http://hdl.handle.net/1721.1/67476 Fri, 24 May 2013 05:41:41 GMT 2013-05-24T05:41:41Z http://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 http://hdl.handle.net/1721.1/75135 2007-04-01T00:00:00Z http://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 http://hdl.handle.net/1721.1/75126 2011-09-01T00:00:00Z http://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 http://hdl.handle.net/1721.1/75125 2011-06-01T00:00:00Z http://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 http://hdl.handle.net/1721.1/75124 2011-06-01T00:00:00Z