plants: Design Requirements. No. NS-R-1.
IAEA, 2006 International Atomic Energy Agency (2006). Fundamental Safety Principles: Safety Fundamentals. No. SF-1, 2006.
IAEA AP, 1997 International Atomic Energy Agency (1997). Model Protocol Additional to the Agreement(s) Between State(s) and the International Atomic Energy Agency for the Application of Safeguards, International Atomic Energy Information Circular 540. Retrieved August 2008 from http://www.iaea.org/Publications/ Documents/Infcircs/1997/infcirc540c.pdf
IAEA NPT, 1970 International Atomic Energy Agency (1970). Treaty on the Non-Proliferation of Nuclear Weapons, International Atomic Energy Agency Information
The Nuclear Energy Option in Alberta, October 1, 2008 69 Circular 140, Retrieved August 2008 from http://www.iaea.org/Publications/ Documents/Treaties/npt.html
Lyons, 2008 Lyons, P.B (2008). International Regulatory Cooperation Supporting Safety and Security—Meeting Future Challenges. Speech at the Japan Atomic Industrial Forum, Tokyo Japan, April 16, 2008. Retrieved August 2008 from http://www.nrc.gov/reading-rm/doc-collections/commission/speeches/2008/s- 08-017.html
NEA, 2006 Nuclear Energy Agency (2006). NEA provides support for new stage of nuclear safety initiative. Press communiqué, Paris, 9 November 2006. Retrieved August 2008 from http://www.nea.fr/html/general/press/2006/2006- 05.html
NEA, 2008 Nuclear Energy Agency (2008). Nuclear safety initiative enters new phase, Press communiqué, Paris, 7 March 2008. Retrieved August 2008 from http://www.nea.fr/html/general/press/2008/2008-01.html
NRPB, 1997 National Radiological Protection Board (1997). Radiological Consequences of the 1957 Windscale Fire. Retrieved August 2008 from http://karws.gso.uri.edu/Marsh/Newsgroups/Wscal-is.htm
NSCA, 1997 Government of Canada (1997). Nuclear Safety and Control Act (1997, c. 9 N- 28-3, assented to March 20th, 1997), retrieved August 11, 2008 from http://laws.justice.gc.ca/en/N-28.3/index.html
Petroski, 1995 Petroski, H. (1995). Learning from Paper Clips, American Scientist, volume 83, number 4, July-August 1995, 313.
Snell, 2006 Snell, V. (2006). McMaster University and University Network of Excellence in Nuclear Engineering, course UN0803, Nuclear Reactor Safety Design (2006 Version). Chapter 2 Design Basis Accidents, January 2006. Retrieved August 2008 from http://www.unene.ca/un803
Stacy, 2000 Stacy, S.M. (2000). Proving the Principle, A History of The Idaho National Engineering and Environmental Laboratory, 1949-1999. United States Government Printing, first edition, October 6, 2000.
UKAEA, web United Kingdom Atomic Energy Agency (n.d.). The Windscale Pile Reactors. Retrieved August 13, 2008 from http://www.ukaea.org.uk/downloads/ windscale/pileaw.pdf
USNRC, 2004 U.S. Nuclear Regulatory Commission (2004). Three Mile Island Accident. Retrieved August 2008 from http://www.nrc.gov/reading-rm/doc- collections/fact-sheets/3mile-isle.pdf
Walker, 2004 Walker, J.S. (2004). Three Mile Island—A Nuclear Crisis in Historical Perspective. University of California Press, Berkeley, 2004.
The Nuclear Energy Option in Alberta, October 1, 2008 70 CHAPTER 8: WATER USAGE AND SOURCING
Summary
Several aspects of water usage need to be considered for nuclear power generation. The primary usage of water in a nuclear reactor is for cooling systems. Most reactors use a closed water system as the primary means to transfer heat from the fuel to steam turbines to generate electricity. The major use of water is for heat rejection to the environment through transfer to a water body or the atmosphere. There are several options for heat rejection, each of which has different scales of water requirements.
The largest consumptive uses of water in Alberta are agricultural, thermal power, municipal, industrial, and enhanced oil recovery (oilfield injection). The majority of allocation is for surface water with only 3% coming from groundwater. Alberta has unevenly distributed fresh water resources and, based on the current and potential water-short areas, it is likely that the northern portion of the province would have the best access to surface water sources. The south-eastern portion of the province is closed to new water allocation applications and is an area where water shortages are likely. Groundwater is the only water source for approximately one quarter of all Albertans, but the resources are not as well defined as surface water. Groundwater assessments are contained in county reports and the Alberta Geological Survey is currently compiling a digital version of groundwater yield maps for the entire province showing potential groundwater yields.
It is likely that water supplies will decline in the province over the next 25 years. Although moratoriums may help alleviate some of the stress on the province’s water supply, water demand is also increasing due to population growth, expansion of the oil sands-related activities and larger extractions by irrigators to their maximum allocations. Climate change is likely to result in an overall decline in recharge to the surface water and groundwater supplies, and may also exacerbate future droughts.
Alberta Environment is the regulatory body in Alberta that grants water diversion licences. These may be issued for temporary diversions up to a maximum of one year, or for longer time periods depending upon the project type. All new licences have an expiry date. For a long-term project such as a nuclear plant, the duration of the licence is set during the initial approval process. In Alberta, water has been traditionally allocated on the first-in-time, first-in-right principle for both surface and groundwater. The older the licence, the higher that user is on the priority list. It is clear that the requirements of a potential nuclear water diversion application would have to be assessed in the context of existing licenses, their status, longevity, and potential for reallocation. Water requirements for a nuclear plant must fit within existing supplies, and in some areas, negotiation for transfer of water licences may be required. Alberta’s Water Act provides for the transfer of an allocation of water held under a licence. In areas of Alberta where available water is fully or nearly fully allocated, a transfer system allows accommodation of new or alternative users. A transfer may only occur where an approved water management plan or an order of Cabinet provides for this.
The Nuclear Energy Option in Alberta, October 1, 2008 71 Water Used in Reactor Operation
The use of water at a nuclear power plant during operation is fundamentally no different than at a fossil-fuelled plant. Similarities include the following: water is used in the primary coolant and the steam generator, water is recycled except for heat transfer to the environment, and water brought into the plant is thoroughly cleaned to prevent plant corrosion problems. There are two minor differences. Because current nuclear power plants have slightly lower thermal efficiency than fossil- fuelled plants, they must transfer slightly more heat to the environment and therefore slightly more water is lost (quantified below). Second, a nuclear power plant uses a small amount of water to cool used fuel that has been discharged from the reactor. This amount is small; it is recycled and not released to the environment. The two major uses are the two major coolant systems: the primary coolant and heat rejection to the environment.
The primary coolant removes heat from wherever the fuel is reacting, whether it is uranium, coal, oil, or natural gas, and transfers it to steam turbines to generate electricity. In boiling water reactors, this is mechanically no different than in fossil systems. In pressurized-water reactors, the primary coolant is kept sealed and away from the steam turbines; instead heat is first transferred to a secondary coolant, which then goes to steam turbines. Most nuclear reactors use water as the primary coolant (either boiling or pressurized), although some use gas or liquid metal (see Appendix A).
In a nuclear power plant, all coolant systems are sealed except for the final heat transfer to the environment. There are two modes of heat rejection to the environment: via a body of water or the atmosphere. Heat rejection can be done using a once-through flow of water from bodies of water such as an ocean, river, or lake. Atmospheric heat rejection uses a cooling tower. In a wet cooling tower, water evaporates in the updraft of air drawn into the tower; the heat transfer via evaporation cools the system. In a dry cooling tower, the water remains sealed and heat is transferred only via conduction from water through tube walls to the air. The heat rejection system has no radioactivity except for trace amounts that leak or diffuse from the primary/secondary systems.
Body of water. ―Once-through cooling uses water only once as it passes through a condenser to absorb heat. Intermittently, chlorine is added to control microbes that corrode the piping and diminish the cooling capacity. This heated treated water is then discharged downstream from the intake into a receiving water body (usually, but not always, the original water source). While there is little water consumption with once- through systems, there are severe impacts to aquatic life as a result of water intake (entrainment and impingement) and water discharge (increased water temperature and added chlorine). Once-through cooling is currently the most common technology in use nationwide, representing about 52% of generation (Baum, 2004).‖ Wet cooling tower. ―Closed-cycle, or re-circulating, systems are the most common cooling system in states with limited water supplies. Re-circulating systems, by recycling water, reduce water withdrawals by 90% or more compared to once-through cooling systems. In a typical closed-cycle system, steam comes out of the turbine into a shell and tube condenser. Cold water is run through the tubes of the condenser; the cooling water heats up as the steam condenses back to water. The cooling water reaches the top of a cooling tower where some of it evaporates, forming a plume of steam above the towers. Most of the water does not escape as steam but dribbles back down through material that supports heat transfer, where it is cooled by 10°–12°C and returned to the condenser. … While recirculating systems withdraw much less water than once-through systems, they consume a much greater portion—about 60%-80%—of the withdrawn water. … To reduce deposits and prevent corrosion, at regular intervals some water is discharged
The Nuclear Energy Option in Alberta, October 1, 2008 72 (termed cooling tower blowdown) and fresh water is added that has been treated with chlorine and other chemicals (biocides) to control corrosion, mineral build, up and microbes (Baum, 2004).‖ Dry cooling tower. ―A very small percentage of plants in the country—about 1%—use dry cooling technology, in which air, not water, cools the steam that drives the turbine. The most common type of dry cooling system in use in the U.S.—direct acting—works like an automobile radiator. The steam in tubes is cooled by air blown over the outside of the tubes. The water demands from dry cooling are extremely low. There are no evaporative losses, and water consumption is limited to boiler requirements, including routine cleaning and maintenance (Baum, 2004).‖ Dry cooling towers require a large amount of tube area to transfer heat to the atmosphere, which like all gases, is a relatively poor heat transfer material. They also use fans to blow air over the tubes to increase performance. Both the large area and the fans make dry cooling an expensive option. It is, however, gaining more attention for use in water-limited areas such as Alberta. The performance of dry cooling towers is significantly affected by altitude because of its effect on air density. This is particularly a problem in and near the Rocky Mountains where the air pressure (and therefore density at the same temperature) can be only 75%–90% of that at sea level.
The major differences from one type of power plant to the next are the size and thermal efficiency; the use of water is proportional to the amount of heat rejected to the environment. The average cooling system needs have been estimated by the Electric Power Research Institute (Myhre, 2002) as shown in Table 8-1.
Table 8-1. The annual water use for nominal 800 MW electric power plant (Myhre, 2002) Withdrawal (m3/yr) Consumption (m3/yr) Fuel Source Technology Lower Upper Lower Upper once-through 480,000,000 1,200,000,000 7,000,000 7,000,000 Fossil wet tower 10,000,000 10,000,000 11,000,000 11,000,000 NG combined once-through 180,000,000 500,000,000 2,000,000 2,000,000 cycle wet tower 10,000,000 10,000,000 4,000,000 4,000,000 once-through 600,000,000 1,400,000,000 10,000,000 10,000,000 Nuclear wet tower 20,000,000 30,000,000 17,000,000 17,000,000 Any dry cooling Nil Nil Nil Nil
Provincial Water Supplies in Alberta
Surface Water Origin
Alberta’s fresh water resources (Figure 8-1) include lakes, rivers, groundwater, and wetlands and are significant in their uneven distribution across the province. Temperature and precipitation patterns across the province result in annual moisture deficits in the southern and western plains, and moisture surpluses in the Rocky Mountains, foothills, and in the northern and eastern boreal forest. Annual precipitation varies from less than 300 mm in southeast Alberta to more than 1000 mm at high elevations in the Rocky Mountains. Located in the rain shadow of the Rocky Mountains, the prairies are one of the driest regions of Canada, with potential evaporation exceeding average precipitation in large portions of the southern parts of the province. Rivers and aquifers that originate in the snow and ice fields of the Rocky Mountains have made water available to the interior of the
The Nuclear Energy Option in Alberta, October 1, 2008 73 province (Schindler, 2006). The Rocky Mountains supply about 85% of the annual streamflow to major Alberta rivers through spring snowmelt, glacier melt, and baseflow (Grant, 1974; Mote, 2005). The seven major river basins in the province flow to the Arctic Ocean (87%), Hudson’s Bay (13%), and the Gulf of Mexico (0.1%).
Figure 8-1. Mean annual natural river discharges for Alberta
The Nuclear Energy Option in Alberta, October 1, 2008 74
Groundwater Sources
Groundwater is the source of potable water for 23% of Albertans (Environment, 2004) and is often the source of base flow during summer and winter months. There are groundwater resources in every part of the province; however, aquifer depths, yields, and water quality vary. Aquifers are found in both the unconsolidated units such as the tertiary or quaternary buried valleys and alluvial deposits, and in fractured rock aquifers such as the sandstone or siltstone units of the Western Canadian Sedimentary Basin. Numerous glacier advances and retreats during the Quaternary Age created complex sequences of glaciolacustrine, stratified, and non-stratified deposits that have a significant role in both surface and groundwater flow systems. Groundwater quality varies in these different types of aquifers depending on the geology and amount of interaction between the water and surrounding rock. In general, only groundwater within a few hundred meters of the surface is suitable for domestic consumption. Water quality changes with depth with increasing concentrations of dissolved minerals. The base of the fresh groundwater zone has been approximated for the province and is dependent on geology, topography, and the direction of groundwater flow.
Sector Breakdown of Competing Water Uses
The five largest water withdrawals for consumptive use in Alberta are agricultural, thermal power, municipal, industrial, and enhanced oil recovery (oilfield injection). More than 70% of the licensed surface water withdrawals in Alberta are for irrigation. The majority (97%) of the combined allocation for surface water and groundwater allocated in the province in 2004 was surface water with only 3% coming from groundwater (AE, 2004). New water license allocations are not available on the Oldman River and Bow River basins, so all growth in these basins must occur within existing allocations.
Regions of Surface Water Allocation
Alberta Environment prepared Figure 8-2 based on long-term averages of river discharge, groundwater supply, and human demand to give an indication of areas where water supply may be a concern. Alberta Environment’s definition of a water-short area is one where natural conditions or development pressures have resulted in conditions where there may be insufficient surface water or groundwater resources for future sustainable development and protection of the aquatic environment (AE, 2006a). The south-eastern portion of the province, where discharges are low and withdrawals are already significant, is closed to new water allocation applications and is an area where water shortages are likely. For example, about 65% of the average natural flow of the Oldman River and its tributaries has already been allocated (Alberta, 2006). Given the projected growth in population, agriculture, and industry in areas that are already water-short or potentially water-short, obtaining surface water allocations on the scale that would be required for the production of nuclear energy (or any kind of thermal plant including coal, natural gas, or geothermal) would not likely be feasible in the southern portion of the province.
The Nuclear Energy Option in Alberta, October 1, 2008 75
Figure 8-2. Assessment of areas where water may be in short supply. The map is intended to represent regional conditions, and exceptions may occur locally (Waterportal, 2008, Water Facts & Info section).
Based on the current and potential water-short areas, it is likely that the northern portion of the province would have the best access to surface water sources. Total water allocations in 2006 on the Athabasca River were about 900,000,000 m3, which is far below the total mean annual discharge of the river of about 23,000,000,000 m3; allocations were about 3.9% of the long-term average supply (Alberta, 2006). However, this comparison based on long-term averages does not take into consideration the seasonal and inter-annual variations in river discharge. The lowest flow periods on
The Nuclear Energy Option in Alberta, October 1, 2008 76 the Athabasca occur between November and March, and maintaining in-stream flow needs (the minimum water flow required to sustain ecosystem heath) during this period will likely determine water availability. Alberta Environment has issued an interim framework for the in-stream flow needs and water management system for specific reaches of the Lower Athabasca River to address the issue of withdrawals from the river during low flow periods. This framework calls for voluntary water conservation measures to limit withdrawals to 10% of the available river flow (AE, 2006b). Current oil sands water use from the Athabasca River has generally been below the limits for in-stream flow needs for protecting ecosystem health (AE, 2007); however, there is concern that further development will add to the cumulative demands on the river (Woynillowicz, 2006).
When evaluating water sources in northern Alberta, one must consider the significant water requirements for the extraction and processing of oil sands. In 2006, the largest sector use of water in the Athabasca River basin was for oil and gas, representing about 55.5% of total allocations (Alberta, 2006). Production of oil sands operations in northern Alberta is forecast to increase from the current level of 1 million barrels per day to 3 million barrels per day by 2020 (Energy, 2008). If similar water/oil ratios are applied in the future, production of more than 3 million barrels per day in 2010 would require 6–13.5 million barrels of water per day (Sauchyn, 2008).
Groundwater Availability and Quality
Alberta’s groundwater resources are not as well defined as surface water. Groundwater assessments in the form of yield maps have been done on a county basis and are contained in reports by the Alberta Research Council and the Prairie Farm Rehabilitation Administration. The Alberta Geological Survey is currently compiling a digital version of groundwater yield maps for the entire province showing potential groundwater yield to a well (Andriashek, 2008).
Projected or Possible Changes to Water Supply
Changes in Allocation Levels and Water Demand
It is likely that water supplies will decline in the province over the next 25 years. Figure 8-3 shows a series of maps that illustrate how water allocations compared to natural river flow have changed in the province over the last 75 years. Note that allocated water represents potential usage as opposed to actual usage, and that a number of sectors currently do not use their full water allocation. Nonetheless, Figure 8-3 indicates that surface water allocations have been progressively increasing. Due in part to this apparent trend, Alberta Environment has placed a moratorium on new allocations for the South Saskatchewan, Bow, and Oldman River Basins located in the southern portions of the province.
Although this moratorium may help alleviate some of the stress on the province’s water supply, water demand is also increasing. In 2005, the volume of water (surface water and groundwater) consumed by all sectors in Alberta was 3,297,876,000 m3. This volume is projected to increase by 21% in 2025 to 3,998,600,000 m3 (AMEC, 2007). Some of the factors that will contribute to this increased usage include:
the population level growing from 3.3 to 4.1 million by 2030 (StatsCan, 2005);
The Nuclear Energy Option in Alberta, October 1, 2008 77 anticipated expansion of oil sands-related activities in the Athabasca River Basin, e.g., Dunbar (2008); and progressively larger extractions by irrigators until approximately 2015, when the 13 irrigation districts are expected to be operating at maximum allocation capacity (AMEC, 2007).
Figure 8-3. Water allocations compared to natural river flow in the period 1930–2005 (Alberta, 2006b)
The Nuclear Energy Option in Alberta, October 1, 2008 78
Potential Climate Change Impacts
Climate change will also likely influence provincial water supplies in the coming decades. A number of climate modelling studies have indicated that Alberta will be warmer and wetter in the future (e.g., Laprise, 1998; Byrne, 1999; Ashmore, 2005; and Lapp, 2002). Although the consensus seems to indicate that Alberta will receive more precipitation, Schindler (2006) has pointed out that these projected increases will be lower than expected increases in potential evapotranspiration, resulting in an overall decline in recharge to the surface water and groundwater supplies. This notion seems to be supported by the conclusions of Rood (2005), which indicate that streamflow rates in a number of the major rivers in Alberta and in its neighbouring regions have been, and are likely to continue, declining at an average rate of 0.2% per year. Projected climate change may also exacerbate future droughts. As was pointed out by Schindler (2006), several studies have indicated that the climate in the Alberta region during the 20th century was unusually stable and moist (Sauchyn, 2001, 2002; Laird, 2003). If projected changes in the climate are correct, future droughts will likely have a substantially greater effect on water supplies than what has been observed in the past.
Current Level of Hydrological and Hydrogeological Knowledge in Alberta
Historically, water supply work performed in Alberta has placed a strong emphasis on understanding the quantity, quality, distribution, and demands on surface water. This is understandable given that as late as 2005, groundwater only accounted for 3% of the water allocated in the province (AMEC, 2007). However, it has recently become clear that groundwater will play an increasingly important role in providing a reliable water supply to regions such as the Calgary– Edmonton corridor, and that the monitoring and management of this resource needs improvement (Rosenberg, 2007). The Rosenberg report also indicated that an inadequate level of groundwater knowledge could hinder future economic growth. Currently, the Alberta Geological Survey is working on the production of a province-wide groundwater yield map (Andriashek, 2008). Although this effort represents a good start, considerably more work will need to be done on groundwater supplies in the future.
Water Permit Application Process
Regulatory Bodies and Stakeholders in Water Usage and Quality
Alberta Environment is the regulatory body in Alberta that accepts applications for water diversions, assesses each application on its merits, and determines whether an extraction licence is granted (AE, 2008a, 2008b, 2008c). Much of the following information is taken from Alberta Environment public information bulletins. The diversion licence identifies the water source, volume, rate, and timing of water to be diverted, as well as the priority of the water right established by the licence, and any conditions the diversion must adhere to. Licences may be issued for temporary diversions up to a maximum of one year, or for longer time periods depending upon the project type. All new licences therefore have an expiry date. The term of a licence depends on criteria specified in regulations. For a long-term project such as a nuclear plant, the duration of the licence is set during the initial approval process. When a licence expires, its holder is required to apply for a renewal. The onus is on the Alberta government to provide reasons for non-renewal of a licence. Once granted,
The Nuclear Energy Option in Alberta, October 1, 2008 79 Alberta Environment maintains records and may compile monthly reports provided by each water user to ensure all water usage conforms to the province’s Water Act27 (WaterAct, 2000). Routine inspections are carried out as part of Alberta Environment’s Compliance Inspection Program.
A summary of stakeholders is provided in Table 8-2. On a municipality scale, the primary stakeholders in water usage were identified via water diversion licence approvals in the publicly available Alberta Environment database. As of August 2008, this database includes over 500,000 licensed wells, with an estimated 5,000 being added each year. Reported usage categories include dewatering, domestic, domestic and stock, domestic and irrigation, heat transfer, industrial, injection, investigation, irrigation, monitoring, municipal and industrial, municipal and observation, observation, and standby. On a provincial level, the Alberta Water Council is made up of a variety of stakeholder bodies from government, industry, and non-governmental organizations. The role of the Water Council is to monitor and steward the implementation of the Alberta’s Water for Life strategy (AE, 2003a) and to champion achievement of the strategy’s three outcomes of a safe and secure drinking water supply, healthy aquatic ecosystems, and reliable quality water supplies for a sustainable economy.
The application and approval of a water licence is not always possible, and is naturally dependent upon the quality and quantity of water available. For example, according to Alberta Environment, licence applications are no longer accepted in the South Saskatchewan River Basin (including the Bow, Oldman, and South Saskatchewan River sub-basins) from surface water sources. Applications for groundwater diversions that are not hydraulically connected to a surface water source will still be accepted. It is understood that there is some flexibility in the application of existing licences within this river basin via water saving practices and conservation of resources.
27 The Water Act has two Regulations: Water (Ministerial) and Water (Offences and Penalties). Copies are available through the Queens Printer (http://www.qp.gov.ab.ca/).
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Table 8-2. Composition of the Alberta Water Council Stakeholder Details Industry Chemical and petrochemical: Canadian Petroleum Products Institute (CPPI) and Canadian Chemical Producers Association (CCPA) Irrigation: Alberta Irrigation Projects Association (AIPA) Mining: Alberta Chamber of Resources Oil and gas: Canadian Association of Petroleum Producers (CAPP) Forestry: Alberta Forest Products Association (AFPA) Livestock: Intensive Livestock Working Group Power generation: TransAlta, ATCO, and EPCOR Non-governmental Wetland conservation: Ducks Unlimited Canada organizations Fisheries habitat conservation: Fish Habitat Conservation Collective Lake environment conservation: Alberta Lake Management Society Bow Riverkeeper Environmental Law Centre Alberta Wilderness Association Watershed Planning and Advisory Council Collective Municipal government Large urban: Cities of Edmonton and Calgary Small urban: Alberta Urban Municipalities Association Rural: Alberta Association of Municipal Districts and Counties Metis settlements: Metis Settlements General Council Government of Alberta Alberta Agriculture and Rural Development and provincial authorities Alberta Energy Alberta Environment Alberta Health and Wellness Alberta Sustainable Resource Development Alberta Economic Development Authority (AEDA) Alberta Water Research Institute (AWRI) Note: The Alberta Water Council is comprised of 25 representatives chosen by the member organizations that make up the Council. Member organizations include industry, non-government organizations, government, the Government of Alberta, and provincial authorities.
Approval Process Stages
Any construction within a water body in Alberta, or requirement to extract water from surface and/or groundwater sources must be preceded by a formal approval under the province's Water Act. Applicants requesting an annual water diversion licence of greater than 62,500 m3 must pay a fee to Alberta Environment to process the application. This fee increases with the quantity of water diverted. The application process is carried out using forms downloadable from the Alberta Environment website.
When an application is issued, the applicant receives a copy with its conditions attached. The approval holder is given a defined time period in which to construct, maintain, and/or operate the project. Once a project is constructed, the approval holder may be required to submit a certificate of completion. Decisions on approvals can be appealed by the applicant, an individual who submits a statement of concern, or an individual who is directly affected. Appeals are submitted to the Environmental Appeals Board.
The Nuclear Energy Option in Alberta, October 1, 2008 81
Anyone who conducts an activity in a water body without an Alberta Environment approval, or who diverts water without a licence, may face enforcement action with a fine of up to $50,000 for an individual, and $500,000 for a company or organization.
First in Time, First in Right System
The Alberta Waterportal28 (Waterportal, 2008) provides a summary of the licence allocation system, where the oldest valid licence is given greater priority than newer applications. According to the Waterportal website:
―In Alberta, water has been traditionally allocated on the First-in-time, First-in-right principle for both surface and ground water. The older the licence, the higher that user is on the priority list. This allows the owners of the first licenses issued to access the full amount of water issued before newer licensees have access, regardless of use. Furthermore, water licenses granted under this principle have no expiry date. However, licenses issued under the Water Act are now issued for a fixed period. The theory of the principle is that it protects an existing user’s rights from those who come after them and is the best way to allow for orderly development. Therefore, during a drought, a farmer with a senior licence may have access to water for irrigation, while at the same time a city with a more recently issued licence may be forced to ask residents to ration water.‖
It is clear that the requirements of a potential nuclear water diversion application would have to be assessed in the context of existing licenses, their status, longevity, and potential for reallocation. Water requirements for a nuclear plant must fit within existing supplies, and in some areas negotiation for transfer of water licences may be required.
Transfer or Sale of Water Permits
Alberta’s Water Act provides for the transfer of an allocation of water held under a licence (AE, 2003b, 2008c). This practice is referred to as resource allocation trading. In Alberta, only water that has been used under a licence—but is not or will no longer be required due to water conservation, or other planned reduction in need—is eligible for transfer. A transfer can only be granted for licences in good standing. There are two types of transfers:
Temporary transfer. All or part of the water allocation is transferred on a temporary basis and reverts back to the existing licensee following an agreed time period. Permanent transfer. All or part of the water allocation is permanently transferred.
In areas of Alberta where available water is fully or nearly fully allocated, a transfer system allows accommodation of new or alternative users. A transfer may only occur where an approved water management plan or an order of Cabinet provides for this. Any transfer is subject to the same review process as a new licence application. Note that the Water Act allows the Government to withhold up to 10% of the transferred water allocation to meet the needs of the aquatic environment, and this 10 % is not available for reallocation or other uses.
28 A: The Alberta WaterPortal project was created to be a not-for-profit organization by Alberta WaterSMART, the Bow River *Basin Council, IBM, and Tesera Systems with funding from the Suncor Energy Foundation, and supported by other private and public sector technology, industry, watershed management, and funding partnerships.
The Nuclear Energy Option in Alberta, October 1, 2008 82
References
AE, 2003a Alberta Environment (2003). Water for Life: Alberta's Strategy for Sustainability. ISBN No. 0-7785-3058-2, Pub No. I/955.
AE, 2003b Alberta Environment (2003). Administrative guideline for transferring water allocations. ISBN No. 0-7785-3002-7, Pub No. I/949.
AE, 2004 Alberta Environment (2004). Advisory Committee on Water Use Practice and Policy: Final Report. ISBN No. 0-7785-3732-3 Pub No. I/979.
AE, 2006a Alberta Environment (2006). Water Conservation and Allocation Guideline for Oilfield Injection.
AE, 2006b Alberta Environment (2006). Interim Framework: Instream flow needs and water management system for specific reaches of the lower Athabasca River.
AE, 2007 Alberta Environment & Fisheries and Oceans Canada (2007). Water Management Framework: Instream Flow Needs and Water Management System for the Lower Athabasca River. Retrieved September 2, 2008 from http://www.dfo-mpo.gc.ca/regions/central/pub/water-eau/index_e.htm
AE, 2008a Alberta Environment (2008). Water Act Approvals: facts at your fingertips. Retrieved August 2008 from http://www.environment.alberta.ca/documents/ WaterAct_Approvals_FS.pdf
AE, 2008b Alberta Environment (2008). Water Act Licences: facts at your fingertips. Retrieved August 2008 from http://www.environment.alberta.ca/documents/ WaterAct_Licences_FS.pdf
AE, 2008c Alberta Environment (2008). Transferring Water Allocations Under a Licence: facts at your fingertips. Retrieved August 2008 from http://www.environment.alberta.ca/documents/ WaterAct_Transfer_of_water_allocations.pdf
Alberta, 2006 Alberta Government (2006). State of the Environment—Water; Sectoral Allocation, Athabasca River Basin. Retrieved August 2008 from http://www3.gov.ab.ca/env/soe/water_indicators/ 26_Athabasca_sub.html
Alberta 2006b Alberta Government (2006). State of the Environment—Water; Historical Data. Retrieved August 2008 from http://www3.gov.ab.ca/env/soe/ water_indicators/27_historical_sub.html
AMEC, 2007 AMEC Earth and Environmental 2007. Current and future water use in Alberta. Prepared for Alberta Environment.
Andriashek, 2008 Andriashek, L. (2008). Personal communication.
The Nuclear Energy Option in Alberta, October 1, 2008 83 Ashmore, 2005 Ashmore, P. & Church, M. (2005). The impact of climate change on rivers and river processes in Canada. Geological Survey of Canada Bulletin 555, Ottawa, Canada.
Baum, 2004 Baum. E. (2004). Wounded Waters–The Hidden Side of Power Plant Pollution. Clean Air Task Force.
Byrne, 1999 Byrne, J.M., Berg, A., & Townshend, I. (1999). Linking observed and general circulation model upper air circulation patterns to current and future snow runoff from the Rocky Mountains. Water Resources Research, 35: 3793–3802.
Dunbar, 2008 Dunbar, R.B. (2008). Existing and proposed Canadian oil sands projects. Prepared for Strategy West, Inc.
Energy, 2008 Alberta Energy (2008). Oil Reserves and Production 2007. Retrieved September 29, 2008 from http://www.energy.gov.ab.ca/Oil/pdfs/ AB_OilReserves.pdf
Environment, 2004 Environment Canada (2004). The nature of water—groundwater. Retrieved August 2008 from http://www.ec.gc.ca/water/en/nature/grdwtr/e_gdwtr.htm
Grant, 1974 Grant, L.O., & Kahan, A.M. (1974). Weather modification for augmenting orographic precipitation. In W.N. Hess (Ed) Weather and Climate Modification, (pp. 282–317), John Wiley.
Laird, 2003 Laird, K.R., Cumming, B.F., Wunsam, S., Rusak, J.A., Oglesby, R.J., Fritz, S.C., & Leavitt, P.R. (2003). Lake sediments record large-scale shifts in moisture regimes across the northern prairies of North America during the past two millennia. Proceedings of the National Academy of Sciences, 100(5): 2483–2488.
Lapp, 2002 Lapp, S., Byrne, J., Kienzle, S., & Townshend, I. (2002). Linking global circulation model synoptics and precipitation for western North America. International Journal of Climatology, 22: 1807–1817.
Laprise, 1998 Laprise, R., Caya, D., Giguere, M., Bergeron, G., Cote, H., Blanchet, J.-P., Boer, G.J., & MacFarlane, N.A. (1998). Climate and climate change in western Canada as simulated by the Canadian regional climate model. Atmosphere- Ocean, 36: 119–167.
Mote, 2005 Mote, P.W., Hamlet, A.F., Clark, M.P., & Lettenmaier, D.P. (2005). Declining mountain snowpack in western North America. Bulletin of the American Meteorological Society, 86, 39–49.
Myhre, 2002 Myhre, R., Goldstein, R., & Smith, W. (2002). Water and Sustainability (Volume 3): U.S. Water consumption for power production - The next half century. Electric Power Research Institute, Technical Report 1006786.
Rood, 2005 Rood, S.B., Samuelson, G.M., Weber, J.K., & Wywrot, K.A. (2005). Twentieth-century decline in streamflows from the hydrographic apex of North America. Journal of Hydrology, 306: 215–233.
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Rosenberg, 2007 Rosenberg International Forum on Water Policy (2007). Report of the Rosenberg International Forum on Water Policy to the Ministry of Environment, Province of Alberta.
Sauchyn, 2001 Sauchyn, D.J. & Skinner, W.R. (2001). A proxy PDSI record for the southwestern Canadian plains. Canadian Water Resources Journal, 26(2): 253–272.
Sauchyn, 2002 Sauchyn, D.J., Barrow, E.M., Hopkinson, R.F., & Leavitt, P.R. (2002). Aridity on the Canadian plains. Géographie Physique et Quaternaire, 56(23): 247– 259.
Sauchyn, 2008 Sauchyn, D.J. & Kulshreshtha, S. (2008). Prairies. In D.S. Lemmen, F.J. Warren, J. Lacrois and E Bush (Eds.), Impacts to Adaptation: Canada in a Changing Climate 2007 (pp. 275–328). Government of Canada, Ottawa, ON.
Schindler, 2006 Schindler, D.W. & Donahue, W.F. (2006). An impending water crisis in Canada’s western prairie provinces. Proceedings of the National Academy of Sciences, 103(19): 7010–7016.
StatsCan, 2005 Statistics Canada (2005). Statistics Canada Population Projections for Canada, Provinces and Territories, 2005-2031. Catalogue 91-520-XIE, Ministry of Industry 2005.
WaterAct, 2000 Alberta Ministry of the Environment (2000). Water Act. Chapter/Regulation: W-3 RSA 2000. Current to 1/1/2008, ISBN# 9780779733651.
Waterportal, 2008 WaterPortal. (2008). Website http://www.albertawater.com/ accessed August 2008.
Woynillowicz, 2006 Woynillowicz, D. & Severson-Baker, C. (2006). Down to the Last Drop—The Athabasca River and Oil Sands. The Pembina Institute.
The Nuclear Energy Option in Alberta, October 1, 2008 85 CHAPTER 9: ENVIRONMENTAL AND OTHER IMPACTS
Summary
Environmental Factors
Nuclear power plants do not emit regulated pollutants or greenhouse gases during operation. However, emissions from a nuclear power plant can occur during construction, maintenance, refuelling, preparation of the nuclear fuel from ore, plant maintenance, and demolition. The lifetime CO2 equivalent emissions of a nuclear power plant, calculated by a life cycle analysis, are comparable to those of wind, solar, or hydro power, and are about a factor of 100 lower than for coal-, gas-, or oil- fired power plants.
Tritium, a radioactive isotope of hydrogen, can be made in heavy-water reactors and its build- up can be controlled by a tritium removal facility. The releases from CANDU plants are well below regulatory limits.
Socioeconomic Factors
A nuclear plant, with its long construction period, capital-intensity, and need for skilled labour during both construction and operation, would have significant socioeconomic impacts on the province and the rural region in which it was located. It would also likely create some public concern and controversy, since Alberta has never had a nuclear power plant. Based on recent Canadian and U.S. studies, Alberta might expect the following impacts:
About 2300 new full-time workers would be needed on-site during construction, with an additional 1000 jobs created indirectly in each of the manufacturing and retail sectors. Skilled labour shortages may occur, particularly of ironworkers, boilermakers, and pipefitters. Plant operation could create about 1000 new permanent on-site jobs, and about 300 new permanent jobs in Alberta’s manufacturing sector. GDP could rise on the order of $400 million annually; combined federal, provincial, and local taxes could increase by $100 to 200 million per year. Locating in a rural area would raise issues similar to those seen in Fort McMurray arising from oil sands development. Of particular concern is the ability of a rural community to expand housing, infrastructure, and public sector labour to accommodate a rapid rise in population during construction. The provincial government will likely have to deal with public concerns about safety (both accidents and long term storage of radioactive wastes), decommissioning and land reclamation, water use, and reliability (given Ontario’s problems with its nuclear fleet).
The Nuclear Energy Option in Alberta, October 1, 2008 86 Environmental factors
Life Cycle Analyses of Carbon Dioxide Production
Operation of any large industrial facility such as a nuclear power plant has a variety of impacts on the surrounding region. This paper discusses some related to radioactive waste disposal (Chapter 6) and water usage (Chapter 8). Another impact is the release of carbon dioxide (CO2) and other greenhouse gases; nuclear power plants release almost none of these during operation. The significance of this is clear when comparing a nuclear plant to a coal- or natural gas-fired power plant of the same capacity; these fossil fuel plants would be large emitters of CO2, and particularly in the case of coal, other air pollutants such as NOx, SOx, and mercury.
In addition to those of normal operations, emissions from a nuclear power plant can occur during construction, maintenance, refuelling, preparation of the nuclear fuel from ore, plant maintenance, and demolition. Calculating these types of emissions over the plant’s lifetime, a process known as a life cycle assessment (LCA), will give a non-zero result. One of the issues around LCA is how far to extend the envelope in which the emissions are calculated.
LCAs, also known as cradle-to-grave analyses, provide an evaluation of the environmental impacts from an energy system. The LCA investigates the full life-cycle of the energy system including construction of the plant, mining and processing the fuel, operations and plant maintenance, disposal of used fuel and other waste by-products, plant decommissioning, and all intervening transportation. The environmental impacts measured in these assessments include contributions to global warming, emissions of acidifying gases (e.g., NOx and SOx), and toxic substances (e.g., heavy metals). The primary greenhouse gases of concern are CO2, methane, and nitrous oxide. Additional environmental impacts from nuclear energy may result from radioactive waste disposal (Chapter 6) and water usage (Chapter 8).
Nuclear power plants do not emit regulated pollutants or greenhouse gases when they are operated, as opposed to fossil energy power plants that are large emitters of CO2, acidic gases, and metals (mercury). For nuclear power, there are atmospheric releases during fuel mining, preparation and transport, plant construction and decommissioning, manufacturing of equipment, and decay of organic matter. The level of emissions depends strongly on the technology and geographical siting of the power plant.
An International Atomic Energy Agency (IAEA) study (Weisser, 2006) estimated that nuclear 29 energy life-cycle CO2 equivalent emissions of 1.5–20 tonnes CO2 equivalent/GWh (tCO2eq/GWh) were comparable to renewable forms of energy generation (solar, 0.74–1.3; wind, 8–30; and hydropower, 1–34 tCO2eq/GWh). The IAEA study further compared the emissions of fossil energy power plants, which have significantly higher greenhouse gas emissions (coal, 800–1000; oil, 700– 800; and natural gas, 360–575 tCO2eq/GWh). The relative differences shown in this study are in agreement with previous studies performed by the University of Wisconsin (Meier, 2002) and the International Energy Agency (Koch, 2000).
The majority of greenhouse gas emissions arise in the upstream stage of the fuel and technology cycle. A study conducted by British Energy (2005) found that the largest emission source (contributing 37% of greenhouse gases) was the mineral extraction process (uranium mining and
29 Carbon dioxide equivalent refers to combining all greenhouse gases into a common term based on the gases’ ability to trap heat in the atmosphere relative to an equal amount of CO2.
The Nuclear Energy Option in Alberta, October 1, 2008 87 milling). However, this result was found to be highly dependent on the concentration of the uranium in the ore and the use of fossil energy as the primary energy source in mining. Another important emission source is uranium enrichment using gaseous diffusion. The diffusion technology is a very energy-intensive process and is being phased out of world production in favour or less-energy intensive technologies. The emissions are also attributable to the local fuel mix of the country where the enrichment is taking place. To reduce greenhouse gas emissions from nuclear technologies, steps can be taken to use more efficient centrifuge or laser technologies in enrichment, to switch from high to low carbon electricity sources, to extend the lifetime of the nuclear power plants, and to increase fuel burnup.
Tritium Releases
Tritium is the radioactive isotope of hydrogen, H-3. It has a half-life of 12.3 years, meaning half of the initial amount decays to non-radioactive helium isotope He-3 in 12.3 years. Tritium is weakly radioactive and it decays by emitting an electron; this is called beta decay. The energy of the decay is so low that it cannot penetrate the outer layer of skin and therefore tritium is not a hazard unless it is absorbed by the body. Unfortunately, because tritium is an isotope of hydrogen, it can take the place of regular hydrogen in water, thereby radioactively contaminating it.30 In the form of tritiated water, tritium is a hazard via inhalation and ingestion. If absorbed in the body, it leaves in about 10 days as the body turns over its water inventory that rapidly.
Small amounts of tritium are generated in nuclear power plants from several processes. The highest tritium inventories are produced in heavy-water reactors such as CANDUs from neutron absorption by heavy hydrogen (H-2).
This tritium in heavy water is periodically removed at the Tritium Removal Facility at the Darlington, Ontario power plant site, at a rate of a couple of kilograms per year (total for all plants). Heavy water is shipped from power plants to the facility, the tritium is removed, and the cleaned heavy water is returned to the power plant.31 The tritium is chemically immobilized and stored in concrete vaults. Some of the tritium is used in emergency exit signs in commercial buildings and airplanes, in lights for airport runways in remote places, and as a tracer in biomedical research (OPG, n.d.).
As discussed in Chapter 5, doses to the public from nuclear power plant operation in Canada are kept within regulatory limits. The regulatory dose limit for members of the public is 1 mSv/yr (Canada, 2007). For comparison, the natural dose from radioactivity that exists naturally in the environment is higher, with the global average being 2–3 mSv/yr. The target per the ALARA principle is a factor of 20 lower, 50 μSv/yr (CNSC, 2004). Both numbers are similar or lower than those used by other countries and according to international guidance.
30 The mass differences among the three hydrogen isotopes (H-1, H-2, and H-3) are large. The mass differences are large enough (e.g., 150% for H-3/H-2) that physical behaviours differ. Therefore, processes like cryogenic distillation are effective. The mass differences among the corresponding types of water are much less. The atomic mass of light water is 18 (2 × H-1 + 1 × O-16); heavy water is 20 (2 × H-2 + 1 × O-16); tritiated water is 22 (2 × H-3 + 1 × O-16). Since tritiated water and heavy water are only 10% different (22 versus 20), their physical characteristics are very similar. Therefore, tritiated water and regular water in the environment behave in a similar manner. Tritium-contaminated water behaves essentially like regular water, except that it contains the radioactive isotope tritium. Tritiated water is therefore ubiquitous in the environment and in the body. 31 At the Tritium Removal Facility, the tritiated water is split into oxygen and H-3/H-2. This hydrogen is cooled to a liquid. Being heavier, H-3 sinks to the bottom and is withdrawn. The cleaner H-2 is withdrawn at the top. The H-2 is then recombined with oxygen to remake heavy water.
The Nuclear Energy Option in Alberta, October 1, 2008 88 ―The doses received by members of the public from routine releases from [nuclear power plants] are too low to measure directly. Therefore, to ensure that the public dose limit is not exceeded, the CNSC restricts the amount of radioactive material that licensees may release. These effluent limits are derived from the public dose limit and are referred to as derived release limits. In addition, the industry sets operating targets that are a small percentage of the derived release limits. These targets are based on the ALARA principle and are unique to each facility, depending on the individual factors (Canada, 2007, Annex 15 d).‖
This procedure applies to tritium and other trace radioactive species at CANDUs. Since 2001, the derived atmospheric release limits for individual Canadian CANDU locations varies from 46,000 to 440,000 terabecquerels (tBq) of tritium (1 Bq is one decay/s). The actual releases during 2003– 2005 were well below limits, in the range of 100–670 tBq/yr to the atmosphere (Canada, 2007, Annex 15 d). The derived liquid release limits for individual Canadian locations vary from 45,000– 16,000,000 tBq/yr. The actual releases during 2003–2005 were again well below limits, in the range of 60–800 tBq/yr (Canada, 2007, Annex 15 d).
In summary, tritium is a significant issue, but one that is well understood, carefully monitored, tightly limited, and successfully kept within limits. The advanced CANDU reactor (ACR) and light- water reactors have light-water coolant and therefore less tritium content than heavy-water coolant, so tritium releases would be lower.
There is one other issue with tritium that does not relate to its radioactivity. Under certain extreme circumstances, deuterium (H-2) and tritium (H-3) will combine or fuse to produce regular helium (He-4) and a neutron. This is the primary fusion reaction used worldwide to make fusion energy power plants, and this is why Canada’s tritium expertise is important in the global fusion energy research program. The extreme difficulty of making deuterium and tritium react has so far prevented fusion energy from becoming a source of electricity.
Tritium is also used in hydrogen bombs; H-2 and H-3 give the bomb its name. Therefore, Canada has very strict controls on any use or distribution of its tritium.
Socioeconomic Factors
A nuclear plant, with its long construction period, capital-intensity, and need for skilled labour during both construction and operation, would have significant socioeconomic impacts on the province and the rural region in which it was located. It would also likely create some public concern and controversy, since Alberta has never had a nuclear power plant. This section covers the following:
likely changes in the regional and provincial demand for labour as a result of construction and operation of a nuclear plant; expected increases in tax revenues, economic activity in the province, and provincial labour income; community issues that may arise as a result of rapid population growth in a rural municipality; and public concerns and new issues that may arise for the Alberta government if nuclear power is introduced into the generation mix.
The Nuclear Energy Option in Alberta, October 1, 2008 89 Other economic impacts are discussed in more depth in Chapter 4.
Employment
The construction and subsequent operation of a nuclear plant would create new jobs in three different ways:
direct employment: labour employed to construct and then operate the plant, indirect employment: jobs created in other sectors as a result of initial expenditures on plant construction and operation, and induced employment: jobs created as a result of new expenditures in other sectors that come about because of higher total labour income.
Most of the technical expertise needed in the design, construction, and operation of nuclear power plants is the same as that required for other large industrial or conventional power projects. The Nuclear Industry Association (NIA) in the UK reports that about 80% of the construction jobs are not nuclear specific. Skilled labour unique to a nuclear plant is generally in the areas of reactor safety and licensing; some nuclear-specific expertise will be required in the engineering workforce, particularly in the areas of civil engineering and quality assurance (NIA, 2006a).
Employment during construction phase
It is difficult to say what labour requirements would be without knowing which reactor design would be used or how much of the plant would be built in Alberta. Companies may find it more efficient to have plants built in modules that are constructed elsewhere and then transported to the plant site, particularly if the plant is being sited in a remote area. This has certainly been the case with Alberta’s oil sands, where much of the manufacturing has taken place near Edmonton or further abroad. The employment estimates in this section assume that all construction is on-site; estimates would fall correspondingly if significant parts of the plant were built elsewhere.
Bruce Power recently released a study of the economic impact of a 4000 Mwe nuclear project in the Athabasca-Grande Prairie-Peace River area (Bruce, 2008). Although the Bruce Power project is larger than the 800 Mwe plant considered in this paper, the analysis of that project should indicate which sectors of Alberta’s economy could expect the biggest changes in employment. They estimate direct, indirect, and induced labour needs for a 10-year construction phase and a typical year of operation. They report a total of 84,000 person-years of labour will be required during the construction period, of which 28% would be direct, 5% indirect, and 67% induced. The most affected sectors are shown in Table 9-1.32 Construction labour accounts for all of the direct employment. Manufacturing is the most important source of indirect employment, and the second-highest contributor to induced employment. The top contribution to induced employment comes from the retail sector, with a little over 1000 new positions generated on average.
32 Bruce Power (2008) presents their results in person-years for the entire 10-year construction period. These have been converted to an annual average simply by dividing their figures by 10.
The Nuclear Energy Option in Alberta, October 1, 2008 90 Table 9-1. Top five sources of cumulative employment during construction (Bruce Power 4000- MWe plant) Average Annual Employment (full-time positions) Portion of Sector Direct Indirect Induced Total total (%) Construction 2315 - - 2315 28 Manufacturing - 161 866 1027 12 Retail - 10 1007 1017 12 Finance, insurance, real estate, and rental or - 13 505 518 6 leasing Accommodation and - 6 468 474 6 food services
Table 9-2 shows the on-site labour force required during construction by occupational category. The second and third columns of this table contain two estimates of the total number of site labour hours required to complete construction. The agreement between these estimates is reasonable, with the DOE Nuclear Power 2010 study predicting 8 million hours in the trades (boilermakers through teamsters) and the United Engineers and Constructors survey estimating 12 million labour hours.
The fourth and fifth columns of Table 9-2 compare the peak construction staff size (number of workers) to the recent number of specialists in each available category of the Alberta workforce. For some trades such as ironworker, boilermaker, and pipefitter, the peak demand for workers at a nuclear plant under construction would exceed 10% of the Alberta workforce in that trade. Specialists from outside Alberta may fill a portion of the most highly skilled jobs. The national workforce could be tapped to meet the demand for a portion of the trades, as these jobs would become permanent within Alberta to support facility operations and maintenance.
If all construction is on-site, developing the nuclear-specific skill sets within Alberta to the required level could be important in implementing the initial nuclear power project since these services constitute a considerable portion of the project cost, and having them readily available can help to reduce the cost and schedule of subsequent projects. These specialties include nuclear engineers and health physicists to ensure the radiation health and safety of workers and the public. The government or utility can sponsor courses and training programs for the development of this expertise.
The Nuclear Energy Option in Alberta, October 1, 2008 91
Table 9-2. Estimates of on-site labour requirements during construction (US DOE, (US DOE, (United, (Alberta, 2004) 33 34 2005) 2005) 1987) Site Labour Force, Peak # Site Labour (hr) Labour (hr) (persons) Labour Skill Type (persons) Boilermakers 305,760 667,000 60 < 500 Bricklayers 215,000 1,000–5,000 Carpenters 815,360 1,322,000 160 > 10,000 Dock Builders - 2,500 - - Electricians 1,477,840 2,201,000 290 5,000–10,000 Iron Workers 1,477,840 1,314,000 290 1,000–5,000 Insulators 152,880 - 30 - Labourers 815,360 1,588,000 160 - Masons 152,880 - 30 - Millwrights 254,800 193,000 50 5,000–10,000 Operating Engineers 662,480 903,000 130 - Painters 152,880 293,000 30 1,000–5,000 3,025,00 Pipefitters 1,375,920 0 270 1,000–5,000 Roofers - 14,800 - - Sheetmetal Workers 254,800 160,000 50 1,000–5,000 Teamsters 254,800 155,000 50 - Craft Supervision 407,680 - 80 - Site Indirect Labour 815,360 - 160 - QC Inspectors 203,840 - 40 - Nucl Steam Sup. staff 713,440 - 140 - EPC Contractor Staff 509,600 - 100 - Owner's O&M staff 1,019,200 - 200 - Start-up Personnel 305,760 - 60 - Regulatory Inspectors 101,920 - 20 -
Employment during operations phase
The overall employment effects and the labour profile shift substantially once the plant moves into operation (see Table 9-3). In the Bruce Power analysis, on-going permanent employment at the plant is calculated to be about 1900 full-time positions. Indirect and induced employment are estimated to rise by almost 6600 jobs per year (about 1500 and 5100, respectively). The top secondary labour effects are in the professional, scientific, and technical workforce, with 645 indirect and 420 induced positions created, and in the retail sector, with about 950 ongoing induced positions.
33 Site labour hours computed from peak number of persons required and the 4.5 year construction schedule provided in the DOE Nuclear Power 2010 study. 34 Based on a 1144-MWe pressurized-water reactor.
The Nuclear Energy Option in Alberta, October 1, 2008 92 Table 9-3. Top six sources of employment during operations (Bruce Power 4000-MWe plant, 2017) Average Annual Employment (full-time positions) Portion of Sector Direct Indirect Induced Total total (%) Utilities 194 194 23 Professional, scientific, and - 64 42 106 12 technical services Retail - 3 95 98 12 Administrative and support, waste - 5 81 86 10 management, and remediation services Information and - 43 24 67 8 cultural industries Finance, insurance, real estate, and rental - 8 47 55 6 or leasing
It is difficult to predict how many of the new permanent jobs would provide opportunities for local residents. The oil sands experience indicates there could be a sizable shift to dependence on the local population. A recent CERI study reported that almost all (92%–97%) of labour expenditures for oil sands mining and upgrading operations were local (Timilsina, 2005). Only one third of labour expenditures were spent locally for in-situ operations, however. For a nuclear project, it seems likely that the local population could benefit; the long construction period associated with a nuclear plant would allow ample time to develop and provide training for members of the local workforce on nuclear-specific labour requirements (NIA, 2006b).
The Bruce Power numbers are somewhat high compared to other estimates of secondary labour market effects. The Nuclear Energy Institute reports that the average nuclear plant in the U.S. creates 400–700 direct full-time positions for a 1000-MW nuclear plant, and about the same number of secondary positions (NEI, 2008). The Idaho National Laboratory (Kenley, 2004) and Canadian Energy Research Institute (CERI, 2008) used standard input-output modeling methodology to estimate direct, indirect, and induced employment from a nuclear project. Their results are compared to the Bruce Power figures in Table 9-4. The Idaho researchers offered a simple rule of thumb, one that had been determined by other investigators as well: for every direct job created through nuclear power plant construction or operations, approximately four jobs are either induced by the plant or indirectly tied to the plant. One must be careful when using this rule of thumb, because it is contingent upon the definition of direct employment. For example, whether particular types of construction or manufacturing employment associated with building a new facility are direct or indirect is a matter of judgement.
The Nuclear Energy Option in Alberta, October 1, 2008 93 Table 9-4. Comparison of employment impact estimates (Kenley, (CERI, 2008) Employment (Bruce, 2008) (Bruce, 2008) 35 2004) Permanent new Sectors Construction Operations New jobs jobs Manufacturing 1,147 283 1,027 292 Construction 1,072 30 2,315 57 Operations 1,294 949 0 1,940 Indirect plus Induced 14,909 2,661 6,060 6,587
In contrast to the fairly wide-ranging construction personnel needs, the operational staffing level of a power reactor is well-established. A recent US DOE study (2004), conducted by Dominion Energy and associates in support of the U.S. Nuclear Power 2010 Program, collected best-estimate operational staffing data for the next-generation plants beginning to come online. These requirements are reproduced in Table 9-5 for two plants: the Westinghouse AP-1000 and the AECL twin ACR-700 designs. A nuclear plant in Alberta with a somewhat smaller capacity of 800 MWe would have slightly lower labour requirements; however, many jobs such as training, security, and health physics technicians are not dependent on plant size.
Table 9-5. On-site labour requirements during operations (US DOE, 2004) (US DOE, 2004) AP1000 Greenfield ACR-700 Greenfield Item Single Unit Twin Units (persons) (persons) Management 9 9 Operations 61 98 Maintenance 164 179 Engineering 72 80 Outage and Planning 22 22 Major Modification and Site Support 45 50 Organizational Effectiveness 20 20 Nuclear Supervision 8 8 Radiation Protection 69 69 Training 24 24 Security 120 120 Supply Chain Management 24 24 Telecommunications 9 9 Off-site Staff (mostly nuclear design and engineering) 51 51 TOTAL 698 763
The burden of infrastructure could be reduced significantly if Alberta forms sharing agreements with other provinces and countries. It could include physical facilities, and common programs and knowledge, and may also lead to economic benefits. The sharing could also contribute in a significant
35 The Idaho study assumes that 33 new 1500-MWe nuclear power plants are constructed by 2024, and that new plants continue to be built at the rate of approximately four per year at that time. Therefore, the Idaho data is normalized to a per-unit basis by dividing by 33, the number of plants operating in 2024, at the time of the projection. The study lumps employment attached to the operational plants plus the facilities being constructed into a single data set that cannot easily be disaggregated.
The Nuclear Energy Option in Alberta, October 1, 2008 94 manner to the harmonization of codes and standards in general, and regulatory framework in particular (IAEA, 2006).
Taxes, Labour Income, and GDP
Financial and labour impacts are very location specific and again depend on the chosen technology and construction methods. Tax regimes vary, and ripple effects depend on the how the local economy is situated within the larger economy. New technologies could require greater reliance on importing necessary labour from outside of Canada, and regional impacts will depend on whether plants are constructed locally or prefabricated elsewhere. Without specifying a particular site, technology, and construction plan, it is not possible to provide accurate estimates of effects on taxes, income, or GDP. The studies cited in this section are intended to indicate possible ranges.
Bruce Power (2008) estimates that the construction of a 4000-MWe nuclear plant would increase provincial GDP more than $12 billion over the construction period, and by about $1 billion per year during operations. Labour income is expected to rise by a little over $5 billion per year during both construction and operations. Unfortunately, project expenditures and economic spinoffs are not linear with respect to plant capacity, but the Bruce Power estimates may at least provide an upper bound on expected benefits.
Although not directly comparable, estimates of changes to GDP from the NEI (2008) and the Canadian Energy Research Institute (Timilsina, 2008) may help put the Bruce Power estimates in perspective (see Table 9-6). The NEI calculates total direct expenditures (local, state-wide, and national) for an average 1000-MWe nuclear plant in the U.S. and then applies a multiplier to estimate the total impact on GDP. Regionally, the NEI reports that every dollar of direct expenditure on a nuclear plant generates slightly more than a dollar of additional indirect spending in the local community (NEI, 2008). Note that the NEI figure excludes revenues associated with the sale of goods and services—in this case, electricity—that are on the order of US$400–500 million for a 1000-MW plant.
Table 9-6. Estimates of fiscal impacts36 (millions of $) Labour Taxes Source of Estimate GDP Income Federal Provincial Local Construction Bruce Power 12,648 5542 222 160 27 (4000-MWe plant) Operations Bruce Power 1111 523 81 86 18 (4000-MWe plant) NEI (2008)37 (1000- 430 40 75 20 MWe plant) CERI (average, 370 - - - - Cdn CANDU units)
CERI has undertaken a similar assessment (Timilsina, 2008) of the 17 CANDU reactors operating in Canada. The direct workforce employed at the reactors is 16,137, or 949 per reactor, which is somewhat higher than is expected for the advanced CANDU reactors. The CERI study utilized an input-output model to project the indirect plus induced economic activity associated with
36 NEI figures are U.S. dollars; all others are Canadian dollars. 37 The NEI estimate of $20 million is for combined state and local taxes.
The Nuclear Energy Option in Alberta, October 1, 2008 95 the plants. The study concluded that the annual economic activity for all 17 CANDUs—again excluding the sale of electricity—amounted to C$6.3 billion, or C$370 million per reactor. This number is in close agreement with the NEI figure of US$250–300 million per reactor.
The estimated tax effects of the Bruce Power plant shown in Table 9-6 were calculated by Alberta Finance using an input-output simulation.
Community Issues: Population Growth and Public Services
The short-term rise in local population during construction would be of particular concern, particularly if all construction takes place on-site. Bruce Power (2008) estimates a sharp increase in labour to about 5000 employees halfway through the construction period (see Figure 9-1). While a smaller plant would not require as large a work force, the increase in population would still represent a substantial increase in the population of many rural communities in Alberta.
6000 es e5000 y lo4000 p m3000 E e2000 im T1000 l u F 0 1 2 3 4 5 6 7 8 9 10 Year of Construction
Figure 9-1. Annual direct employment during construction (Bruce Power 4000-MW plant)
The Government of Alberta examined issues raised for rural communities with the rapid expansion of the oil sands (Alberta, 2006). They found that high growth areas presented special challenges due in part to the following:
provincial resource allocation formulas and a three-year planning horizon that do not account for rates of population growth, lack of coordination between provincial and municipal authorities, and mismatch between municipal responsibilities to create infrastructure and their ability to raise revenue.
Gaps that were identified in high growth rate areas include:
shortages of housing, and affordable housing in particular, difficulty in attracting additional public sector workers to handle a short-term increase in population, and inability to expand infrastructure—particularly in water treatment, waste treatment, health services, and transportation—because the required capital expenditures must be made before additional tax revenues from a development project are realized.
The Nuclear Energy Option in Alberta, October 1, 2008 96
Without changes to Alberta’s municipal funding programs, it is likely that a nuclear project would raise similar issues for a rural community, albeit on a smaller scale.
Public Concerns and New Provincial Government issues
Any major new construction or industrial development will be met with some public opposition in various forms. For example, opposition may be driven by concern over health risks (both real and perceived), possible depreciation of property values, strain on local infrastructure, overcrowded roads, or loss of enjoyment use and natural habitat. Nuclear power faces additional hurdles, mostly around safety, and public opinion in that area tends to be highly polarized.
A 2008 Angus-Reid poll found that Albertans were the strongest supporters of nuclear power in Canada, with 58% in favour of building more nuclear plants, compared to a national average of 50%. However, a majority also expressed concerns about safety issues, as shown in Table 9-7. In other jurisdictions, major public concerns have included safety in the transportation of nuclear material and waste fuel, low-level radiation from plant operations, the risk of major accidents, and long-term secure containment of waste material.
Table 9-7. Public concerns about nuclear power (Angus, 2008) Concerns National Average (%) Alberta (%) Accidents 70 58 Waste management 75 - Local health risks 75 - Terrorism 63 52
Pauluis (2001) recommends early designation of permanent storage sites to assure the public that waste materials are being managed properly. As discussed in Chapter 10, this is a federal responsibility.
Water use is also an important potential concern, as nuclear plants use large amounts of water for cooling, and water use by the oil sands is already a growing public concern. All thermal plants use water. However, nuclear plants use slightly more (205 L/kWh) than fossil-fuel plants (140 L/kWh) (Environment, 2008). Chapter 8 provides an in-depth discussion of water use by nuclear power plants.
Some public scepticism about costs and reliability may arise based on Ontario’s experience with its nuclear fleet. Plants have often not run at expected capacity factors, and have required costly overhauls only part way through their expected lives (Winfield, 2006).
Governments have traditionally placed caps on the liability of plant operators for off-site damages because of the potentially enormous cost associated with a nuclear accident. This issue is discussed further in Chapter 10. It should be noted here, however, that the public may feel that a liability cap does not provide sufficient incentive for an operator to pursue the safest possible practices. Further, non-nuclear generators may view this as an unfair subsidy to the nuclear industry. While estimates of the extent of the subsidy vary, Heyes (2000) estimated that the liability cap implies a subsidy of 1–4 cents/kWh.
Decommissioning and land reclamation will likely also be a public issue. Federal law places the responsibility for decommissioning on plant operators; this is also discussed further in Chapter 10. However, there is growing awareness of the impact of oil sands development and uncertainty about
The Nuclear Energy Option in Alberta, October 1, 2008 97 the likelihood that private firms will live up to such financial obligations. This may lead to calls for the provincial government to provide more assurance that land will be reclaimed satisfactorily and that the public will not foot the bill.
The Nuclear Energy Option in Alberta, October 1, 2008 98 References
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The Nuclear Energy Option in Alberta, October 1, 2008 101 CHAPTER 10: REGULATORY PROCESS
Summary
This chapter reviews regulation that applies to the construction and operation of nuclear power plants as well as the infrastructure for interconnecting nuclear power. Regulations specific to nuclear projects fall under federal jurisdiction while regulations related to the siting and interconnection of new power and transmission are subject to provincial legislation. The major steps in licensing a new nuclear power plant are shown in a flow diagram. The combination of new regulations since 2000 and the fact that no nuclear power plants have been built in Canada in the last 25 years make it difficult to assess the actual performance of the regulatory approval process for new facilities.
Regulatory Process and Review of Recent Changes
Regulation of Nuclear Plants
The federal government established legislative control and jurisdiction over the development of nuclear energy in 1946, with the Atomic Energy Control Act and the Atomic Energy Control Board. In 2000, the legislation and control board were replaced with the Nuclear Safety and Control Act (Justice, 1997) and the Canadian Nuclear Safety Commission (CNSC) to address concerns about protection of the environment, health, safety, and security. Under the Nuclear Safety and Control Act, the CNSC is mandated to regulate all nuclear facilities and nuclear-related activities. The Nuclear Safety and Control Act is supported by a suite of legislation, regulations, and regulatory documents that include:
Legislation: Nuclear Liability Act, Nuclear Fuel Waste Management Act, and the Canadian Environmental Assessment Act; Regulation: General Nuclear Safety and Control Regulations, Radiation Protection Regulation, and the Nuclear Security Regulation; and Regulatory documents: Life Extension of Nuclear Power Plants, Safety Analysis of Nuclear Power Plants, Design of New Nuclear Power Plants, and Certification of Persons Working at Nuclear Power Plants.
The licensing of nuclear facilities is also subject to legislation (Table 1).
The Nuclear Energy Option in Alberta, October 1, 2008 102 Table 10-1. Issues subject to federal legislation, regulation, or policy Issue subject Government of Canada to federal Authority Scope Regulatory Act or Policy regulation Licensing CNSC Nuclear Safety and Control Act, Obtain separate licences for site section 3 of the General Nuclear preparation, construction of the Safety Regulations, nuclear plant, operation, sections 3–7 of the Class I Nuclear decommissioning, and Facilities Regulations, abandonment. the Nuclear Security Regulations, the Radiation Protecting Regulation, the Packaging and Transport of Nuclear Substance Regulations, the Nuclear Substance and Radiation Devices Regulations, other regulations and regulatory documents Environmental CNSC, Canadian Environmental Assess the environmental impact. Impact Minister of Assessment Act Environment Environmental Federal Canadian Environmental Protection Assess the environmental impact. Impact government, Act 1999, provincial the Fisheries Act, governments, the Species at Risk Act, stakeholders the Migratory Bird Convention Act, the Canada Water Act Liability Federal Nuclear Liability Act Nuclear plant operators are not government required to purchase more than $75 million of insurance for off-site accident damages
Liability (Accidents, Land reclamation)
Under the Nuclear Liability Act (1985), nuclear plant operators are not required to purchase more than $75 million of insurance for off-site accident damages (Justice, 2008). Damage costs above that limit would presumably be borne by government, and ultimately the taxpayers.
Regulation of New Generating Projects, Demand, and Transmission
Local and provincial agencies such as the Alberta Utilities Commission and the Alberta Environment may also be involved in granting approvals and licences required for the construction and operation of any electric power generating project (Energy, 2004). For example, the land chosen for a new generating project may be subject to zoning or may require re-zoning. Similarly, the water to be heated to steam by nuclear fission or for system cooling requires a license. New transmission lines may need to be built to serve the location and capacity of new nuclear power plants. Some of the issues in the licensing process that are subject to provincial approval and regulation are summarized in Table 2.
The Nuclear Energy Option in Alberta, October 1, 2008 103 Table 10-2. Issues that may be subject to provincial legislation, regulation, or policy Issue subject Government of Alberta to provincial Authority Scope Regulatory Act or Policy regulation Municipal land local Municipal Government Act Obtain approval for land use. zoning municipal government Land: First Nations First Nations Consultation Alberta recognizes that it has a consultations or aboriginal Guidelines on Land duty to consult with First Nations with First communities Management and Resource where land management and Nations Development resource development has the potential to impact First Nations’ traditional use of Crown lands adversely. Land: Alberta Historical Resources Act A Historical Resources Overview historical Tourism, must be submitted. This includes resources Parks, the assessment and clearance Recreation, of all archaeological, historical, and Culture; and paleontological resources. possibly Royal Tyrell Museum of Palaeontology Water Alberta Water Act Obtain licence to divert. Environment Transmission: Alberta Alberta Electric Utilities Act, The AESO establishes the connection to Electric Transmission Regulation transmission interconnection the grid, use System option, determines route and of right-of-way Operator design, conducts engineering for (AESO), evaluations on the impacts of transmission Alberta new generation capacity on the lines Utilities grid system, and submits the Commission Needs Application to the Alberta Utilities Commission. Transmission: Alberta Alberta Environmental The transmission facility may environmental Environment Protection and Enhancement trigger a provincial impact of new Act, Alberta Regulation 111/93, environmental assessment. lines Environmental Assessment (Mandatory and Exempted Activities) Regulation New power Alberta Hydro and Electric Energy Act, Separate applications must be project Utilities under AUC rule 007, rules submitted for power plants, Commission respecting Applications for interconnections, substations, or Power Plants, Substations, transmission facilities. Transmission Lines and Industrial System Designations
Sequence of Regulatory Requirements
The Nuclear Safety and Control Act is the cornerstone of the CNSC’s regulatory framework. The major steps in licensing a new nuclear power plant are covered in CNSC (2006) and CNSC
The Nuclear Energy Option in Alberta, October 1, 2008 104 (2008). The regulations require separate licences, issued in sequence, for each of the five phases in the life cycle of a nuclear plant:38
a licence to prepare a site (regulatory information provided in Section 4 of the Class I Nuclear Facilities Regulation), a licence to construct (regulatory information provided in Section 5 of the Class I Nuclear Facilities Regulation), a licence to operate (regulatory information provided in Section 6 of the Class I Nuclear Facilities Regulation), a licence to decommission (regulatory information provided in Section 7 of the Class I Nuclear Facilities Regulation), and a licence to abandon.
There are four major steps in the licensing process:
applicant submits a licence application (for a new power plant, for amendments to existing licence, or for any other process that uses nuclear energy and material). environmental assessment. technical assessment. decision by CNSC.
The process followed by CNSC to assess the licence application is outlined in Figure 1.
Step 1: Applicant Submits a Licence Application
In the first step, the applicant submits a licence application to the CNSC. For major resource projects such as a nuclear power plant, a project description should also be sent to the Natural Resources Canada’s Major Project Management Office, which offers licensees a single entry point into the federal regulatory system. Once the CNSC receives the application (see box A in Figure 1), it establishes fees required to analyse the application, assesses information about financial guarantees to ensure that sufficient funds are available for decommissioning activities at any licensing stage39 (box B), and draws an assessment plan and a timeline. The applicant must also submit an environmental impact statement (EIS) to CNSC, who will assess the EIS and prepare an environmental assessment (EA) report (box C).
38 Facilities must obtain a licence at each phase of the life cycle. While the EA covers all five phases in the life cycle (i.e., the approval of the initial EA allows the facility to seek a licence at each phase), additional EAs may be required if the project changes over time. 39 Plant operators are responsible for all decommissioning costs, and the CNSC has the authority to require operators to provide financial guarantees for decommissioning (NEA, 2007). Decommissioning costs vary considerably by technology.
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Figure 10-1. Process for obtaining a licence to construct or operate a new nuclear plant in Canada (CNSC, 2008). CMD = commission member document; EA = environmental assessment.
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Step 2: Environmental Assessment
The EA is carried out to meet the requirements of the Canadian Environmental Assessment Act (CEAA). Although nuclear jurisdiction is solely federal, the CEAA allows the federal Minister of Environment to enter into agreements with provincial and territorial governments where both governments have an interest in the EA. The EA considers all five phases in the life cycle of a nuclear power plant. For a new nuclear plant, the EA may be conducted as a comprehensive study by the CNSC or referred to a review panel (CNSC, 2008). Comprehensive studies are a type of EA prescribed in the Comprehensive Study List Regulations, and are conducted for large complex projects that are likely to have significant negative environmental effects or attract public interest and concern. The CEAA offers participant funding for comprehensive studies. A review panel may be appointed to conduct the EA if it is uncertain whether a proposed project is likely to have negative environmental effects that cannot be mitigated, or if public concerns warrant it. Panel members are appointed by the Minister of the Environment.
Under the Comprehensive Study List Regulations the EA usually includes opportunities for public participation through written comments and participation in public hearings.40 Typically, public hearings for licensing applications for nuclear power plants take place over two hearing days that are held over a ninety-day period (boxes E and G in Figure 1). Following the second day of hearings, the Commission members deliberate and render a record of proceedings, including the reason for decision (box H). Ultimately the Commission Tribunal, a CNSC-designated officer, or the Governor in Council considers the recommendations and makes the EA decision before proceeding with licensing.
Step 3: Technical Assessment
Once the EA decision is made, the CNSC undertakes a variety of technical assessments to ensure that the application complies with regulatory requirements. The CNSC produces an integrated assessment report that makes a decision recommendation on the licence application. The technical assessment process is flexible to some degree as the recommendation may include proposed changes to the regulatory framework to accommodate evolving nuclear technologies.
Step 4: CNSC Renders its Decision
In the final step, CNSC renders its licensing decision (box I of Figure 1). As with the EA, the decision is made by the Commission Tribunal or a CNSC-designated officer, and a licence or letter of refusal is issued. Note that if the licence decision is made by a Commission Tribunal, additional public hearings may be held as part of this process.
Time Frame for Approval Process
The CNSC estimates that the total time from the receipt of an application to the issuance of a licence to operate is approximately nine years (CNSC, 2008). The process is broken down by phase in Table 3.
40 The public may also be involved in review of the EIS.
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Table 10-3. Approximate duration of the environmental assessment and licensing steps (CNSC, 2008) Activity Duration Aboriginal consultation Ongoing Environmental assessment and licence to prepare site ~ 36 months Site preparation ~ 18 months Licence to construct ~ 30 months (minimum 6-month overlap with the previous activities) Licence to operate ~ 24 months Applicant’s activities (e.g., plant construction) ~ 48–54 months Total duration ~ 9 years
The EA and the licence to prepare sites (including development of a Joint Review Panel Agreement41 and EIS Guidelines) can take between ten months and three years to complete, and include one or two sessions of one-day public hearings. For example, as of August 2008, the ongoing EAs posted on CNSC’s website were started on May 17, 2007, and February 12, 2007 for new nuclear power plants at Darlington and Kincardine, respectively. There are no completed EAs related to new nuclear plant projects. The completed EAs for projects such as resumption of power operation, restart of nuclear generating stations, and additional storage for radioactive waste operations, took 15–19 months.
Evaluation of the Regulatory Process
There are a number of uncertainties in the regulatory process for a nuclear facility.
First, the CNSC’s assessment of a licence application may depend on ―whether the CNSC has the resources to carry out its review in a timely manner (CNSC, 2008).‖ In addition, some aspects of the regulatory framework are vulnerable to interpretation and may delay the licensing process. Issues may arise due to lack of understanding of or experience with the proposed technology, emergence of new issues unregulated by existing legislation, and updates in international standards.
Secondly, the $75 million of insurance for off-site accident damages liability caps have been criticized as weakening industry incentives to prevent accidents and as a subsidy favouring nuclear power over other forms of generation.
The CNSC is in the process of updating its regulatory framework by drawing upon international standards and best practices, including the International Atomic Energy Agency’s nuclear safety standards. The regulatory framework is flexible, and open to changes that become apparent from assessing new licence requests and evolving nuclear technology.
41 Both the EA and licensing to prepare a site occur concurrently when a project undergoes a Joint Review Panel, to ensure that information submitted (overlapping to some extent) can be considered in a single process.
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References
CNSC, 2006 Canadian Nuclear Safety Commission (2006). Licensing Process for New Nuclear Power Plants in Canada. Catalogue number INFO-0756 ISBN 0-662- 42643-6 [Electronic version].
CNSC, 2008 Canadian Nuclear Safety Commission (2008). Licensing Process for New Nuclear Power Plants in Canada. Catalogue number INFO-0756 (Revision 1) ISBN 978-0-662-48658-9 [Electronic version].
Energy, 2004 Alberta Energy (2004). "New Generation Brochure." Retrieved August 12, 2008, from http://www.energy.gov.ab.ca/Electricity/pdfs/ newgenbrochure2004.pdf
Justice, 1997 Department of Justice, Canada (1997). Nuclear Safety and Control Act [Electronic version].
Justice, 2008 Department of Justice, Canada (2008). Nuclear Liability Act (R.S., 1985, c. N- 28). Retrieved August 2, 2008 from http://laws.justice.gc.ca/en/showdoc/cs/N- 28/bo-ga:l_I-gb:s_4//en#anchorbo-ga:l_I-gb:s_4
NEA, 2007 Nuclear Energy Agency (2007). "Decommissioning Nuclear Facilities in Canada." OECD. Retrieved August 2, 2008 from http://www.nea.fr/html/rwm/wpdd/canada.pdf
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APPENDIX A: SURVEY OF NUCLEAR REACTOR OPTIONS
Summary
This appendix summarizes information on the world market of nuclear reactors to provide background to the summary information in several chapters and to acquaint the reader with concepts that may be marketed in Alberta. The appendix is divided into five sections. The first gives an overview; the other four summarize light-water reactors, heavy-water reactors, helium-cooled high- temperature reactors, and small–medium-sized reactors.
Throughout the main body of this report, we have endeavoured to minimize the use of acronyms. Indeed, generally, the report does not refer to specific reactor concepts with the primary exception of the CANDU and the ACR, which have special importance to Canadians. CANDU is also an example of a concept that is more familiar in the acronym form than written in its long form (Canada deuterium uranium). The Advanced CANDU Reactor (ACR) is an example of a compound acronym, one inside the other. However, this appendix is unavoidably full of acronyms as it surveys the international market of acronym-dense reactor approaches. We have no simple answer to the practice of acronyms that are commonly written as words, e.g., Eskom42, and words that are commonly written as acronyms, e.g., AREVA43.
Overview
Alberta’s current largest power plant is approximately 450 MWe, and early in the study we identified a nominal nuclear power plant size in Alberta to be perhaps 800 MWe. This was based on being about twice the current largest plant and comparable to the newer CANDUs in Canada. As the study progressed, we obtained more information on the sizes of plants that are, or may be, on the market.
Heavy-water reactors. The market has evolved to fairly large sizes, 700–1165 MWe, with the newer designs on the high end of this range. The newer designs are only partially heavy water; they retain heavy water as the neutron moderator but have shifted to light water for cooling. Canada’s reactor experience resides in this category. Light-water reactors. The conventional market has evolved to large sizes, 1100–1700 MWe, with the exception of the Westinghouse AP-600 at 650 MWe. The AP-600 has never been built and Westinghouse is focusing on the AP-1000 (1154 MWe) instead. Helium-cooled high-temperature reactors. There is no active market yet, although planned offerings are in the range 175–300 MWe. Small–medium reactors. Most of the ones potentially entering the market are scaled down versions of pressurized light-water reactors with traditional uranium oxide fuel, 10–300 MWe. Some of these are adapted from proven designs in submarines or icebreakers. There are other concepts include pressurized water with uranium aluminum
42 Eskom is a South African electricity public utility. It started in 1923 as the Electricity Supply Commission (ESCOM). It was also known by its Afrikaans name Elektrisiteitsvoorsieningskommissie (EVKOM). The two acronyms were combined in 1986 and the utility is now known as Eskom. 43 AREVA is a large energy company headquartered in France, formed by Framatome and Cogema. Although its name is generally written in all capital letters like an acronym, it is not an acronym.
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silicide fuel, uranium hydride fuel, the sodium-cooled Toshiba 4S, the lead-cooled BREST reactor, and technology adapted from Russian submarines.
Countries with nuclear power plants have taken one of three options:
Build a domestic uranium enrichment capability for use with light-water or helium- cooled reactors: Brazil, China, France, Germany, India, Iran, Japan, Netherlands, Pakistan, Russia, U.S., and UK (WISE, 2008). Build a domestic heavy-water production capability for use with heavy-water reactors: Argentina, Canada, India, Pakistan, and South Korea (WISE, 2008). Buy enriched uranium or heavy water internationally: Armenia, Belgium, Bulgaria, Czech Republic, Finland, Hungary, Lithuania, Mexico, Romania, Slovakia, South Africa, South Korea, Spain, Sweden, Switzerland, Taiwan, and Ukraine.
Nuclear power is an international, competitive market. Several international consortia exist, such as General Electric-Hitachi (known as Hitachi-General Electric in Japan) and the International Reactor Innovative and Secure (IRIS) consortium led by Westinghouse, which is itself majority owned by Toshiba. Likewise, many countries such as China, Japan, Finland, South Korea, and U.S. have nuclear power plants in operation or under construction that stem from multiple vendor companies. So far, other countries have kept to the mode of a single large national nuclear company, which has a domestic monopoly. Even so, internationalization is nonetheless occurring in countries such as Russia; the World Nuclear Association (2008) reports that in March 2008, ―Toshiba signed a technical cooperation agreement on civil nuclear power with Russia's Atomenergoprom, the single vertically-integrated state holding company for Russia's nuclear power sector created in 2007.‖
There is increasing awareness of the importance of international fuel arrangements so that countries need not fear being cut off as a result of international disputes. This is hoped to decrease costs (due to economies of scale) and decrease motivation for every country to develop all the nuclear technologies at every step of the fuel cycle, especially uranium enrichment, heavy-water production, and used fuel chemical separation, which are considered sensitive in the sense of potentially enabling a pathway for nuclear weapon material.
There are 443 nuclear power units in 32 countries around the globe. Of these, 375 use regular light water as the coolant, 48 use heavy water, 18 are gas-cooled, and 2 are liquid-metal cooled fast reactors (News, 2008). The light-water and heavy-water technologies are now quite mature and are supported by full-service companies that offer the reactor, fuel, replacement parts, monitoring, and resolution of issues as they arise. New helium-cooled high-temperature designs are replacing the existing gas-cooled reactors that are in use in the United Kingdom. Two fast breeder reactors, cooled by liquid sodium metal, are in service in Russia, and are deemed not relevant to application in Alberta as are they being marketed to our knowledge.
All water-cooled and helium-cooled reactors under consideration have a thermal neutron flux, in which most fissions occur with neutrons that are at low energy, close to thermal equilibrium with the surrounding environment. This means that high energy neutrons created by fission must be slowed down or moderated to thermal energies. Of all the reactors today, 99% use this approach, in part because the moderating process creates a time lag in the process of fission-neutron-fission. Only two materials are used as moderators: water (light or heavy) or carbon (as graphite in helium-cooled reactors).
However, in thermal reactors, only fissile isotopes such as natural U-235 and man-made Pu- 239 contribute significantly to energy production. Fertile isotopes such as U-238 do not. Therefore,
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the energy recovery from the original uranium ore is limited in thermal reactors. The opposite approach is reactors with a fast neutron flux, in which most fissions occur with neutrons at high energy; moderation is avoided. As far as we can determine, all of the liquid metal-cooled reactors being developed are fast reactors. Moderating elements such as water and carbon are avoided.
In Chapter 3, four basic types of commercial nuclear power plants were identified as being applicable to electricity production in Alberta. The nuclear technologies include pressurized heavy- water reactors such as the CANDU, light-water reactors, newly developed helium-cooled high- temperature reactors and small–medium reactors (Chicago, 2004). This categorization by reactor technology is used to emphasize the primary differences between the systems in terms of availability of the technology, application-specific reactor size, requirements for enrichment and heavy-water production, applicability to heat applications, and reactor efficiency.
The four types of reactor technologies are described in the following sections and include information on the specific reactor systems and vendors, fuels, target markets, design certification status, and reference sources. A summary comparison of the four reactor types and representative performance data is provided in Chapter 3. The reactor data are also referred to in Chapters 4, 5, 6, and 7.
Heavy-water Reactors (Table A-1)
Heavy-water reactors (700–1165 MWe) are cooled by water with an extra neutron in the hydrogen (heavy water).44 These reactors are pressurized to prevent boiling of the coolant.45 These types of reactor are found in Argentina, Canada (Ontario, Quebec, and New Brunswick), China, India, Pakistan, Romania, and the Republic of Korea. New up-to-date versions are being marketed by companies in Canada (NEI, 2008; EIA, 2003; EIA 2008; WNA 2008).
Atomic Energy of Canada Limited (AECL) CANDU. These heavy-water reactors generally use uranium oxide as fuel. The fuel is in pellet form and is placed in tubes made of zirconium alloy. Existing heavy-water reactors use unenriched uranium, that is, 0.7% U-235 as found in nature. They also use the heavy water both as the reactor coolant and as the moderator to slow down neutrons from the high energy at which they are created by the fission process to the lower energy at which most induce the next generation of fissions. The CANDU 6 design is the existing technology reactor that went into service in the early 1980s. CANDU plants share a containment building and are therefore often in groups of two or four units. Qinsham, China is a 2 × 728-MWe installation and Darlington, Ontario is composed of 4 × 935 MWe units.
AECL ACR. The ACR-700 is designed by AECL and is based on the CANDU 6 design. Information on the ACR-1000 can be found at AECL (2008), Torgerson (2007), and WNA (2008). Development of the ACR 700 is not being pursued; ACR 1000 is the product being marketed. The ACR-700 and ACR-1000 reactors use light water as the reactor coolant and retain heavy water as the moderator. The reactor uses a modest uranium enrichment (~2% U-235) to improve reactor performance. Unlike the light-water reactors, the ACR-700/1000 is continuously refuelled while producing power. Fuelling machines are designed to isolate an individual fuel channel, remove a
44 Heavy water absorbs fewer neutrons than light water and is therefore more efficient in the use of neutrons. This allows lower enriched uranium to be used as fuel, but requires a plant to separate heavy hydrogen (H-2 with one proton and one neutron) from regular hydrogen (H-1 with one proton and no neutrons) via cryogenic distillation. 45 Besides the reactors cooled by light or heavy water, the other world power plants are gas-cooled (22) and sodium-cooled breeder reactors (3). Five of the 439 are in long-term shutdown. There are also 35 reactors currently under construction.
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selected number of fuel assemblies, and return the channel to service. The ACR-700/1000 is designed as a two-unit integrated plant design. The reactors make extensive use of modular construction to improve their economic competitiveness (DOE, 2004; AECL, 2008; Chicago, 2004). The ACR-1000 is designed to also be able to use uranium-plutonium mixed oxide fuel, thorium, and other transuranic elements (WNA, 2008).
Warning: physics paragraph! Chapter 7 explains the power shutdown safety function. It notes that the power feedback must be negative. This is easiest to prove if each individual effect that comprises total power feedback is negative, but acceptable if the total combined effect is negative even if an individual effect is positive. A reason for that (admittedly cryptic) explanation is that the CANDU reactors have a positive void coefficient, i.e., the fission rate can increase if boiling occurs in a coolant tube. For the ACR-1000, ―Regulatory confidence in safety is enhanced by a small negative void reactivity for the first time in CANDU, and utilising other passive safety features as well as two independent and fast shutdown systems (WNA, 2008).‖
The World Nuclear Association (WNA, 2008) also notes that there is another CANDU option being considered for commercialization after 2020 called CANDU X. It is variant of the ACR but with supercritical light-water coolant (25 MPa pressure, 625°C); water systems kept in the pressurized liquid state are limited to ~320°C and 15 MPa pressure, below the thermodynamic critical temperature of water (374°C). Higher temperatures increase the thermal efficiency at the cost of higher pressure. A supercritical fluid is a fluid substance at a temperature and pressure above its thermodynamic critical point. The significance of this is that it cannot undergo a phase change from gas to liquid or back, but instead behaves like a gas with very high liquid-like density. With no phase change, the fluid can carry over sensible heat, not latent heat. Water in the supercritical state, although it has never been used as a reactor coolant, would allow higher temperatures and thus higher thermal efficiency.
India AHWR - India is also developing an advanced heavy-water reactor (AHWR) to use thorium and plutonium fuel (WNA 2008). However, the choice of fuel and India’s failure to sign the Nuclear Non-proliferation Treaty will greatly inhibit any moves to market such a concept internationally.
India’s focus on the thorium nuclear fuel cycle instead of the uranium fuel cycle stems in large part from India’s large thorium ore resources. All nuclear fuel cycles start with U-235, which is the only fissile isotope found in nature. Fissile means the isotope readily fissions in thermal nuclear reactors; 99% of the reactors in the world today are thermal. There are also fertile isotopes that do not readily fission in thermal nuclear reactors but can be made into fissile isotopes by absorbing a neutron. There are two fertile isotopes in nature, U-238 (99.3% of natural uranium) and Th-232 (100% of natural thorium). Uranium fuel cycles start with U-235 to create fissions and neutrons that convert fertile U-238 into fissile Pu-239, which is not found in nature. The thorium fuel cycle starts with U-235 to create fissions and neutrons that convert fertile Th-232 into fissile U-233, which is not found in nature. The Indians have started with U-235 mixed with U-238 and therefore have made Pu- 239, which they eventually hope to fission in the presence of Th-232 to make U-233, thus converting to the thorium fuel cycle. This is the motivation for their thorium-plutonium fuel.
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Table A-1. Potentially marketable heavy-water reactor nuclear power plant designs Regulatory Size Coolant Plants in Plants under Plants Company a design (MWe) and Fuel operation construction proposed reviews 7 plants 2 plants Atomic based on heavy- based on reviewed in Energy of CANDU water CANDU Canada, Canada 700–935 34 technology cooled and technology Taiwan, Limited under moderated planned in South Korea CANDU construction India in India Atomic heavy- Energy of water Canada moderated, b b ACR series Limited 2 × 753 none none none pressurized pre-review ACR-700 light-water (replaced by cooled ACR-1000) heavy- Atomic water Energy of moderated, b b ACR series Canada 2 × 1165 none none ? pressurized pre-review Limited light-water ACR-1000 cooled India heavy- Advanced water Heavy-water unknown none none none no info moderated Reactor and cooled (AHWR) a All are fuelled with uranium oxide in zirconium alloy tubes b Earlier designs of these nuclear power plants are in service throughout the world.
Light-water Reactors (Table A-2)
Light-water reactors (650–1700 MWe) are cooled by water that is kept in the liquid phase (i.e., pressurized water) or water that is allowed to boil (i.e., boiling water). These reactor types are in operation throughout the world and new up-to-date versions are being marketed by companies in France, Japan, and the U.S (NEI, 2008; EIA, 2008; WNA, 2008).
Pellets of uranium oxide are placed in tubes (cladding) made from alloys of zirconium. The uranium is enriched to 3%–5% U-235. Since natural uranium is 0.7% U-235, this requires a uranium enrichment plant; there are several commercial enrichment plants in operation worldwide.
AREVA EPR. The European Pressurized water Reactor (EPR) is a very large design developed in the 1990s as a joint venture by French and German companies (AREVA, 2008). The EPR is a conventional pressurized-water reactor in which components have been simplified and where considerable emphasis is placed on reactor safety. The design is now being used to build a reactor in Finland with a target completion date of 2009. France has started a second EPR at Flamanville. Present French policy suggests that additional EPRs might replace additional commercial reactors now operating in France, starting in the late 2010s (DOE, 2004; EIA, 2008).
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AREVA-MHI ATMEA1. A joint venture between AREVA and Mitsubishi Heavy Industries called ATMEA is developing a mid-sized 1100-MWe pressurized-water reactor (ATMEA, 2008).
General Electric-Hitachi ABWR. The Advanced Boiling Water Reactor (ABWR) design is based on similar designs operating in the U.S. but with advanced features such as advanced instrumentation and control systems (GE, 2008; DOE, 2004). The ABWR is a mature design, and two of them have been built in Japan by a U.S. firm working with a Japanese firm (Chicago, 2004). There is also one under construction and eight more planned in Japan (WNA, 2008a).
General Electric ESBWR - The Economic Simplified Boiling Water Reactor (ESBWR) is a further evolution from the ABWR (GE, 2008). The reactor was developed by GE in concert with international utilities, designers, and research organizations. The reactor uses natural circulation and passive safety systems to enhance system plant performance. The ESBWR is designed as a single- unit, stand-alone system (DOE, 2004; Chicago, 2004).
Korea AP-1400. Another pressurized-water variant is the AP-1400 (WNA, 2008), which evolved from the System 80+ (originally Combustion Engineering in the U.S.). The design has been certified by the Korean Institute of Nuclear Safety. The first two plants of 1450 MWe are expected to be built in South Korea.
Mitsubishi Heavy Industries APWR. The Advanced Pressurized Water Reactor (APWR) generation III reactor was developed by Mitsubishi Heavy Industries based on pressurized-water reactor technology. The reactor has several design enhancements including a neutron reflector, improved efficiency, and improved safety systems. It has improved safety features compared to the last generation, including a combination of passive and active systems (MHI, 2008). The standard APWR is going through the licensing process in Japan and is planned to be constructed at the Tsuruga plant (WNA, 2008a). The next APWR will be of a 1700-MWe power and will be modified to comply with U.S. regulations (WNA, 2008a).
Russian VVER-1200. A third-generation pressurized-water reactor based on the VVER-1000, is now being offered for export. The VVER-1000 is currently in operation in Russia, Bulgaria, Slovakia, Iran, Czech Republic, Ukraine, and India. The VVER-1200 offers safety features including a containment building and missile shield (WNA, 2008b). The reactor will have full emergency systems that include an emergency core cooling system, emergency backup diesel power supply, advanced refuelling machine, full reactor control systems, backup feed water support, and full reactor shutdown system. The reactor is designed for high fuel burn up, which means that the nuclear fuel for it will last longer (AUA 2007).
Westinghouse AP-600/AP-1000. This is a pressurized-water reactor based on the U.S. NRC- certified AP-600 (Westinghouse, 2002), with design changes to support the higher output. The AP- 1000 is designed with passive features for emergency cooling of the reactor and containment provided by natural forces such as gravity, natural circulation, convection, evaporation and condensation rather than AC power supplies and motor-driven components. The AP-1000 is designed as a single unit, stand-alone system (DOE, 2004; Chicago, 2004; Westinghouse, 2008).
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Table A-2. Potentially marketable light-water reactor nuclear power plant designs Regulatory Size Coolant Plants in Plants under Plants Company a design (MWe) and Fuel operation construction proposed reviews submitted to U.S. NRC in AREVA 6 (U.S.) pressurized b 1 (Finland) Dec 2007, European Power 1600 none 1 (China) water 1 (France) approved in Reactor (EPR) ? (France) Finland and France none yet, AREVA-MHI 1100– pressurized b b b licensing none none none ATMEA1 reactor 1150 water activities to start in 2010 certified in GE Hitachi 2 (Taiwan) U.S., Advanced 1350– boiling 8 (Japan) 3 (Japan) 1 (Japan) reviewed in Boiling Water 1460 water 2 (China) Japan and Reactor (ABWR) Taiwan GE Economic U.S. NRC Simplified boiling b b certification 1520 none none 3 (U.S.) Boiling Water water expected in Reactor 2009 (ESBWR) Korea pressurized b b 2 (S. reviewed in 1450 none none AP-1400 water Korea) South Korea Mitsubishi Heavy submitted to Industries 1500– pressurized b b 2 (Japan) U.S. NRC in Advanced none none 1700 water 4 (U.S.) Dec 2007, Pressurized target 2011 Water Reactor (APWR) Russian pressurized b b 11 none to 1200 none none VVER-1200 water (Russia) U.S. NRC Westinghouse pressurized b b b certified in 650 none none none AP600 water U.S. certified in Westinghouse pressurized b 12 (U.S.) U.S., 1154 none 4 (China) AP1000 water 2 (China) applied in UK a All are fuelled with uranium oxide in zirconium alloy tubes b Earlier designs of these nuclear power plants are in service throughout the world.
Helium-cooled High-temperature Reactors (Table A-3)
The designs for helium-cooled high-temperature reactors are the range 165–300 MWe. The high end of this range comes from a target of 50% thermal efficiency and a maximum reactor capacity of 600 MWth below which natural convection can adequately cool the reactor core in an emergency. Earlier gas coolants (air and carbon dioxide), have been superseded by helium. The high-
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temperature reactor (HTR) is a result of the combination of helium coolant and graphite moderator. The helium gas has a significant technical base due to experience gained in the U.S. with the 40-MWe Peach Bottom and 330-MWe Fort St. Vrain reactors designed by General Atomics. Germany also built and operated the 15-MWe Arbeitsgemeinschaft Versuchsreaktor (AVR) and the 300-MWe Thorium High-Temperature Reactor (THTR) power plants. The operational experience gained from these early gas reactors can be applied to the next generation of nuclear power systems. High- temperature reactor systems are being developed in South Africa, China, Japan, the U.S., and Russia. For more information see World Nuclear Association data (WNA, 2008c).
The fuel for high-temperature reactors requires high fuel enrichment, and consequently they have a higher uranium consumption than light-water reactors. The fuel used in HTRs differs most significantly from LWR fuel in that it is contained in massive quantities of graphite. Also, the fuel consists of small particles (spheres of the order of 0.5 mm in diameter) of uranium oxide or carbide. The particles are coated with thin layers of pyrolytic carbon (pyrocarbon) and silicon carbide, which serve as tiny pressure vessels to contain fission products and fuel. The coated fuel particle is the basic component of the gas-cooled fuel element.
AREVA Antares. The AREVA New Technology based on Advanced gas-cooled Reactors for Energy Supply (ANTARES) reactor is a high-temperature gas-cooled modular reactor. AREVA’s goal is to create a commercially competitive advanced high-temperature reactor to meet future industrial demands for electricity generation and process heat supply. The reactor is 300 MWe and would operate up to 850°C. The reactor fuel is coated particle fuel that may be designed for high burn up (AREVA, 2008a).
General Atomics GT MHR. The Gas Turbine Modular Helium Reactor (GT-MHR) is a graphite-moderated helium-cooled reactor (LaBar, 2002). The fuel consists of spherical fuel particles, each encapsulated in multiple coating layers, formed into cylindrical fuel compacts and loaded into fuel channels in graphite blocks in the reactor core. The GT-MHR is expected to have a very high thermal efficiency of approximately 48% (GA, 2008; Chicago, 2004).
PBMR. The Pebble Bed Modular Reactor (PBMR) is a graphite-moderated, helium-cooled reactor. The reactor uses an efficient Brayton power cycle that eliminates the requirement for a heat exchanger between a primary and secondary cycle. The core is modelled after the German high- temperature gas-cooled technology using spherical fuel elements. New and potentially reusable fuel pebbles are continuously added into the reactor core. The PBMR is designed to refuel while in operation, minimizing down time. The first unit is planned for construction in South Africa under a joint venture led by Eskom. The PBMR is expected to have a high thermal efficiency of approximately 42% (PBMR, 2008; Chicago, 2004).
VHTR. The Very High Temperature Reactor is a Generation IV reactor concept that uses a graphite-moderated nuclear reactor with a once-through uranium fuel cycle. This reactor design envisions an outlet temperature of 1000°C, although materials limitations have made even 900°C look like an aggressive target. The reactor core can be either a prismatic block or a pebble-bed core. The high temperatures enable applications such as process heat or hydrogen production via the thermo- chemical sulphur-iodine cycle (GenIV, 2007). This concept is being developed in the U.S. under the name Next Generation Nuclear Plant.
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Table A-3. Helium-cooled high-temperature reactor nuclear power plant designs U.S. NRC When first Size Coolant and Target Company design plants might (MWe) Fuel Market certification start gas cooled, AREVA Antares 300 NA NA particle fuel electricity helium with (small and General Atomics NA, uranium oxide medium grids) Gas Turbine licensed for 300 fuel inserted NA Modular Helium construction in in a prismatic process heat, Reactor (GT-MHR) Russia graphite core electricity helium with (small and PBMR Ltd uranium oxide medium grids) Pebble Med pebbles for process 2014, 165 NA Modular Reactor coated with heat South Africa (PBMR) carbon and/or applications silicon carbide (e.g, gas cooled, hydrogen) VHTR 300 NA NA particle fuel
Small–medium Reactors (Tables A-4a and A-4b)
Since the largest electricity generating unit in Alberta is 450 MWe, large base-load electric plants may be difficult to integrate into the grid, transportation, and labour infrastructure. The small– medium reactors (also known as grid appropriate reactors) provide electricity in the range of 10–300 MWe. The IAEA defines small as less than 300 MWe (WNA, 2008c). Therefore, this class of reactor may be more suitable for Alberta than conventional light- or heavy-water reactors. Their performance and availability are unclear since none are in operation aside from the Russian KLT-40S used on icebreakers. These reactors have a modular design to simplify on-site construction and make the reactor deployable in areas not suitable for large reactors. Some are small enough to be transported completely as a self-contained unit on a ship, truck, or train.
Because helium-cooled reactors are included in the previous section, the small–medium reactors here are cooled either by pressurized water or liquid metal. The pressurized-water options are similar to the large light-water cooled reactors described below, except smaller. The smaller size generally allows easier heat transfer in accidents.
For liquid metal coolants, lithium, sodium, and potassium are metallic elements that are molten at relatively low temperatures (181°C, 98°C, and 63°C, respectively). As liquids they have excellent coolant properties and do not require high operating pressures as do water or helium coolants. Several countries have had, or still have operate, sodium or sodium-potassium cooled reactors. However, these liquid metals react vigorously with air or water. Therefore, the other liquid metal coolant being considered is lead or lead-bismuth eutectic alloy (melting points of 327°C and 126°C, respectively), which solve the chemical reactivity problem at the cost of having a heavier coolant that is more corrosive. Russia uses lead coolant in some of its submarine reactors.
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Water-cooled
AREVA NP-300. This is a small pressurized-water reactor with uranium oxide fuel. It was developed from the French submarine power plant, has passive safety features, and is to be installed below ground level. It is designed for 100–300 MWe (WNA, 2008c).
Argentina CAREM. This advanced small nuclear power plant is being developed in Argentina at 27 MWe. It uses a standard pressurized-water reactor with uranium oxide fuel, and has inherent safety features (WNA, 2008c).
China NHR-200. This is a small pressurized-water reactor that operates at low temperature and is not designed to produce electricity, but rather for heat production or desalination (WNA, 2008c).
General Atomics TRIGA. The TRIGA reactor is water cooled in a pool geometry with uranium-zirconium hydride fuel. It is in common use as a research reactor. General Atomics has a variation on this concept that would produce electricity (WNA, 2008c).
JAERI MRX. The Japanese Atomic Energy Research Institute is developing the MRX, which is another small pressurized-water reactor that uses standard light-water reactor uranium oxide fuel. It is intended for marine propulsion or small electricity production. Its fuelling cycle is 3.5 years, has a water-filled containment for safety (heat transfer in accidents), and could be deployed within a decade (WNA, 2008c).
NuScale Power. The NuScale was originally developed by Oregon State University through a U.S. Department of Energy grant (OSU, 2008). This is a small light-water reactor that will include off-the-shelf components to facilitate commercialization. The entire reactor is only 2 × 5 meters and will be prefabricated and shipped to the site. The reactor is targeted to serve markets in developing countries (NuScale, 2008). It is designed as a single unit to be installed below ground (WNA, 2008c).
Russia KLT-40S. This is a 35-MWe (gross) pressurized water reactor with uranium aluminum silicide fuel in use on Russian icebreakers. It runs 3–4 years before requiring refuelling. During loss of cooling accidents, natural convection is sufficient (WNA, 2008c).
Russia ABV. A factory-built reactor to be used for electricity (10–12 MWe), located on the ground or on barges. It is similar but smaller than the KLT-40S (WNA, 2008c).
Russia RITM-200. This is planned to be the replacement for the KLT icebreaker reactors. It is larger (55 MWe) and has more inherent safety features (WNA, 2008c).
Russia VBER-300. This [pressurized-water reactor] is a 295–325 MWe unit developed from naval power plants and was originally envisaged in pairs as a floating nuclear power plant. It is designed for 60 year life and 90% capacity factor. It now planned to develop it as a land-based unit with Kazatomprom, with a view to exports, and the first unit will be built in Kazakhstan (WNA, 2008c).‖
S. Korea SMART. The System-integrated Modular Advanced Reactor (SMART) is another small pressurized-water reactor, with a 3-year refuelling cycle and a planned 60-year life. A one-fifth scale plant is under construction (WNA, 2008c).
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Westinghouse IRIS. The International Reactor Innovative and Secure (IRIS) design is a pressurized water reactor under development by a consortium led by Westinghouse (IRIS, 2008; WNA, 2008). A key feature of the IRIS design is the integrated primary system where all primary system components including the steam generators, coolant pumps, and pressurizer, are housed along with the nuclear fuel in a single large pressure vessel. This integral system configuration, although novel, introduces significant design and licensing challenges that are likely to affect near-term deployment. Fuel is standard uranium oxide with slightly higher uranium enrichment to allow fuelling intervals as high as five years at 5% U-235 enrichment (WNA, 2008c).
Liquid Metal-cooled
Japan LSPR. Japan’s long-life small power reactor uses lead-bismuth as its coolant. It would be an integrated sealed unit, delivered in a factor with adequate fuel for 30 years, and then returned. It is envisioned to be 53 MWe (WNA, 2008c).
Japan Rapid-L. This effort includes Toshiba and Japan’s Central Research Institute of Electric Power Industry with funding by the Japan Atomic Energy Research Institute. This is a very small reactor (0.2 MWe) with uranium nitride fuel and lithium and an inert gas as coolant. The fuelling interval would be 10 years, and it would be replaced as a unit (WNA, 2008a).
Hyperion Power Generation. The Hyperion reactor was invented at Los Alamos National Laboratory, and was developed for remote locations. The reactor produces 25 MWe and could be deployed in multiples to produce energy for larger projects. The Hyperion power module is about the size of a hot tub, approximately 1.5 meters wide. The reactor is buried underground, and works like a battery (HPG, 2008). It is liquid potassium cooled and uses uranium hydride fuel.
Russia BREST. This is a lead-cooled reactor with the lead at 540°C. The small version of this concept is designed for 300 MWe; there is also a 1200-MWe version. It uses a uranium-plutonium nitride fuel. A pilot plant is under construction (WNA, 2008b).
Russia SVBR. The Russian lead-bismuth fast reactor (SVBR) is a modest size reactor using a pool of liquid lead-bismuth at 400°–480°C. It could use several types of fuel including enriched uranium or uranium-plutonium and would be factory-made. A prototype by 2015 is envisioned (WNA, 2008b).
Toshiba 4S. Perhaps the most unusual small reactor design is the one being pursued by Japanese conglomerate Toshiba (EIA, 2008; Bryce, 2008). For the past two years, Toshiba has been talking about its 4S (super-safe, small, and simple) reactor (10 MWe) that will be cooled by liquid sodium instead of water. Using sodium allows the reactor to run hotter and avoid using highly pressurized pipes. Toshiba, which owns Westinghouse, claims that the reactor could produce power for $0.05–$0.13/kWh, far cheaper than that from generators powered by diesel engines. The company attracted media attention in 2006 when it began discussing the possibility of locating a small reactor in Galena, Alaska. Toshiba has called its design a nuclear battery that could operate for up to 30 years without refuelling. According to the Nuclear Energy Institute, Toshiba could apply to the U.S. NRC for design certification as soon as next year. The agency says that the design approval for the 4S may not be complete until the end of 2013.
U.S. STAR. The Secure Transportable Autonomous Reactor (STAR) is being developed by Argonne and Lawrence Livermore National Laboratories. It is a lead-cooled fast neutron spectrum reactor with uranium-transuranic nitride fuel. It is small enough to be a single cassette, shipped by rail
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and cooled by natural circulation. The refuelling interval is 15–20 years. It is designed to operate at 578°C and produce 180 MWe (WNA, 2008c).
U.S. SSTAR. The Small STAR (SSTAR) effort includes Toshiba as a collaborator, linking with their 4S concept. Its smaller size means that the steam generator is inside the sealed unit and it would be installed below ground level. The reactor core is only 1 m in diameter and 0.8 m high. It is intended eventually to shift from a steam generator to a Brayton cycle turbine with supercritical carbon dioxide. Prototype envisioned in 2015. SSTAR is designed with a 566°C outlet temperature, producing 20 MWe (WNA, 2008c).
Table A-4a. Small–medium reactor nuclear power plant designs, water-cooled U.S. NRC When first Size Coolant and Company Target Market design plants might (MWe) Fuel certification start electricity, heat, AREVA NP-300 100–300 none unknown desalination pressurized electricity, heat, light water, Argentina CAREM 27 research, none within a decade uranium oxide desalination fuel heat, China NHR-200 0 none unknown desalination none, but the uranium General Atomics non-research 16 zirconium electricity unknown TRIGA TRIGA is in use hydride in many places marine pressurized JAERI MRX 30 propulsion, none within a decade light water, electricity uranium oxide NuScale Power electricity 45 fuel submit 2010 unknown NuScale Reactor (small grids) pressurized in use on Russia KLT-40S 35 water, uranium desalination, none Russian aluminum remote area icebreakers Russia ABV 10–12 silicide fuel power supply none unknown pressurized (located on replacement for Russia RITM-200 55 water, unknown barge) none Russian fuel icebreakers power, district to be built in Russia VBER-300 295–325 heating, Kazakhstan unknown desalination and Russia pressurized one-fifth scale electricity, S. Korea SMART 100 light water, none plant under desalination uranium oxide construction Westinghouse fuel electricity 2015, but International Reactor submit 2010, 100–300 (small–medium appears behind Innovative and Secure obtain 2012 grids) schedule (IRIS)
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Table A-4b. Small–medium reactor nuclear power plant designs, liquid-metal cooled U.S. NRC When first Size Coolant and Target Company design plants might (MWe) Fuel Market certification start Hyperion Power potassium- oil shale Generation cooled, fields, 25 none unknown Hyperion Power uranium electricity Module (HPG) hydride fuel (small grids) lead-bismuth developing Japan LSPR 53 none Unknown cooled countries lithium/inert gas cooled, very small Japan Rapid-L 0.2 None unknown uranium loads nitride fuel lead cooled, pilot plant uranium- Russia BREST 300+ electricity none under plutonium construction nitride fuel lead-bismuth cooled, 2015 Russia SVBR 75–100 uranium or electricity none prototype uranium- plutonium fuel to be Toshiba sodium, electricity submitted to 2013, Galena, Super-Safe, Small, 10+ several being (small grids) U.S. NRC in Alaska and Simple (4S) considered 2009 U.S. Secure Transportable lead-cooled, 180 electricity none unknown Autonomous uranium- Reactor (STAR) transuranic U.S. Small STAR nitride fuel 2015 20 electricity none (SSTAR) prototype
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References
AECL, 2008 Atomic Energy of Canada Limited (2008). ACR-1000 Technical Summary. Retrieved August 21, 2008 from http://www.aecl.ca/Reactors/ACR-1000.htm
AREVA, 2008 AREVA (2008). EPR: the first generation III+ reactor currently under construction. Retrieved August 2008 from http://www.areva-np.com
AREVA, 2008a AREVA (2008). ANTARES: HTR for electricity/process heat generation and ANTARES - The AREVA HTR-VHTR Design. Retrieved August 2008 from http://www.areva-np.com
ATMEA, 2008 ATMEA (2008). The mid-sized Generation III+ PWR you can rely on. Website http://www.atmea-sas.com accessed August 2008.
AUA, 2007 Australian Uranium Association, Russia sets course for major nuclear expansion, AUA Newsletter, 4, July–August 2007, http://www.uic.com.au/ news407.htm
Bryce, 2008 Bryce, R. (2008). Nukes Get Small, Energy Tribune, Featured Stories July 16, 2008, Retrieved August 2008 from http://www.energytribune.com/articles.cfm?aid=948
Chicago, 2004 University of Chicago (2004). The Economic Future of Nuclear Power. Retrieved from http://www.ne.doe.gov/np2010/reports/NuclIndustryStudy- Summary.pdf
DOE, 2004 U.S. Department of Energy (2004). Study of Construction Technologies and Schedules, O&M Staffing and Cost, Decommissioning Costs and Funding Requirements for Advanced Reactor Designs. Prepared by Dominion Energy Inc., Bechtel Power Corporation, TLG, Inc., and MPR Associates, May 2004.
EIA, 2003 Energy Information Administration (2003). Official Energy Statistics from the U.S. Government - CANDU Reactors, data as of October 10, 2003. Retrieved August 2008 from http://www.eia.doe.gov/cneaf/nuclear/page/nuc_reactors/ china/candu.html
EIA, 2008 Energy Information Administration (2008). Official Energy Statistics from the U.S. Government—New Commercial Reactor Designs. Retrieved August 2008 from http://www.eia.doe.gov/cneaf/nuclear/page/analysis/ nucenviss2.html#_ftn12
GA, 2008 General Atomics (2008). GT-MHR—Inherently Safe Nuclear Power for the 21st Century. Websites http://www.gt-mhr.ga.com and http://www.ga.com accessed August 2008.
GE, 2008 General Electric (2008). Advanced Boiling Water Reactor (ABWR) fact sheet and ESBWR fact sheet. Retrieved August 2008 from http://www.gepower.com/ prod_serv/products/nuclear_energy/en/index.htm
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GenIV, 2007 Generation IV International Forum (2007). 2007 Annual Report. Printed by the OECD Nuclear Energy Agency for the Generation IV International Forum.
HPG, 2008 Hyperion (2008), Hyperion Power Generation. Website http://www.hyperionpowergeneration.com/index.html accessed August 2008.
IRIS, 2008 IRIS Official Web Site (2008). IRIS Project Overview. Website http://hulk.cesnef.polimi.it accessed August 2008.
LaBar, 2002 LaBar, M.P. (2002). The Gas Turbine - Modular Helium Reactor: A Promising Option for Near Term Deployment. General Atomics report GA-A23952. Retrieved August 2008 from http://gt-mhr.ga.com/images/ANS.pdf
MHI, 2008 Mitsubishi Heavy Industries (2008). Nuclear Energy Systems Headquarters. Website http://www.mhi.co.jp/en/nuclear/index.html accessed August 2008.
NEI, 2008 Nuclear Energy Institute (2008). Key Issues—New Reactor Designs. Retrieved August 2008 from http://www.nei.org/keyissues/newnuclearplants/ newreactordesigns
News, 2008 American Nuclear Society (2008. Nuclear News, 10th Annual Reference Issue. Vol. 51, No. 3.
NuScale, 2008 NuScale Power Inc. (2008) NuScale Power. Website http://www.nuscalepower.com/home.html accessed August 2008.
OSU, 2008 Oregon State University (2008), Media Release–New Company, reactor Design May Boost Nuclear Energy. Retrieved August 2008 from http://oregonstate.edu/dept/ncs/newsarch/2008/Jul08/nukes.html
PBMR, 2008 Pebble Bed Modular Reactor (Pty) Limited (2008). Future Energy. Website http://www.pbmr.com, accessed August 2008.
Torgerson, 2007 Torgerson, D. (2007). AECL Looks to the Future With the ACR-1000. Electricity Transmission and Distribution Today. Vol. 19, no. 8, October 2007. Retrieved August 2008 from http://www.aecl.ca/Assets/Publications/ET- AECL.pdf
Westinghouse, 2002 Westinghouse (2002). AP600 Background. Website http://www.ap600.com accessed August 2008.
Westinghouse, 2008 Westinghouse (2008). AP10000. Website http://www.ap1000.com accessed August 2008.
WISE, 2008 World Information Service on Energy Uranium Project (2008). World Nuclear Fuel Facilities. Website http://www.wise-uranium.org/efac.html accessed August 2008.
WNA, 2008 World Nuclear Association (2008). Information Papers—Advanced Nuclear Power Reactors. Retrieved August 2008 from http://www.world- nuclear.org/info/inf08.html
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WNA, 2008a World Nuclear Association (2008). Information Papers—Country Briefings, Nuclear Power in Japan. Retrieved August 2008 from http//www.world- nuclear.org/info/inf79.html
WNA, 2008b World Nuclear Association (2008). Information Papers—Country Briefings, Nuclear Power in Russia. Retrieved August 2008 from http://www.world- nuclear.org/info/inf45.html
WNA, 2008c World Nuclear Association (2008). Information Papers—Small Nuclear Power Reactors. Retrieved August 2008 from http://www.world- nuclear.org/info/inf33.html
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APPENDIX B: SYNOPSYS OF THE ACCIDENT AT CHERNOBYL-4
Failure to design for a negative power feedback led to the Chernobyl-4 accident. A positive power feedback occurred at the Chernobyl-4 power plant, which was of the RBMK design (water cooled and graphite moderated). While conducting a safety test, the operators withdrew more control rods than allowed by safety regulations. A design flaw then became clear; the operators had inadvertently put the reactor into a condition that led to positive feedback. The power level increased rapidly, caused a steam explosion, and destroyed the reactor. The lack of a containment structure around the reactor allowed large amounts of radioactivity to escape.
The Chernobyl Forum, led by the International Atomic Energy Agency and World Health Organization, was established in 2003 to understand the health, environmental, and socio-economic consequences (Chernobyl, 2005). The combination of operator error and multiple design flaws such as positive feedback and no containment created what the International Atomic Energy Agency has called the ―foremost nuclear catastrophe in human history.‖
Chernobyl’s consequences are frequently misstated. The Chernobyl Forum notes that ―Claims have been made that tens or even hundreds of thousands of persons have died as a result of the accident. These claims are exaggerated; the total number of people that could have died or could die in the future due to Chernobyl originated exposure over the lifetime of emergency workers and residents of most contaminated areas is estimated to be around 4000 (Chernobyl, 2005).‖
The Forum states that 47 reactor staff and emergency workers have died from high radiation doses and thermal fire burns. Nine children in the area have died from thyroid cancer from ingestion of milk contaminated by radioactive iodine; thyroid radiation exposures could have been reduced by more prompt implementation of emergency off-site notification and protective measures and wider distribution of stable iodine tablets.46 The Chernobyl Forum estimates that another ―3940 people could die from cancer contracted as a result of radiation exposure (Chernobyl, 2005).‖ The contaminated areas of Belarus, Russia, and Ukraine are home to about 5 million people. About 116,000 people were evacuated in the spring and summer of 1986, with a total peak evacuation of about 350,000. A total of 7800 km2 of agricultural land and 6900 km2 of forest have been removed from production.
Radioactive contamination does not last forever. The radioactive iodine (I-131) that was released during the accident is no longer present due to natural decay in the 22 years since the accident. The worst contamination, that from radioactive cesium (Cs-137), continues to decay with a half-life of about 30 years. This means that in 300 years, Cs-137 contamination will reduce itself by a factor of a thousand.
46 Stable iodine ingestion swamps the body’s intake of iodine, reducing the absorption of radioactive iodine and hence reducing radiation exposure if taken at the right time.
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References
Chernobyl, 2005 The Chernobyl Forum (2005). Chernobyl’s Legacy: Health, Environmental and Socio-economic Impacts and Recommendations to the Governments of Belarus, the Russian Federation and Ukraine. International Atomic Energy Agency.
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APPENDIX C: OVERVIEW OF THE ALBERTA RESEARCH COUNCIL AND IDAHO NATIONAL LABORATORY
Alberta Research Council
About ARC
The Alberta Research Council (ARC) is an applied research and development corporation that develops and commercializes technology to grow innovative enterprises. ARC specializes in converting early stage ideas into marketable technology products and services. Since its establishment in 1921, the Alberta Research Council (ARC) has undertaken leading-edge research and transferred the results into practice for the benefit of people in Alberta and beyond. ARC recognizes the importance of seeking out new research prospects that are important to Albertans, and continues to explore opportunities for future long-term development.
Throughout its history, ARC has been a pioneer and world leader in oil sands and heavy oil technology research, developing methodologies that have become industry standards across the globe.
ARC is a not-for-profit corporation that is owned by the province of Alberta and governed by a seven-member board of directors drawn from the private, public, and higher education sectors.
Working to Meet Alberta’s Needs
ARC works with representatives of industry and government to identify and define areas where ARC can strengthen its role as a strategic agent for economic development across Alberta. The work is aimed at meeting Alberta's needs, taking into account national and global trends that include the following:
the increased need for clean, reliable energy, food, and water, the need for improved quality of life (especially for the growing number of elderly persons), the need for enhanced employment opportunities, economic growth and services, and the need for better decision making processes related to the environment.
Integrated Excellence
The sectors that ARC serves include energy, life sciences, agriculture, environment, forestry, and manufacturing. The key lines of business are applied research, technology assessment, technology development, product development, demonstration and scale-up, testing and analysis, technology transfer, and consulting services.
ARC’s multi-discipline integration provides for unique internal teamwork on complex issues that require many different sectors of study. In addition, the ARC has access to specialized facilities
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and experts across the country through Innoventures Canada (I-CAN), a consortium of 10 research organizations across the country.
Community Resource
ARC is in the business of innovation. ARC customers and partners have access to leading edge expertise, equipment, and facilities that no one company could afford on its own. ARC employs more than 600 scientists, engineers, business managers, and support staff who work in one million square feet of facilities spread throughout five Alberta locations: Edmonton (2), Calgary, Vegreville, and Devon. ARC scientists are frequently consulted as unbiased experts by public, private, and government organizations.
Idaho National Laboratory
Idaho National Laboratory (INL) is one of the U.S. Department of Energy's multi-program national laboratories. Based on 890 square miles of land in and near Idaho Falls, Idaho, the laboratory has 3500 scientists, researchers, and support staff. It works with national and international governments, universities, and industry partners to discover new science and develop technologies that underpin the nation's nuclear and renewable energy, national security, and environmental missions. Its core competencies, highlighted below, reflect more than half a century of nuclear energy development and decades of experience in basic and applied science research and applied engineering.
Nuclear reactor design, reactor demonstration and reactor safety. Having designed, constructed and operated 52 nuclear reactors during its 57-year existence, INL understands reactor operations and safety, and is recognized internationally for its expertise in nuclear energy. INL is the leading laboratory in nuclear energy research and applications. National and homeland security. INL leverages its signature capabilities in wireless and communication systems, process control and cyber security, unmanned aerial vehicle platforms and sensors, and explosives testing and detection along with its complex, secure, and remote facilities to provide comprehensive critical infrastructure testing and technology development to government agencies and industrial partners. The lab’s expertise in nuclear research and development allows it to play a vital role in securing the nuclear fuel cycle and preventing the proliferation of weapons of mass destruction. Research, development, and demonstration. INL has an experienced engineering and technical work force to develop, model, test, demonstrate, and validate a variety of engineered systems and processes including fossil energy, and hydrogen production and use. Basic and applied science research. The scientific credentials of INL researchers include earth sciences and environmental engineering, biotechnology, physical systems modeling, systems engineering, intelligent automation and remote systems, applied engineering, materials processing, chemical separations and processing, sensing and diagnostics, surface ionization mass spectrometry, and fusion safety.
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APPENDIX D: ACRONYMS AND ABBREVIATIONS
ABWR advanced boiling water reactor AC alternating current ACR advanced CANDU reactor AECB Atomic Energy Control Board AECL Atomic Energy of Canada Limited AESO Alberta Electric System Operator AHWR advanced heavy-water reactor ALARA as low as reasonably achievable AREVA New Technology based on Advanced gas-cooled Reactors for Energy ANTARES Supply APM adaptive phased management APWR advanced pressurized-water reactor ARC Alberta Research Council AVR Arbeitsgemeinschaft Versuchsreaktor (experimental reactor group) Bq Becquerels CANDU Canada deuterium uranium (reactor) CERI Canadian Energy Research Institute CMD commission member document CNS Canadian Nuclear Society CNSC Canadian Nuclear Safety Commission CNWO Canadian Nuclear Waste Organization Co-59, Co-60 cobalt-59, cobalt-60
CO2 carbon dioxide COG CANDU owners group Cs-137 cesium-137 DC direct current DOE U.S. Department of Energy DUPIC direct use of spent light-water reactor plutonium in CANDUs EA environmental assessment EIS environmental impact statement EPR European Pressurized-water Reactor EPRI Electric Power Research Institute ERCB Energy Resources Conservation Board ESBWR Economic Simplified Boiling Water Reactor FGD flue gas desulphurization GDP gross domestic product GHG greenhouse gas GT-MHR gas turbine modular helium reactor Hg mercury HHV higher heating value
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HRSG heat recovery steam generator HTR high-temperature reactor HVDC high-voltage direct current HW heavy water I-131 iodine-131 IAEA International Atomic Energy Agency IEA International Energy Agency IGCC integrated gasification combined cycle INL Idaho National Laboratory INPO Institute of Nuclear Power Operations IRIS international reactor innovative and secure ISR integrated safety review JAERI Japanese Atomic Energy Research Institute L litres Li-7 lithium-7 LLRW low-level radioactive waste LLRWMO Low-Level Radioactive Waste Management Office LW light water m2 square meters m3 cubic meters MEA monoethanolamine MJ megajoules MMBTU million British thermal units MPa megapascals MW megawatts MWe megawatts of electricity MWh megawatt hours MWth megawatts thermal NEA Nuclear Energy Agency NEI U.S. Nuclear Energy Institute NEPDG National Energy Policy Development Group NETL National Energy Technology Laboratory NGCC natural gas combined cycle NOx nitrogen oxide NRX Nuclear Research Experimental (reactor) NSCA Nuclear Safety Control Act O&M operations and maintenance OECD Organization for Economic Cooperation and Development PBMR pebble bed modular reactor Pu-239 plutonium-239 PV photovoltaic RBMK reaktor bolshoy moshchnosti kanalniy (high-power channel-type reactor)
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SAGD steam assisted gravity drainage SCO synthetic crude oil SCR selective catalytic reduction SMART system-integrated modular advanced reactor
SO2 sulphur dioxide SOx sulphur oxide SSTAR small secure transportable autonomous rector STAR secure transportable autonomous reactor Sv sievert SVBR (Russian lead-bismuth fast reactor) TBD to be determined tBq terabecquerels tCO2eq tonnes of CO2 equivalent Th-232 thorium-232 THTR thorium high-temperature reactor U-235, U-238 uranium-235, uranium-238 USD U.S. dollars USNRC United States Nuclear Regulatory Commission V volts VHTR very-high temperature reactor W watts WANO World Association of Nuclear Operators We watts of electricity Wh watt-hours WNA World Nuclear Association Wth watts thermal yr year, years
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