https://hdl.handle.net/1721.1/67476 Thu, 09 Apr 2026 09:01:28 GMT 2026-04-09T09:01:28Z https://hdl.handle.net/1721.1/75135 An Alternative to Gasoline: Synthetic Fuels from Nuclear Hydrogen and Captured CO[subscript 2] Middleton, B. D.; Kazimi, Mujid S. 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 CO[subscript 2] 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 CO[subscript 2] 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 CO[subscript 2] 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 CO[subscript 2] 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 CO[subscript 2] 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 CO[subscript 2] 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. Revision 2 Sun, 01 Apr 2007 00:00:00 GMT https://hdl.handle.net/1721.1/75135 2007-04-01T00:00:00Z https://hdl.handle.net/1721.1/75126 Nuclear Energy for Variable Electricity and Liquid Fuels Production: Integrating Nuclear with Renewables, Fossil Fuels, and Biomass for a Low- Carbon World Forsberg, Charles W. The world faces two energy challenges: (1) the national security and economic challenge of dependence on foreign oil and (2) the need to reduce carbon dioxide emissions from the burning of fossil fuels to avoid climate change. Nuclear energy as a low-carbon domestic source of energy can address both challenges. However, nuclear energy in the United States is only used for base-load electricity production—about a quarter of the total energy demand. To address the two energy challenges, we have initiated a series of studies to understand long-term nuclearrenewable energy futures for a low-carbon world that can meet all energy demands. This includes liquid fossil fuel options with low greenhouse gas releases. This is a first effort to synthesize what has been learned about hybrid energy systems. The electricity challenge is to provide variable electricity production to match demand. Today this is primarily accomplished with variable-load fossil plants burning stored coal, oil, and natural gas. It is an economic option because of the low cost of storing fossil fuels and the relatively low cost of fossil power plants. The output of nuclear and renewable electricity sources do not match electricity demand. In a low-carbon world it would be required to store electricity when excess electricity is available to meet demand at times of low electricity production. If there are restrictions on carbon dioxide emissions, economics favors nuclear for most electricity production unless renewable electricity production costs are significantly lower than nuclear electricity production costs. This is because the amount of electricity that has to be stored to match electricity production with demand is much smaller in an all-nuclear system than any renewable system1. About two-thirds of all electricity demand is base-load electricity where the steady-state electricity output of a nuclear plant matches customer demand. While there are many electricity storage technologies to help match electricity production with demand over a period of a day (smart grid, pumped hydroelectric storage, batteries, etc.), only two seasonal energy storage technologies were identified2: nuclear geothermal heat storage and hydrogen. A nuclear renewables electricity system that also produces hydrogen for industrial markets may enable an economic system for variable electricity production where a larger fraction of the electricity can be produced by wind and solar energy sources. Nuclear energy can reduce greenhouse emissions from gasoline, diesel and jet fuel by replacing fossil fuels used in the production and refining processes. In the context of increasing U.S. oil production, a primary need is for heat to recover heavy oil and shale oil. U.S. shale oil resources exceed total oil produced worldwide to date and thus their use could eliminate U.S. dependence on foreign oil. The recovery and conversion of shale oil into liquid fuels using heat from nuclear reactors may have the lowest carbon dioxide releases per liter of fuel of all the fossil fuel alternatives to conventional crude oil production. Unlike almost all other industrial processes, shale oil and heavy oil production do not require steady-state heat input. That characteristic would allow nuclear plants coupled to shale oil and heavy oil production to operate at base-load with variable heat and electricity production. The variable electricity production could help match electricity production to demand and enable the larger-scale use of renewables. Heavy oil and shale oil production are the only potential industries large enough where variable heat demand is the alternative to energy storage to match electricity production with demand. Very little research has been done on these options. There is the potential for nuclear biofuels to supply a major fraction of the liquid fuels demand. This option results in no net addition of greenhouse gases to the atmosphere. Liquid fuels from biomass are limited by the availability of biomass. Synergisms between nuclear and biofuels can enable up to three times as much liquid fuel to be produced per ton of biomass. This is achieved by using nuclear to provide heat and hydrogen to operate the biorefinery and thus avoid the use of biomass as a fuel for the biorefinery. Liquid fuels can also be made from air and water with heat and electricity from nuclear power plants. This option can provide unlimited liquid fuel and places an upper cap on the cost of liquid fuels—2 to 3 times that of the cost of electricity on a unit heat basis. Key enabling technologies for a low-carbon nuclear-renewable energy system include nuclear-geothermal gigawatt-year energy storage, high-temperature electrolysis for hydrogen production, use of nuclear heat for reservoir heating of heavy oils and shale oil, conversion of lignin (the non-cellulosic component of plants) to liquid fuels, and densification of biomass for economic transport of biomass to large biorefineries. Most applications can be met with light water reactors; but some applications require the commercialization of high-temperature reactors. A nuclear renewables energy future is possible and potentially economic. Nuclear and renewable energy sources have different characteristics and in some systems are synergistic. Allnuclear or all-renewables energy futures are more expensive and difficult to achieve. Wind and solar economics are strongly dependent on location—particularly latitude because (1) it drives variable seasonal energy demands and (2) wind and solar inputs are functions of latitude. The analysis herein is for the United States but would be generally applicable for countries at similar or higher latitudes.3 Little work has been done to develop credible low-carbon energy futures for a prosperous world of 10-billion people. The uncertainties are very large. Thu, 01 Sep 2011 00:00:00 GMT https://hdl.handle.net/1721.1/75126 2011-09-01T00:00:00Z https://hdl.handle.net/1721.1/75125 Conceptual Design of Nuclear-Geothermal Energy Storage Systems for Variable Electricity Production Lee, Youho; Forsberg, Charles W. Nuclear plants have high capital costs and low operating costs that favor base-load operation. This characteristic of nuclear power has been a critical constraint that limits the portion of nuclear power plants in a grid to stay below the base-load demand. A novel gigawatt-year thermal-energy storage technology is proposed to enable base load nuclear plants to produce variable electricity to meet seasonal variations in electricity demand. A large volume of underground rock is heated with hot water (or steam or carbon dioxide) from a nuclear power plant during periods of low electricity demand, and the heat is extracted during times of high demand and converted to electricity using a standard geothermal plant (Figure 1). Among various technical options, technically mature ones were selected for the reference design; a Pressurized Water Reactor (PWR) injects hot fluid into an underground reservoir through an intermediate heat exchanger and bypass flow lines on either the primary or secondary side. The reservoir size of 500 m in each dimension at 1.5 km underneath the surface is engineered to have permeability of 2 Darcy using commercial hydraulic fracture methods, and is cyclically heated up and cooled down between the temperatures of 50°C and 250°C. Peak power electricity is produced by exploiting the stored thermal energy via an Enhanced Geothermal System (EGS) that employs a binary flash cycle. Models of a nuclear-EGS system performance, taking into account heat transfer in the reservoir, thermal front velocity in the reservoir, conductive heat & water losses, geothermal power plant electricity production performance, operating conditions and system interfaces were developed and independently compared with Computational Fluid Dynamics (CFD) simulations using FLUENT 6.3 to confirm the validity of the models. The design study with the validated models reveals that the reference nuclear-EGS system based on 2.8~6.0 GW(th) of nuclear power would have a thermal storage size of 0.7~1.5 GW(th)-year, which corresponds to 0.08~0.2 GW(e)-year with electricity round trip efficiency of 0.34~0.46. Reservoir permeability and geofluid temperature are found to be the most important design parameters that affect performance of nuclear-EGS storage systems. A grid that deploys a nuclear-EGS system will have three distinct electricity sectors: nuclear base load, EGS intermediate load, and gas turbine peak power. The nuclear-EGS storage system introduces economic benefits to a grid by leveraging economic gains arising from replacing expensive intermediate and peak electricity with cheap base-load electricity. A nuclear-EGS system has a higher capital cost than natural gas turbines; consequently, it replaces intermediate-load power plants but not all the gas turbines that operate for a small number of hours per year. It was found that the deployment of a operate for a small number of hours per year. It was found that the deployment of a Nuclear-EGS could cut the electricity production cost of the New England Independent Systems Operator (NE-ISO) by as much as 14% of the storage-free cost (Fig. 2). Economic competitiveness of nuclear power plants is the most decisive factor for the deployment of the system in a grid. Because this was the first analysis of a nuclear EGS system, we used off-the-shelf technology wherever possible to reduce uncertainties and have confidence that the system will work. Significant improvements in roundtrip efficiency and economics may be possible by development of more advanced systems. For example, existing geothermal power plants are small (megawatts) versus several hundred megawatts for a nuclear EGS system. They use double flash power systems. The larger scale may enable the use of triple-flash and other more efficient power cycles. Reservoir development methods designed explicitly for nuclear EGS systems may significantly lower the costs of reservoir development. Like any other system dependent upon geology, costs and performance will depend upon the local geology. Wed, 01 Jun 2011 00:00:00 GMT https://hdl.handle.net/1721.1/75125 2011-06-01T00:00:00Z https://hdl.handle.net/1721.1/75124 Nuclear Tanker Producing Liquid Fuels From Air and Water: Applicable Technology for Land-Based Future Production of Commercial Liquid Fuels Galle-Bishop, John Michael; Driscoll, Michael J.; Forsberg, Charles W. Emerging technologies in CO[subscript 2] air capture, high temperature electrolysis, microchannel catalytic conversion, and Generation IV reactor plant systems have the potential to create a shipboard liquid fuel production system that will ease the burdened cost of supplying fuel to deployed naval ships and aircraft. Based upon historical data provided by the US Navy (USN), the tanker ship must supply 6,400 BBL/Day of fuel (JP-5) to accommodate the highest anticipated demand of a carrier strike group (CSG). Previous investigation suggested implementing shipboard a liquid fuel production system using commercially mature processes such as alkaline electrolysis, pressurized water reactors (PWRs), and methanol synthesis; however, more detailed analysis shows that such an approach is not practical. Although Fischer-Tropsch (FT) synthetic fuel production technology has traditionally been designed to accommodate large economies of scale, recent advances in modular, microchannel reactor (MCR) technology have to potential to facilitate a shipboard solution. Recent advances in high temperature coelectrolysis (HTCE) and high temperature steam electrolysis (HTSE) from solid oxide electrolytic cells (SOECs) have been even more promising. In addition to dramatically reducing the required equipment footprint, HTCE/HTSE produces the desired synthesis gas (syngas) feed at 75% of the power level required by conventional alkaline electrolysis (590 MW[subscript e] vs. 789 MW[subscript e]). After performing an assessment of various CO[subscript 2] feedstock sources, atmospheric CO[subscript 2] extraction using an air capture system appears the most promising option. However, it was determined that the current air capture system design requires improvement. In order to be feasible for shipboard use, it must be able to capture CO[subscript 2] in a system only ¼ of the present size; and the current design must be modified to permit more effective operation in a humid, offshore environment. Although a PWR power plant is not the recommended option, it is feasible. Operating with a Rankine cycle, a PWR could power the recommended liquid fuel production plant with a 2,082 MW[superscript th] reactor and 33% cycle efficiency. The recommended option uses a molten salt-cooled advanced high temperature reactor (AHTR) coupled to a supercritical carbon dioxide (S-CO[subscript 2]) recompression cycle operating at 25.0 MPa and 670°C. This more advanced 1,456 MWth option has a 45% cycle efficiency, a 42% improvement over the PWR option. In terms of reactor power heat input to JP-5 combustion heat output, the AHTR is clearly superior to the PWR (31% vs. 22%). In order to be a viable concept, additional research and development is necessary to develop more compact CO[subscript 2] capture systems, resolve SOEC degradation issues, and determine a suitable material for the molten salt/S-CO[subscript 2] heat exchanger interface. Wed, 01 Jun 2011 00:00:00 GMT https://hdl.handle.net/1721.1/75124 2011-06-01T00:00:00Z https://hdl.handle.net/1721.1/75123 Nuclear-Renewables Energy System for Hydrogen and Electricity Production Haratyk, Geoffrey; Forsberg, Charles W.; Driscoll, Michael J. Climate change concerns and expensive oil call for a different mix of energy technologies. Nuclear and renewables attract attention because of their ability to produce electricity while cutting carbon emissions. However their output does not match demand. This thesis introduces a nuclear-renewables energy system, that would produce electricity and hydrogen on a large scale while meeting the load demand. The system involves efficient high temperature electrolysis (HTE) for hydrogen production, with heat provided by nuclear and electricity by the grid (nuclear and/or renewables). Hydrogen production would be variable, typically at time of low demand for electricity and large power generation from renewables. Hydrogen would be stored underground on site for later shipping to industrial hydrogen users by long-distance pipeline or for peak power production in fuel cells. A hydrogen plant was designed, and the economics of the system were evaluated by simulating the introduction of the system in the Dakotas region of the United States in both a regulated and a deregulated electricity market. The analysis shows that the system is economically competitive for a high price of natural gas ($12-13 MMBtu) and a capital cost reduction (33%) of wind turbines. The hydrogen production is sufficient to supply the current demand of the Great Lakes refineries. With today's electricity prices, a competitive production cost of $1.5 /kg hydrogen is achievable. The analysis indicates large economic incentives to develop HTE systems that operate efficiently in reverse as fuel cells to displace the gas turbines that operate only a few hundred hours per year and thus have high capital cost charges. The capital cost of the HTE system has a significant impact on system economics, with large incentives to develop reversible HTE/ FC systems to reduce those costs. Such a system would expand the use of nuclear beyond electricity generation, and allows a larger penetration of renewables by providing an energy storage media and bringing flexibility to the grid operators. Wed, 01 Jun 2011 00:00:00 GMT https://hdl.handle.net/1721.1/75123 2011-06-01T00:00:00Z https://hdl.handle.net/1721.1/75122 Nuclear Energy for Simultaneous Low-Carbon Heavy-Oil Recovery and Gigawatt-Year Heat Storage for Peak Electricity Production Forsberg, Charles W.; Krentz-Wee, Rebecca E.; Lee, You Ho; Oloyede, Isaiah O. In a carbon-constrained world or a world of high natural gas prices, the use of fossil-fueled power plants to satisfy variable electricity demands may be limited. Nuclear power plants operating at full capacity with large-scale energy storage systems could be employed to provide variable intermediate and peak electricity production. One storage option is to use a nuclear-geothermal system for peak electricity production. At times of low electricity demand, heat from a nuclear reactor in the form of pressurized hot water is used to heat underground rock. At times of high electricity demand, the reactor produces electricity. In parallel, cold pressurized water is injected into the bottom of the manmade hot-rock heat source, hot pressurized water is recovered, and the hot pressurized water is used with a geothermal power plant to produce peak electricity. A nuclear geothermal system for peak electricity production is a new concept with many possible configurations. This paper is an initial assessment of converting heavy oil reservoirs with a history of oil production into nuclear-geothermal systems for peak electricity production. Heavy oil is recovered by steam injection into a reservoir and raising the temperature so the heavy oil can flow to production wells. Such a reservoir may be economically attractive for conversion into a nuclear-geothermal peak electricity system because (1) the reservoir has been preheated to high temperatures that would minimize long-term heat losses from a nuclear geothermal system, (2) such geologies are likely to have reasonable permeability to water flow—a requirement for a nuclear-geothermal system, (3) much of the infrastructure is in place, and (4) the local geology is well understood—including effects of adding heat to the rock. The use of a heavy oil field as a nuclear-geothermal peak power system may significantly increase the fraction of heavy oil that is recovered and enable heavy oil recovery from deeper heavy-oil reservoirs. Total recoverable heavy oil resources may be significantly increased. The nuclear-geothermal heat storage facility acts like a washing machine on the heavy oil reservoir over time with oil extracted using the hot pressurized water. The reservoir characteristics (high porosity, etc.) for heat storage would be expected to improve as more oil is removed. The assessment is that this option is potentially attractive but there are significant uncertainties. The next step must include detailed studies of specific sites to develop a realistic understanding of the option. Wed, 01 Dec 2010 00:00:00 GMT https://hdl.handle.net/1721.1/75122 2010-12-01T00:00:00Z https://hdl.handle.net/1721.1/75121 Hydrogen Production for Steam Electrolysis Using a Supercritical CO[subscript 2]- Cooled Fast Reactor Memmott, M. J.; Driscoll, Michael J.; Hejzlar, Pavel; Kazimi, Mujid S. Rising natural gas prices and growing concern over CO[subscript 2] 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-CO[subscript 2]) 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. Thu, 01 Feb 2007 00:00:00 GMT https://hdl.handle.net/1721.1/75121 2007-02-01T00:00:00Z https://hdl.handle.net/1721.1/75119 OPTIMIZATION OF THE HYBRID SULFUR CYCLE FOR HYDROGEN GENERATION Jeong, Y. H.; Kazimi, Mujid S.; Hohnholt, K. J.; Yildiz, Bilge 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 H[subscript 2]SO[subscript 4] at the decomposer, 70 w–% of H[subscript 2]SO[subscript 4] 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 H[subscript 2]SO[subscript 4] for decomposer, 70 w–% of H[subscript 2]SO[subscript 4] 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. Sun, 01 May 2005 00:00:00 GMT https://hdl.handle.net/1721.1/75119 2005-05-01T00:00:00Z https://hdl.handle.net/1721.1/75098 ATTRIBUTES OF A NUCLEAR-ASSISTED GAS TURBINE POWER CYCLE Jeong, Y. H.; Saha, P.; Kazimi, Mujid S. 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 CO[subscript 2] 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 $/kW[subscript e] of nuclear capital cost can be reduced to about 1500 $/kW[subscript e]. 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. Tue, 01 Feb 2005 00:00:00 GMT https://hdl.handle.net/1721.1/75098 2005-02-01T00:00:00Z https://hdl.handle.net/1721.1/75083 Nuclear Energy Options for Hydrogen and Hydrogen-Based Liquid Fuels Production Yildiz, Bilge; Kazimi, Mujid S. 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 [degrees]C, 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 [degrees]C have often been proposed for such purposes. However, we find the high temperature steam electrolysis process coupled to a supercritical CO[subscript 2] gas turbine cycle, possibly in a direct cycle Supercritical Advanced Gas Reactor, as more promising than other technology options. At 650 to 750[degrees]C 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 [degrees]C, 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. Mon, 01 Sep 2003 00:00:00 GMT https://hdl.handle.net/1721.1/75083 2003-09-01T00:00:00Z