NES: Nuclear Energy and Sustainability

Nuclear Energy Options for Hydrogen and Hydrogen-based Liquid Fuels Production

Program: 

Type: 

  • TR

RPT. No.: 

1

Authors:: 

B. Yildiz and M.S. Kazimi

Report Date: 

September 2003

Abstract

Nuclear energy can be used for hydrogen production through thermochemical or electrochemical processes for splitting water (and/or steam) into its elemental parts. The overall performance of alternative routes for using nuclear energy to supply the needed heat or electricity depends on the operating temperature, efficiency of the processes involved, complexity of the systems used and capital costs of the nuclear and hydrogen technologies. In this work, we assess the economics of possible technologies to produce hydrogen using nuclear energy. The purpose of this assessment is to identify the most attractive options for further research and development and eventual application to nuclear hydrogen production.

Both thermochemical processes and electrolysis require high temperatures for good efficiency. Thus, hydrogen production is best accomplished using advanced reactors that are capable of reaching much higher temperatures than today's LWRs. At temperatures above 700 oC, the options range from using steam methane reforming in the short term to the much more involved chemical cycles or steam electrolysis in the long term. The helium cooled graphite moderated reactors operating at temperatures above 850 oC have often been proposed for such purposes. However, we find the high temperature steam electrolysis process coupled to a supercritical CO2 gas turbine cycle, possibly in a direct cycle Supercritical Advanced Gas Reactor, as more promising than other technology options. At 650 to 750oC of reactor outlet/turbine inlet/process temperatures, this technology can achieve 52 to 56% overall efficiency in converting nuclear thermal energy into energy content of hydrogen, respectively.

In this work, we also evaluate the technical and economical viability of liquid fuel synthesis using nuclear hydrogen. The liquid fuel can be used in the existing mature infrastructure for transportation and combustion of liquid fuels before large scale hydrogen infrastructure becomes widely established. We propose that CO2 captured from coal plant emissions and nuclear hydrogen be the feedstock to the synthesis process. The cost of this approach would be independent of the natural gas feedstock and may prove market competitive in the near future.

Considering the production cost of hydrogen, the thermochemical Sulfur-Iodide cycle coupled to the helium cooled Modular High temperature Reactor (MHR) is found to be also attractive at temperatures above 850 oC, based on the plant cost and the process efficiency estimates by the designer company. In our work, the cost of production is estimated to fall between $1.13 and 2.37/kg-H2. This range reflects the uncertainties about the operating conditions and cost of the technology in the future.

Hydrogen Production Using High Temperature Steam Electrolysis and Gas Reactors with Supercritical CO2 Cycles

Program: 

Type: 

  • TR

RPT. No.: 

2

Authors:: 

B. Yildiz, K. Hohnholt, and M.S. Kazimi

Report Date: 

December 2004

Abstract

A design evaluation has been performed for an integrated system of high temperature steam electrolysis (HTSE) supported by a supercritical CO2 (SCO2) recompression Brayton cycle that is directly coupled to an advanced gas cooled reactor (AGR). The analysis includes the effects of major components performance parametrically and the component integration systematically for different plant configurations. The configuration (HTSE-SCO2-AGR) with thermal recuperation from the gas product streams and an intermediate heat exchanger (IHX) between the turbine exit and the feed water stream is found to be superior with respect to thermal efficiency, operational flexibility and cost.

HTSE for H2 production provides two major advantages: 1- It can promise higher efficiency (with the appropriate materials and power conversion system for intermediate and high temperature operation of the solid oxide electrolysis cell) compared to the leading high temperature thermo-chemical water splitting cycles and to traditional water electrolysis; 2- It has already been demonstrated experimentally by several groups, based on materials used for solid oxide fuel cells. Thus, there is a potential for improving its performance further with processing of new materials that can minimize the energy losses due to the electrocatalytic mechanisms specific to electrolysis on oxide electrodes.

HTSE energy efficiency depends significantly on the thermal to electrical energy conversion efficiency. The supercritical CO2 recompression Brayton cycle is a strong candidate to enhance the HTSE efficiency due to its high electrical efficiency, comparable with that of He cycle but at significantly lower temperatures (550oC vs 850 oC). In addition, it is expected to reduce the capital cost of the plant due to its simplicity and compactness. The advanced gas cooled reactor, AGR, which has extensive operational experience in the UK, can support a direct SCO2 cycle and provide heat for the HTSE. The SCO2 power conversion system is proposed to couple to the AGR with a direct cycle. This requires a design update of the AGR (which operates at 4MPa) to withstand high pressures (20MPa) and operation near 700oC. An intermediate heat exchanger that provides heat from CO2 at the exit of the turbine to boil feed water for electrolysis is proposed for operational flexibility of adjusting the hydrogen and electricity output. In addition, the IHX at this configuration is subject to less harsh temperature environment than that at the exit of the reactor.

The HTSE average process temperature is chosen as 900oC and the hydrogen pipeline delivery pressure is assumed to be 7MPa for the evaluation of each design configuration in this work. The reactor exit temperature and the SCO2 cycle turbine inlet temperature are chosen to be the same as those for the SCO2 recompression cycle design options for consistency and compatibility. For the base case design, the reactor exit temperature is selected as 550oC, the HTSE operates at 1bar with 80%-90% voltage efficiency, the SCO2 cycle is based on a conservative design and the produced hydrogen is compressed for pipeline delivery. For these operating conditions, the system can achieve 40.4%-43.5% (LHV) overall hydrogen production energy efficiency. When the operating pressure of the HTSE is increased to 3MPa, the system can achieve 42.4%-48.2% (LHV) of hydrogen production energy efficiency, where the range depends on the SCO2 cycle operating conditions and the HTSE materials performance. With improved recuperators and HTSE cells, 7MPa can be expected as a feasible product exit pressure from the HTSE system in the future. The design with HTSE operating at 7MPa can achieve energy efficiency of 41.6%-47.4% (LHV) and eliminate the hydrogen compressor before delivery of the product into the pipeline. The product gas streams remain at relatively high temperatures even after the thermal recuperation in this design. Further thermal recuperation for a bottoming steam cycle, for preheating the water or for providing heat for the SCO2 cycle can be energetically possible. However, none of these alternatives are found viable economically. Process heating by the final product can be possible depending on the proximity to the necessary industry, and is not pursued in this study.

As with all new technology concepts, there are major R&D needs for commercial realization of a recuperative HTSE-SCO2-AGR system. The major needs for HTSE-SCO2-AGR R&D have been identified as: materials processing for the durability and efficiency of the HTSE system at intermediate temperatures, the design update of the AGR with advanced materials to resist high pressure CO2 coolant, thermalhydraulics of CO2 at supercritical pressures, and detailed component design for system integration.

The energy efficiency of the recuperative HTSE-SCO2-AGR as analyzed in this work is more promising than the other leading nuclear hydrogen production technologies. Challenges for this system exist, but appears less difficult than those for the very high temperature thermochemical hydrogen production processes proposed for future VHTRs that have more uncertainties in their development. In the near term, the aim must be to expand the research on this promising technology, as summarized above, in order to have a system available for large scale hydrogen production with confidence and economy.

The Attributes of a Nuclear-Assisted Gas Turbine Power Cycle

Program: 

Type: 

  • TR

RPT. No.: 

3

Authors:: 

Y.H. Jeong, P. Saha, and M.S. Kazimi

Report Date: 

February 2005

Abstract

By using a combination of a nuclear reactor, which emits no carbon dioxide, and a high efficiency natural gas turbine combined cycle (NGCC), electric utilities can reduce their generation cost as well as minimize the greenhouse gas emissions. In this work, the economic competitiveness of pure NGCC, nuclear assisted NGCC and pure nuclear power plants are studied.

An advanced gas cooled nuclear reactor can be added to the conventional NGCC as a heat source for the air exiting the compressor. For this study we assumed a high temperature pebble bed modular reactor (PBMR) with reactor outlet gas temperature of 900ºC. With that temperature, the thermal contribution (fossil fuel savings and CO2 reduction) of nuclear energy in the nuclear-assisted NGCC cycle was 46.3%.

For assessing the economic competitiveness of the three options, the levelized electricity generation costs were calculated. The economics depend on the cost of natural gas and the capital cost of the nuclear reactor. Obviously, the best option for low natural gas cost is the pure NGCC, whereas the pure nuclear power is the best choice for high natural gas prices. The crossing points vary depending on the level of expected carbon tax. The pure nuclear option is not affected by the level of carbon tax. The nuclear-assisted NGCC cost is in the middle.

There are several synergetic effects to using nuclear and fossil powers together. First, since the generation cost of the nuclear-assisted NGCC cycle is not as sensitive to the gas price as the NGCC, the economic risk of an NGCC plant can be minimized by adopting a nuclear-assisted NGCC cycle. Second, by introducing NGCC to nuclear power, the risk from high nuclear capital cost can be mitigated. For example, 3000 $/kWe of nuclear capital cost can be reduced to about 1500 $/kWe. Third, in addition to minimizing the risk from gas price fluctuation and high capital cost, even though the window is very narrow, the nuclear assisted NGCC can be more advantageous over the other two options in case of high nuclear capital costs and high gas prices.

Finally, green house gas emissions can be reduced significantly using nuclear assisted NGCC.

Optimization of the Hybrid Sulfur Cycle for Hydrogen Generation

Program: 

Type: 

  • TR

RPT. No.: 

4

Authors:: 

Y.H. Jeong, M.S. Kazimi, K.J. Hohnholt, and B. Yildiz

Report Date: 

May 2005

Abstract

The hybrid sulfur cycle (modified from the Westinghouse Cycle) for decomposing water into oxygen and hydrogen is evaluated. Hydrogen is produced by electrolysis of sulfur dioxide and water mixture at low temperature, which also results in the formation of oxygen and sulfuric acid. The sulfuric acid is decomposed into steam and sulfur trioxide, which at high temperature (1100 K) is further decomposed into sulfur dioxide and oxygen.

The presence of sulfur dioxide along with water in the electrolyzer reduces the required electrode potential well below that required for electrolysis of pure–water, thus reducing the total energy consumed by the electrolyzer. Further, using only sulfuric acid for the thermochemical processes minimizes the required chemical stock in the hydrogen plant well below that required for the sulfur–iodine pure thermochemical cycle (SI cycle).

In this study, ways to optimize the energy efficiency of the hybrid cycle are explored by varying the electrolyzer acid concentration, decomposer acid concentration, pressure and temperature of the decomposer and internal heat recuperation, based on currently available experimental data for the electrode potential.

An optimal cycle efficiency of 43.9% (LHV) appears to be achievable (5 bar, 1100 K and 60 mol–% of H2SO4 at the decomposer, 70 w–% of H2SO4 at the electrolyzer). However, the ideal cycle efficiency is over 70% (LHV), which leaves room to improve the achievable efficiency with further development. For a maximum temperature of 1200 K, 47% (LHV) appears to be the maximum achievable cycle efficiency (10 bar, 1200 K and 60 mol–% of H2SO4 for decomposer, 70 w–% of H2SO4 for electrolyzer). The ideal cycle efficiency is over 80% (LHV). Operation under elevated pressures (70 bar or higher) results in minimized equipment size and capital cost, but there is loss in thermal efficiency. However, the loss in efficiency as pressure increases is not large at high temperature (1200 K) compared to that at low temperatures (1000–1100 K). Therefore, high pressure operation would be favored only if we can achieve high temperature. The major factors that can affect the cycle efficiency are reducing the electrode over–potential and having structural materials that can accommodate operation at high temperature and high acid concentration.

Nuclear Technology and Canadian Oil Sands: Integration of Nuclear Power and in situ Oil Extraction

Program: 

RPT. No.: 

5

Authors:: 

G. Becerra, E. Esparza, A. Finan, E. Helvenston, S. Hembrador, K. Hohnholt, T. Khan, D. Legault, M. Lyttle, K. Miu, C. Murray, N. Parmar, S. Sheppard, C. Sizer, E. Zakszewski, K. Zeller

Report Date: 

December 2005

Abstract

This report analyzes the technical aspects and the economics of utilizing nuclear reactor to provide the energy needed for a Canadian oil sands extraction facility using Steam-Assisted Gravity Drainage (SAGD) technology. The energy from the nuclear reactor would replace the need for energy supplied by natural gas, which is currently burned at these facilities. There are a number of concerns surrounding the continued use of natural gas, including carbon dioxide emissions and increasing gas prices. Three scenarios for the use of the reactor are analyzed: using the reactor to produce only the steam needed for the SAGD process; using the reactor to produce steam as well as electricity for the oil sands facility; and using the reactor to produce steam, electricity, and hydrogen for upgrading the bitumen from the oil sands to syncrude, a material similar to conventional crude oil. The report shows that nuclear energy would be feasible, practical, and economical for use at an oil sands facility. Nuclear energy is two to three times cheaper than natural gas for each of the three scenarios analyzed. Also, by using nuclear energy instead of natural gas, a plant producing 100,000 barrels of bitumen per day would prevent up to 100 megatonnes of CO2 per year from being released into the atmosphere.

An Alternative to Gasoline: Synthetic Fuels from Nuclear Hydrogen and Captured CO2

Program: 

Rev.: 

2

Type: 

  • TR

RPT. No.: 

6

Authors:: 

B.D. Middleton and M.S. Kazimi

Report Date: 

April 2007

Abstract

The motivation for this study stems from two concerns. The first is that carbon dioxide from fossil fuel combustion is the largest single human contribution to global warming. The use of nuclear power to produce hydrogen on a global scale for any of various possible end uses would reduce the net amount of carbon dioxide emitted into the atmosphere. The second concern is in regard to U.S. dependence on foreign oil. Over 58% of petroleum used by the US in 2002 was imported and most likely a higher fraction is being imported today. With the majority of this oil originating in highly volatile Middle Eastern countries, there is a potential threat to stability in the US energy market.

This study was conducted to determine the extent to which nuclear power can contribute to a transition in the transportation sector; away from an infrastructure that places the US at risk for depending largely on foreign oil and that makes it inevitable that large quantities of carbon dioxide will be emitted into the atmosphere. Several scenarios are reviewed in this study for using nuclear hydrogen in transportation, including:

  • Combining hydrogen with carbon dioxide captured from fossil fired plants to produce liquid fuel
  • Using nuclear power to aid in the recovery of oil from tar sands or shale oil

Initially, a review of the literature pertaining to the potential contribution of nuclear power to hydrogen production is performed. Two approaches for producing hydrogen from water are found that have significant literature related to the subject. These cycles are High Temperature Steam Electrolysis and the Sulfur Iodine Cycle. The UT-3 cycle is also promising but does not seem to offer the same advantages with respect to energy efficiency. This work focuses on the High Temperature Steam Electrolysis option. 

A review of possible nuclear reactor concepts is also performed. Many advanced concepts have been proposed, a large number of which show potential in producing hydrogen. However, there are drawbacks to many of them for several reasons. The high temperatures needed eliminate some reactors while lack of operational experience eliminates others. Ultimately, the two concepts that are proposed for hydrogen production in the literature found are the High-Temperature Gas Cooled Reactor (HTGR), which uses Helium coolant, and a modified version of the Advanced Gas Reactor (AGR) using supercritical CO2 as the coolant (S-AGR). The reactor concepts that are chosen for aiding production of oil from tar sands are the Advanced Candu Reactor (ACR-700), the Pebble Bed Modular Reactor (PBMR), and the Advanced Passive pressurized water reactor (AP600).

A detailed study of how nuclear power can contribute to production of shale oil has not been performed. Therefore, the section dealing with this particular possibility is much less in depth and more speculative. However, some preliminary calculations are performed and presented in this report.

Based on the reference year 2025 case, we find that the United States will need about 6.60 billion barrels of ethanol (EtOH) or 8.77 billion barrels of methanol (MeOH) in order to replace the conventional gasoline (CG) that will otherwise be used. About 39.4% of the CO2 that is projected to be emitted from coal plants will need to be captured to produce this much EtOH and about 41.1% of the CO2 will need to be captured to produce the needed MeOH. For production of EtOH, we estimate that there will need to be between 700 and 900 GWth of nuclear power to produce the needed hydrogen and energy to create this amount of EtOH. By the same token, it will take between 1000 and 1400 GWth of nuclear power to aid in production of the needed MeOH.

In the same year – 2025 – the entire world will require 16.87 billion barrels of EtOH or 22.49 billion barrels of MeOH to replace the CG that will otherwise be used. This would require capture of 29.5% of total emitted CO2 for production of EtOH or 28.4% for production of MeOH. This amount of hydrogen and the associated energy requirements will demand between 1800 and 2300 GWth to produce the needed EtOH or between 2550 and 3500 GWth to produce the needed MeOH.

These numbers show that there is a very wide market for using nuclear power to aid in the production of alternative fuels to aid in the transition to the hydrogen economy. The large fraction of emitted CO2 that need to be captured shows that a benefit of this process would be to significantly decrease the total greenhouse gas emissions. A total cycle analysis reveals that the total reduction in CO2 emissions in the U.S. will be slightly more than 20% for either ethanol use or methanol use. A second benefit would be to decrease a nation’s dependence on imported petroleum.

In conclusion, it is found that the concept of alternative liquid fuels produced from nuclear hydrogen and captured carbon dioxide is viable. There is abundant CO2 for use and the hydrogen can be produced with proven technology. There is also evidence that nuclear power can be utilized in the production of oil from sand and shale. 

Hydrogen Production Steam Electrolysis Using a Super-critical CO₂-Cooled Fast Reactor

Program: 

Type: 

  • TR

RPT. No.: 

7

Authors:: 

M.J. Memmott, M.J. Driscoll, M.S. Kazimi, P. Hejzlar

Report Date: 

February 2007

Abstract

Rising natural gas prices and growing concern over CO2 emissions have intensified interest in alternative methods for producing hydrogen. Nuclear energy can be used to produce hydrogen through thermochemical and/or electrochemical processes.

This report investigates the feasibility of high temperature steam electrolysis (HTSE) coupled with an advanced gas-cooled fast reactor (GFR) utilizing supercritical carbon dioxide (S-CO2) as the coolant. The reasons for selecting this particular reactor include fast reactor uranium resource utilization benefits, lower reactor outlet temperatures than helium-cooled reactors which ameliorate materials problems, and reduced power conversion system costs.

High temperature steam electrolysis can be performed at conditions of 850°C and atmospheric pressure. However, compression of the hydrogen for pumping through pipes is unnecessary if electrolysis takes place at around 6 MPa. The reactor coolant at 650°C is used to heat the steam up to temperatures ranging between 250°C and 350°C, and the remaining heat is provided by thermal recuperation from product hydrogen and oxygen. Several different methods for integrating the hydrogen production HTSE plant with the GFR were investigated. The two most promising methods are discussed in more detail: extracting coolant from the power conversion system (PCS) turbine exhaust to boil water, and extracting coolant directly from the reactor using separate water boiler (WB) loops. Both methods have comparable thermal to electricity efficiencies (~43%) at 650°C. This relates to an overall hydrogen production efficiency of about 47%. The approach which utilizes separate WB loops has the added advantage of being able to provide emergency cooling to the reactor, and also the benefit of not interfering with the operation of the PCS. This makes the separate WB loop integration method a more desirable scheme for hydrogen production using HTSE.

The HTSE electrolysis unit adopted for the present analysis was designed by Ceramatec in coordination with INL. In this unit the steam flows into an electrolytic cell. It is separated by electron flow from a nickel-zirconium cathode to a strontium-doped lanthanum manganite anode. The optimal conditions for stack operation have been found by INL using various modeling and experimental techniques. These conditions include a 10% by volume flow of hydrogen in the feed, a stack operating temperature of 800°C, and an operating voltage of 1.2 V.

The GFR integrated with the HTSE plant via separate water boiler loops was modeled in this work using the chemical engineering code ASPEN. The results of this model were benchmarked against the Idaho National Lab (INL) process,  modeled using HYSIS. Both models predict a hydrogen production rate of ~10.2 kg/sec (± 0.2 kg/sec) for a 600 MWth reactor with an overall efficiency ranging between 47%-50%.  The highly recuperated HTSE plant developed for the GFR can in principle be used in conjunction with a variety of other nuclear reactors, without requiring high reactor coolant outlet temperatures.

Public Attitudes Toward America’s Energy Options: Insights for Nuclear Energy

Program: 

Type: 

  • TR

RPT. No.: 

8

Authors:: 

S. Ansolabehere

Report Date: 

October 2021

Abstract

In 2002, as part of the MIT study on The Future of Nuclear Power, the first MIT Energy survey investigated public attitudes toward nuclear power in light of other sources of electric power. The survey found cost and environmental harm to be key drivers behind public preferences regarding energy sources. In February 2007, the survey was repeated using similar sampling methodologies and the same core questionnaire, augmented by questions about global warming, waste treatment, and transfer of nuclear technology.

Public preferences exhibit considerable stability in the five years between surveys. Americans hold extremely optimistic views of alternative energy sources – solar, wind, and hydroelectric – especially as far as price is concerned. They have more realistic views of traditional fuels – fossil fuels plus nuclear power. In the aggregate, public opinion continues to reflect the relative pricing and environmental harm of these energy sources. Cost and harm, in turn, strongly influence public desires to expand or reduce different energy sources. Concern about global warming rose somewhat from 2002 to 2007, but remains only weakly associated with preferences about electricity generation.

The most notable change in survey responses is the decline of oil’s popularity. Americans now strongly wish to reduce the use of oil, and they view this energy source less favorably than any other source of power. Coal, seen as moderately priced but very harmful to the environment, also remains quite unpopular. Five years ago, nuclear power was viewed similarly poorly; it now seems to have gained modestly in support and is approaching natural gas in terms of favorability.

Integration of Nuclear Energy with Oil Sands Projects for Reduced Greenhouse Gas Emissions and Naturaly Gas Consumption

Program: 

Type: 

  • TR

RPT. No.: 

9

Authors:: 

A.F. Bersak, A.C. Kadak

Report Date: 

August 2007

Abstract

The oil sands of Alberta are a huge natural resource and bitumen production has expanded dramatically in the past five years as the price of oil has risen to record levels. Bitumen recovery from oil sands deposits involves either strip mining the sands and extracting the oil, or pumping large quantities of steam into the ground to free the bitumen from the sand which is then pumped above ground for upgrading. Traditionally, the energy to produce the steam and hot water used in these processes has come from natural gas. The use of increasingly large amounts of natural gas for oil sands recovery presents a number of economic and environmental problems. Steam generation and upgrading processes will contribute large amounts of greenhouse gas emissions while Canadian and regional environmental policies seek long term reductions. Large planned increases in natural gas consumption will cause western Canada to become a net importer of gas, with potentially serious impacts on regional natural gas pricing and market volatility. This is likely to impact not only the profitability of the oil sands business but also the price and availability of natural gas to home owners, commercial uses and other industries.

This paper explores the feasibility and economics of using nuclear energy to power future oil sands production and upgrading activities. Although more expensive to build than conventional facilities, nuclear reactors produce no greenhouse gas emissions and offer relatively low and stable fuel and operating costs. Although uranium has been subject to recent price increases as a result of improved operation of existing reactors and plans for new plants, nuclear energy production costs are relatively insensitive to uranium costs. There are, however, several trade-offs. This paper compares the benefits and the drawbacks, and puts forth several nuclear energy application scenarios for steam or steam and electricity for upgrading bitumen from both in-situ and surface mining operations.

This review includes the Enhanced CANDU 6, the Advanced CANDU Reactor (ACR) and representing high temperature gas reactor technology, the Pebble Bed Modular Reactor (PBMR) which represents the first advanced high temperature gas reactor technology to become commercially available within the next decade. Based on reasonable projections of available cost information, nuclear energy used for steam production is expected to be less expensive than steam produced by natural gas at current natural gas prices. For electricity production, nuclear becomes competitive with natural gas plants at natural gas prices of $10-13/MMBtu (CAD). Costs of constructing nuclear plants in Alberta are affected by higher local labor costs which this paper took into account in making these estimates. Although more definitive analysis of construction costs and project economics will be required to confirm these findings, there appears to be sufficient merit in the potential economics to support further study.

The primary environmental benefit of nuclear energy in this application is to reduce CO2 emissions by up to 3.1 million metric tons per year for each 100,000 barrel per day (bpd) bitumen production Steam Assisted Gravity Drainage facility, or 2.0 million metric tons per year for the replacement of 700MWe of grid electricity with a nuclear power plant. The potential impact on future regional gas markets can be dramatic considering that natural gas use to support current plans for oil industry expansion through the year 2020 represents 20% of projected western Canadian gas production.

A single PBMR reactor is able to supply high pressure steam for a 40,000 to 60,000 bpd SAGD plant, whereas the CANDU and ACR reactors are too large and unable to produce sufficient steam pressures to be practical in that application. A single module PBMR cogenerating its own power requirements can supply steam for SAGD operations from 30,000 to 50,000 bpd in size.1 The CANDU, ACR and PBMR reactors have potential for supplying heat and electricity for surface mining operations.

Key challenges to deployment of new nuclear plants in Alberta include obtaining public acceptance, achieving acceptable construction costs, transportation of large components, resolving workforce issues and addressing nuclear licensing requirements. All would require an integrated planning process to address the prerequisites to make nuclear energy a realistic option in the near future. Recommendations are provided which include development of conceptual designs of specific nuclear energy oil sands applications; developing and implementing a public information program; the development of an integrated oil sands energy strategy including nuclear to address electricity, work force issues, natural gas supply, greenhouse gas reductions and licensing such that nuclear energy can be a viable option for the future.

A number of current initiatives have been announced that will consider options to utilize bitumen derived fuels in advanced gasification systems with CO2 capture and sequestration. Since nuclear energy can be an alternative to these projects which are also capital intensive and challenging, a study comparing nuclear options with other proposals to address future gas supply constraints and options for achieving greenhouse gas reductions would be beneficial. With the possible imposition of carbon taxes, limits on natural gas availability, or restrictions on natural gas use, it would be prudent to begin to seriously investigate nuclear energy as an alternative to growing utilization of natural gas and expensive carbon capture schemes using bitumen or coke gasification. If the oil sands development plans currently being discussed are implemented in the 2017 to 2020 timeframe, should nuclear energy be used instead of natural gas, the total reduction in CO2 emissions could be as high as 745 million metric tons over the lifetime of the operation.

In summary, nuclear energy applications appear to be well suited for long term oil sands production and are likely to provide an economically competitive, CO2 emission free option to greatly help Canada in meeting its Kyoto greenhouse gas emission commitments and reduce pressure on limited regional gas supply, allowing more responsible development of its rich oil sands resources.

Nuclear Hydrogen Using High-Temperature Electrolysis and Light-Water Reactors for Peak Electricity Production

Program: 

Type: 

  • TR

RPT. No.: 

10

Authors:: 

C. W. Forsberg, and M. S. Kazimi

Report Date: 

April 2009

Abstract

In a carbon-dioxide constrained world, the primary methods to produce electricity (nuclear, solar, wind, and fossil fuels with carbon sequestration) have low operating costs and high capital costs. To minimize the cost of electricity, these plants must operate at maximum capacity; however, the electrical outputs do not match changing electricity demands with time. A system to produce intermediate and peak electricity is described that uses light-water reactors (LWRs) and high-temperature electrolysis. At times of low electricity demand the LWR provides steam and electricity to a high-temperature steam electrolysis system to produce hydrogen and oxygen that are stored. At times of high electricity demand, the reactor produces electricity for the electrical grid. Additional peak electricity is produced by combining the hydrogen and oxygen by operating the high-temperature electrolysis units in reverse as fuel cells or using an oxy-hydrogen steam cycle. The storage and use of hydrogen and oxygen for intermediate and peak power production reduces the capital cost, increases the efficiency of the peak power production systems, and enables nuclear energy to be used to meet daily, weekly, and seasonal changes in electrical demand. The economic viability is based on the higher electricity prices paid for peak-load electricity. Significant development work is required before the technologies will be commercially deployable.

 

Pages

Subscribe to NES: Nuclear Energy and Sustainability