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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs 8 Hydrogen Production Technologies This chapter discusses in more detail the various technologies that can be used to produce hydrogen. These technologies have already been identified in previous chapters and the cost analyses presented in Chapter 5 enumerate them (see Table 5-2). In this chapter, the committee addresses the following technologies: (1) reforming of natural gas to hydrogen, (2) conversion of coal to hydrogen, (3) use of nuclear energy to produce hydrogen, (4) electrolysis, (5) use of wind energy to produce hydrogen, (6) production of hydrogen from biomass, and (7) production of hydrogen from solar energy. The following sections—one for each technology—include a brief description of the current technology; its major technical challenges; possible improvements for future technology; references to Chapter 5 and Appendix E (spreadsheet data from the committee’s cost analyses), where applicable; the potential advantages and disadvantages of using the technology for hydrogen production; comments on the Department of Energy’s hydrogen research, development, and demonstration (RD&D) plan; and recommendations. The committee emphasizes that it made recommendations about research and development (R&D) and priorities in the context of hydrogen production and the possible future “hydrogen economy.” The committee understands that the DOE programs outside the Office of Hydrogen, Fuel Cells, and Infrastructure Technologies have other objectives and priorities besides those related to hydrogen, and the committee did not review those other programs vis-à-vis that of producing hydrogen. For example, the committee identified R&D needs for producing hydrogen from wind and solar-based technologies, but did not review the wind program or the solar technologies program, which also (as does the Office of Hydrogen, Fuel Cells and Infrastructure Technologies) reside within the Office of Energy Efficiency and Renewable Energy (EERE), or consider the objectives and priorities within those offices. Appendix G contains more extensive discussion of each of the technology areas covered in this chapter. In general, in developing estimates about possible future technologies, the committee systematically adopted an optimistic posture. The state of development referred to as possible future is based on technological improvements that may be achieved if the appropriate R&D is successful. The committee is not predicting that these technical advances will be achieved; however, they may be the result of successful R&D programs. And they may require significant technological breakthroughs. Generally, these possible future technologies are available at significantly lower cost than that of current technologies using the same feedstocks. HYDROGEN FROM NATURAL GAS Compared with other fossil fuels, natural gas is a cost-effective feed for making hydrogen, in part because it is widely available, is easy to handle, and has a high hydrogen-to-carbon ratio, which minimizes the formation of by-product carbon dioxide (CO2). However, as pointed out elsewhere in this report, natural gas is imported into the United States today, and imports are projected to grow. Thus, increased use of natural gas for a hydrogen economy would only increase imports further, and as a result the committee considers natural gas to be a transitional fuel for distributed generation units, not a long-range fuel for centralized plants for the hydrogen economy. The primary ways in which natural gas, mostly methane, is converted to hydrogen involve reaction with either steam (steam reforming), oxygen (partial oxidation), or both in sequence (autothermal reforming). In practice, gas mixtures containing carbon monoxide, as well as carbon dioxide and unconverted methane, are produced and require further processing. Reaction of carbon monoxide with steam (water-gas shift) over a catalyst produces additional hydrogen and carbon dioxide, and after purification, high-purity hydrogen is recovered. In most cases, carbon dioxide is vented to the atmosphere today, but there are options for capturing it in centralized plants for subsequent sequestration. For distrib-
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs uted generation, the cost of sequestration appears prohibitive (DiPietro, 1997). Release of carbon dioxide from distributed generation plants during the period of a transition to a hydrogen economy may be a necessary consequence unless an alternative such as hydrolysis with electricity from renewable resources becomes sufficiently attractive or R&D significantly improves distributed natural gas production systems. Further information on the technology and the economics of conversion is given in Appendix G. Distributed generation from natural gas could be the lowest-cost option for hydrogen production during the transition. However, it has never before been achieved in a manner that meets all of the special requirements of this application. The principal challenge is to develop a hydrogen appliance with demonstrated capability to be mass-produced and operated in service stations reliably and safely with only periodic surveillance by relatively unskilled personnel (station attendants and consumers). The capability for mass production is needed in order to meet the demand during the transition, when thousands of these units would be needed, and in order to minimize manufacturing costs. These units need to be designed to maximize operating efficiency and to include the controls, “turndown” capability, and hydrogen storage required to meet the variable demand for hydrogen during a 24-hour period. They must also be designed to meet the hydrogen purity requirements of fuel cells. Steam reforming process technology is available for this application, and companies have already provided one-of-a-kind units in the size range of interest.1 Whether it will be possible to utilize partial oxidation or autothermal reforming for the distributed generation of hydrogen appears to depend on developing new ways of recovering oxygen from air or separating product hydrogen from nitrogen. This is needed because conventional, cryogenic separation of air becomes increasingly expensive as unit size is scaled down. Membrane separations, in contrast, appear amenable to this application and may provide the means for producing small, efficient hydrogen units. Currently, there is little if any market for mass-produced hydrogen appliances such as those described, and it is clear to the committee that the DOE should stimulate development of these devices. The primary challenges involve the development and demonstration of the following: A mass-produced hydrogen appliance suitable for distributed generation in fueling stations, and A complete hydrogen system for fueling stations, capable of meeting variable demand for hydrogen on a 24-hour basis. Each of these challenges is discussed below. The committee estimates that, with further research and development, the unit capital cost of a typical distributed hydrogen plant producing 480 kilograms per day (kg/d) of hydrogen could be reduced from $3,847/kg/d to $2,000/kg/d, and the unit cost of hydrogen reduced from $3.51/kg to $2.33/ kg. These hydrogen unit costs are based on a natural gas price of $6.50 per million British thermal units (Btu); a change in natural gas price of plus or minus $2.00 per million Btu would change hydrogen cost by about 12 percent with current technology. Improved plants could reduce CO2 emissions from an estimated 12.1 to 10.3 kg per kilogram of hydrogen, and overall thermal efficiencies could improve from 55.5 to 65.2 percent, in each case without sequestration. Additional information on these estimates as well as estimates for central station (i.e., large, centralized) hydrogen generators using natural gas is included in Appendixes E and G. The DOE program publications indicate that the program on distributed generation will include demonstration of a “low-cost, small-footprint plant” (DOE, 2003a, b). However, it is not clear whether the program gives priority to distributed generation or includes an effort to demonstrate the benefits of and specific designs for mass production in the specified time frame of the program. The latter would involve concomitant engineering, including design for manufacturing engineering to guide research and prepare for mass production of the appliance. It would also include development of a system design for a typical fueling facility, including the generation appliance, compression, high-pressure storage incorporating the latest storage technology, and dispensers. With today’s technology, the ancillary systems cost about 30 percent as much as the reformer. The committee believes that these costs can be reduced by over 50 percent and that efficiency can be improved through system integration and incorporation of the latest technology. Compression and high-pressure storage are examples of areas in which significant improvements are expected. The DOE program is positioned to stimulate the development of newer concepts such as membrane separation coupled with chemical conversion, and this seems appropriate to the committee. However, most of the effort appears to be directed toward partial oxidation or autothermal reforming. The committee believes that steam reforming could be the preferred process for this application and that it should also be pursued in parallel with the effort on partial oxidation. Finally, the committee notes that the DOE program places significant emphasis on centralized hydrogen plants using natural gas and believes that this effort should be limited, given the increasing importation of natural gas, to those developments that would be applicable to distributed generation. Recommendation 8-1. The Department of Energy should focus its natural gas conversion program on the develop- 1 Dennis Norton, Hydro-Chem, “Hydro-Chem,” presentation to the committee, June 11, 2003; Marvin A. Crews and Howe Baker, “Small Hydrogen Plants for the Hydrogen Economy,” presentation to the committee, June 11, 2003.
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs ment of a hydrogen generation appliance that can be mass-produced and operated reliably and safely in a typical fueling station with only periodic attention, with the goal of having prototype designs in 5 to 7 years. Two prototype designs, one incorporating partial oxidation (or autothermal reforming) and the other steam methane reforming, should be pursued. Funding should be adjusted to ensure that this goal is achieved. In addition, the DOE should downsize its efforts on centralized generation, pursuing only those developments that would be applicable to distributed generation. Recommendation 8-2. The committee recommends that the Department of Energy give appropriate attention in its program to the development of an integrated fueling facility, including the generation appliance and its ancillary subsystems, to minimize cost and to improve efficiency, safety, and reliability. HYDROGEN FROM COAL This section presents the basics of making hydrogen from coal in large centralized plants. Appendix G presents a detailed discussion of making hydrogen from coal. Many of the issues and technologies associated with making hydrogen from coal are similar to those associated with making electric power from coal. These subjects are closely linked to one another and should be considered in concert. This is particularly the case for gasification, a clean coal technology, which will be required for making hydrogen and which also offers the best opportunity for making low-cost, high-efficiency, and low-emission power production through the integrated gasification combined cycle (IGCC) process. The lowest-cost hydrogen coal plants are likely to be ones that coproduce power and hydrogen.2 Coal is a viable option for making hydrogen in very large, centralized plants when the demand for hydrogen becomes large enough to support an associated very large distribution system. The United States has enough coal to make all of the hydrogen that the economy will need for more than 200 years, a substantial coal infrastructure already exists, commercial technologies for converting coal to hydrogen are available from several licensors, the cost of hydrogen from coal is among the lowest available, and technology improvements are identified to reach the future DOE cost targets. The major consideration is that the CO2 emissions from making hydrogen from coal are larger than those from any other way of making hydrogen. This puts an added emphasis on the need to develop carbon sequestration techniques that can handle very large amounts of CO2 before the widespread use of coal to make hydrogen is implemented. Gasification Technology The key to the efficient and clean manufacture of hydrogen from coal is to use gasification technology, which is a clean coal technology, as opposed to the combustion process used in conventional coal-fired power plants. Gasification systems typically involve partial oxidation of the coal with oxygen and steam in a high-temperature and elevated-pressure process. This creates a synthesis gas, a mix of predominantly carbon monoxide (CO) and H2 with some steam and CO2. This synthesis gas (syngas) can be further reacted with water to increase H2 yield. The gas can be cleaned in conventional ways to recover hydrogen and a high-concentration CO2 stream that is easily isolated and sent for disposal. Syngas produced from current gasification plants can be used in a variety of applications, often with multiple applications from a single facility. These applications include use as a feedstock for chemicals and fertilizers, use for making hydrogen for hydro-processing in refineries, or use for generating electricity by burning the syngas in a gas turbine. Research and Development Needs In terms of its stage of development, coal gasification is a less mature commercial process than other coal processes and other hydrogen generation processes using other fossil fuels, especially with respect to capturing CO2 and providing flexibility in both H2 and electricity production. In the committee’s analysis, the current production cost of making hydrogen from coal in central station (i.e., large, centralized) plants is estimated to be $1.03/kg. The potential for improvement through technology development is significant, as indicated below: R&D for current technology should be directed at the following: capital cost reduction; standardization of plant design and execution concept; and improvements in reliability, gas cooler designs, process integration, oxygen plant optimization, and acid gas removal technology. With success in these areas, the production cost of hydrogen from coal is estimated to drop to $0.90/kg. The potential also exists for new technologies to make larger improvements in the efficiency and cost of making hydrogen from coal. For new gasification technologies, the best opportunities for R&D appear to be for new reactor designs (entrained bed gasification) and improved gas separation (hot gas separation) and purification techniques (membrane purification). These new technologies and the concept of integrating them with one another into a complete operating plant are in very early development phases and will require longer-term development to verify the true potential and to reach commercial readiness. With success, the estimated hydrogen production cost can be reduced to $0.77/kg. 2 David Gray and Glen Tomlinson, Mitretek Systems, “Hydrogen from Coal,” presentation to the committee, April 24, 2003.
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs Department of Energy Programs for Coal-to-Hydrogen Production The DOE programs for making hydrogen from coal reside in the Office of Fossil Energy (FE) and are related to programs for making electricity from coal. The overall goal of the Hydrogen from Coal Program is to have an operational, zero-emissions coal-fueled facility in 2015 that coproduces hydrogen and electricity with 60 percent overall efficiency (DOE, 2003c). Major milestones to reach this goal include the following: 2006—Identification of advanced hydrogen separation technology including membranes tolerant of trace contaminants; 2011—Demonstration of hydrogen modules for a coal gasification combined-cycle co-production facility; and 2015—Demonstration of a zero-emission, coal-based plant producing hydrogen and electric power (with sequestration) that reduces the cost of hydrogen by 25 percent compared with the cost of current coal-based plants. To reach these milestones, R&D activities within the Hydrogen from Coal Program are focused on the development of novel processes that include the following: Advanced water-gas-shift reactors using sulfur-tolerant catalysts, Novel membranes for hydrogen separation from carbon dioxide, Technology concepts that combine hydrogen separation and water-gas shift, and Reduction of steps needed to separate impurities from hydrogen. Beyond the DOE’s Hydrogen from Coal Program, two other significant DOE coal R&D programs are ongoing and important to the hydrogen program: Vision 21 and FutureGen. Several years ago the DOE initiated an R&D program called Vision 21, which is up and running and was reviewed by the National Research Council most recently in early 2003 (NRC, 2003b). Major aspects of the Vision 21 program include the following areas that will be applicable to making hydrogen from coal and will lead to more efficient and lower-cost hydrogen: Advanced ion transport membrane technology for oxygen separation from air, Advanced cleaning of raw synthesis gas, Improvements in gasifier design, and Carbon dioxide capture and sequestration technology. Making hydrogen from coal produces a large amount of CO2 as a by-product. A part of the DOE program is aimed at developing safe and economic methods of sequestering CO2 in a variety of underground geologic formations. Indeed, a sequestration R&D program was initiated in the Office of Fossil Energy a number of years ago and is now supported at a significant level. The new coal-based power systems being developed under the Vision 21 program are aimed at coupling power plant with sequestration systems. Beyond the Vision 21 program, the DOE recently announced its intention to proceed with FutureGen, a large coal-to-electricity-and-hydrogen verification plant with coupled sequestration. This plant is now in the early stages of detailed planning. In addition to demonstrating coproduction of electricity and hydrogen with sequestration, the system is also intended to act as a large-scale testbed for innovative new technologies aimed at reducing systems costs. Recommendations Recommendation 8-3. Coal is a viable option for making hydrogen in large, centralized plants when the demand for hydrogen becomes large enough to support an associated distribution system. Thus, coal should be a significant component of any domestic research and development program aimed at producing large quantities of hydrogen for a possible U.S. hydrogen economy. Recommendation 8-4. Because there are a number of similarities between the integrated gasification combined cycle process and the coal-to-hydrogen process, the committee endorses the continuation of both programs in tandem at budget levels that are determined to be adequate to meet the programs goals. Recommendation 8-5. The committee commends the Department of Energy on its initiative in undertaking the FutureGen Project and recommends that the DOE move ahead with the project because of its promise of demonstrating coal-to-hydrogen production coupled with sequestration at a significant scale and its use as a large-scale testbed for related process improvements. As costs can be very high for this type of demonstration, the overall project size and complexity should be closely monitored by the DOE. HYDROGEN FROM NUCLEAR ENERGY Why Nuclear? Nuclear energy is a long-term energy resource that can serve the United States and the world for centuries. With major uranium supplies in the United States, Canada, and Australia, increased reliance on nuclear fuel supplies adds to U.S. energy security. Nuclear power reactors do not involve any CO2 emissions to the atmosphere, nor do they emit any toxic air pollutants such as are emitted by fossil-fueled power
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs plants.3 The development of more efficient nuclear power stations requires technologies with high-temperature coolants—developments that are also required for efficient application of nuclear technology to hydrogen generation. The United States is making progress toward establishing a geologic repository for the spent fuel used in a once-through nuclear fuel cycle, while other fuel cycles are being investigated to optimize resource utilization and reduce the waste burden. Nuclear fuel cycles involving separation of fissile materials leave open the possibility of improper access to those materials (e.g., plutonium) through theft or diversion, but this risk can be mitigated through international cooperation (PCAST, 1999). Status of Nuclear Power Technology The United States derived about 20 percent of its electricity from nuclear energy in 2002 (EIA, Electric Power Monthly, 2003). The 103 power reactors operating today have a total capacity of nearly 100 gigawatts electric (GWe) and constitute about 13 percent of the installed U.S. electric generation capacity. The current U.S. plants use water as the coolant and neutron moderator (hence called light-water reactors, or LWRs) and rely on the steam Rankine cycle as the thermal-to-electrical power conversion cycle. Other countries use other technologies—notably CO2-cooled reactors in the United Kingdom and heavy-water-cooled reactors (HWRs) in Canada and India. In the past 20 years, several advanced versions of the LWR, collectively called ALWRs, have been designed, but only one type has been built: the advanced boiling water reactor (ABWR), which was built in Japan. New versions of light-water reactors are now under review for safety certification by the U.S. Nuclear Regulatory Commission (USNRC). It is expected that a high-temperature helium-cooled reactor, if built in South Africa, would become of interest to U.S. utilities and would also be reviewed by the USNRC for certification. In 2002, several reactor concepts were selected by an international team representing 10 countries, including the United States, as promising “Generation IV (GEN IV) technologies” that should be further explored for availability beyond 2025. The goals for the proposed advanced reactor systems are to improve the economics, safety, waste characteristics, and security of the reactors and the fuel cycle. The emphasis in the development was given to six options (see Appendix G), to be later narrowed to fewer options. The helium-cooled very high temperature reactor (VHTR) is an extension of the helium-cooled reactors built in the United States and in other countries so as to reach higher temperatures and to use gas turbines for their power generation. Hydrogen Production Using Nuclear Energy Hydrogen can be produced using reactors for water splitting by electrolysis or by thermochemical processes without any CO2 emissions. Potentially more efficient hydrogen production may be attained by significantly raising the water temperature before splitting its molecules using either thermochemistry or electrolysis. Such approaches require temperatures in the range of 700°C to 1000°C. Current LWRs and near-term, water-cooled ALWRs produce temperatures under 350°C and cannot be used for such purposes. However, other coolants of several Generation IV reactor concepts are proposed to reach such high temperatures (above 700°C) and may be coupled to thermochemical plants (Brown et al., 2003; Doctor et al., 2002; and Forsberg, 2003). A recent report by the Electric Power Research Institute (EPRI) pointed out that the use of nuclear reactors to supply the heat needed in the steam methane reforming (SMR) process is potentially more economic than their use for water splitting (Sandell, 2003). Nuclear-assisted SMR would reduce the use of natural gas in the process as well as the CO2 emissions. The various options for nuclear hydrogen production are compared in Table 8-1. High-Temperature Electrolysis of Steam The increased demand for thermal energy is offset by a decrease in the electrical energy demand, which improves the overall thermal-to-hydrogen heat conversion efficiency. Higher temperatures also help lower the cathodic and anodic overvoltages. Thus, the high-temperature electrolysis of steam (HTES) is advantageous from both thermodynamic and kinetic standpoints. The HTES overall efficiency appears less sensitive to temperature than the thermochemical processes appear to be. However, much about the technology needs to be investigated. The durability of the electrode and electrolyte materials is not known and needs to be investigated. Also, the effect of high pressure is to increase the overvoltage needed and reduce the size of the chemical units and transmission lines. The scale-up of the size of the electrolysis cell should be sought. Thermochemical Reactions A recent screening of several hundred possible reactions (Besenbruch et al., 2001) has identified two candidate thermochemical cycles for hydrogen production from water (i.e., cycles that enable chemical reactions to take place at high temperatures) with high potential for efficiency and practical applicability to nuclear heat sources. These are the sulfur-iodine (S-I) and calcium-bromine-iron (Ca-Br) cycles. Also, Argonne National Laboratory (ANL) has identified the copper-chlorine (Cu-Cl) thermochemical cycle for this purpose (Doctor et al., 2002). A hybrid sulfur-based process that does not require iodine but has a single electrochemical 3 Nuclear power reactors do emit trace amounts of radionuclides, chiefly noble gases (USNRC, 1996), which cause small doses of radiation to persons offsite, the total annual risk of which is less than one part in 1 million.
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs TABLE 8-1 An Overview of Nuclear Hydrogen Production Options Approach Electrolysis Thermochemistry Feature Water High-Temperature Steam Methane Reforming Water Splitting Required temperature (°C) >0 >300 for LWR >600 for Cu-Cl cycle >700 >850 for S-I cycle >600 for S-AGR Efficiency (%) of chemical process 75–80 85–90 70–80 >45, depending on temperature Efficiency (%) coupled to LWR 27 30 Not feasible Not feasible Efficiency (%) coupled to HTGR, AHTR, or S-AGR Below 40 40–60, depending on temperature >70 40–60, depending on cycle and temperature Advantages Proven technology with LWRs Can be coupled to reactors operating at intermediate temperatures Proven chemistry Eliminates CO2 emissions 40% reduction in CO2 emissions Eliminates CO2 emissions Eliminates CO2 emissions Disadvantages Low efficiency Requires hightemperature reactors CO2 emissions are not eliminated Aggressive chemistry Also requires development of durable HTES units Depends on methane prices Requires development NOTE: LWR = light-water reactor; S-AGR = supercritical CO2 advanced gas reactor; S-I = sulfur-iodine; Cu-Cl = copper-chlorine; HTGR = high-temperature gas-cooled reactor; AHTR = advanced high-temperature reactor; HTES = high-temperature electrolysis of steam. low-temperature step to produce H2 and reforms sulfuric acid has also been proposed by researchers at Westinghouse.4 The low-voltage electrolysis step (low power compared with electrolysis of water) may allow much larger scale-up of the electrochemical cells. The temperatures required for these reactions are generally higher than those provided by LWRs and ALWRs. However, several of the GEN IV reactors would be able to provide the needed heat and high temperatures. The high temperature (above 700°C) would also enable the use of nuclear heat in connection with the SMR process. Reaching higher temperatures would increase the reaction efficiencies. (See Appendix G for details.) Advanced Reactor Technologies Several aspects of nuclear energy technology development for electricity production are also useful for hydrogen production and are not detailed here. Among these is the development of high-temperature reactors that can provide coolants at temperatures higher than 800°C. This seems most readily achievable using the helium-cooled gas reactor technology of high-temperature gas-cooled reactors (HTGRs). Irradiation effects at higher temperatures need to be examined. Operation and control of the helium power cycle at very high temperatures are yet to be demonstrated. Development of a supercritical CO2 power cycle should also be given a high priority. It could potentially allow achieving high power cycle efficiencies at lower temperature than that of the helium gas turbines. This will help the high-temperature electrolysis approach. Research and Development Priorities for Hydrogen Production Research and development priorities for nuclear hydrogen production include the following: The efficiency of thermochemical schemes to accomplish water splitting without any CO2 emissions should be examined at a laboratory scale for the promising cycles such 4 Charles Forsberg, Oak Ridge National Laboratory, “Production of Hydrogen Using Nuclear Energy,” presentation to the committee, January 22, 2003.
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs as the S-I cycles. The R&D program should include the following areas: Materials compatibility issues at high temperature, Catalysts to enhance the reaction at lower temperatures, and Determination of the efficiency of the integrated processes, and how to optimize it through careful thermal management of the heat and mass flows. Development of the high-temperature steam electrolysis process should be pursued. The following issues should be investigated: Materials durability for electrodes and electrolytes, Reduction of overvoltages, Effects of the operating pressure, and Separation of gas products in an efficient and safe manner. The safety issues of coupling the nuclear island to the hydrogen-producing chemical island need to be examined in order to establish the guidelines necessary for avoiding accident propagation from one island to the other. Such guidelines would be needed even if the first application of nuclear hydrogen production was based on the nuclear-assisted SMR approach. Summary Hydrogen can be produced from current nuclear reactors using electrolysis of water. More efficient hydrogen production may be attained by thermochemical splitting of water or electrolysis of high-temperature steam. Another possibility is the use of nuclear energy as the source of heat for steam methane reforming (SMR). The water-splitting approach releases no carbon dioxide. Efficient water-splitting processes and nuclear-SMR all require temperatures well above 700°C. Current water-cooled reactors produce temperatures under 350°C and cannot be used for efficient hydrogen production. Advanced reactors, such as gas-cooled reactors, can achieve the required high temperatures. The committee supports a nuclear-energy-to-hydrogen research program as a small incremental effort to the nuclear-to-power program. The nuclear-to-power program is justified on its own merits. The research budget for the nuclear-to-hydrogen program, which was requested at the level of $4 million for 2004 (DOE, 2003b), appears to be modest. The examination of several options for promising cycles, including the process kinetics, the ability of materials to withstand the aggressive chemistry and temperatures, the separation of fluids, and overall efficiency of the systems requires a higher level of funding for a few years, to determine if a feasible H2 technology concept can be identified. The research program should allow innovative exploration of other processes, such as direct photolysis generation of hydrogen using intense radiation sources. The research portfolio should also include safety aspects of integrating the nuclear reactor with the chemical plant for hydrogen production. This aspect of the program is an important ingredient in establishing guidelines for the designs to avoid potential accident propagation. The involvement of industry in assessing the practicality and cost of the technology is recommended. Recommendations Recommendation 8-6. The Department of Energy’s nuclear hydrogen program should focus on the options to accomplish water splitting without any CO2 emissions. At this early stage of laboratory-scale investigations, the program should involve several options for promising cycles covering catalysts to enhance the reactions at lower temperatures and materials-compatibility issues. Development of the high-temperature steam electrolysis process should be pursued in balance with the thermochemical cycles. The issues of materials durability, reduction of overvoltages, operating pressure effects, and the separation of gas products in an efficient and safe manner should be investigated. If research is successful, one or two processes should be selected for demonstration of the integrated process in a few years. Recommendation 8-7. A portfolio of research that advances the near-term technologies while examining the innovative approaches needs to be maintained. The total budget covering the thermochemical, electrochemical, and other alternatives should be increased for a few years in order to allow for selecting the most promising approaches for demonstration. The Department of Energy should promote industry involvement in assessing the economic potential of the various options. Recommendation 8-8. The Department of Energy’s research and development program should involve safety elements of the nuclear-chemical integrated system and aim to establish guidelines to arrest accident propagation from one part of the system to another. HYDROGEN FROM ELECTROLYSIS Electrolysis to dissociate water into its separate hydrogen and oxygen constituents has been in use for decades, primarily to meet industrial chemical needs. While more expensive than steam reforming of natural gas, electrolysis may play an important role in the transition to a hydrogen economy because small facilities can be built at existing service stations. In addition, electrolysis is well matched to intermittent renewable technologies. Finally, electrolyzers can allow distributed power systems to manage power during peak-
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs demand hours by using stored hydrogen to generate additional power; this hydrogen can be generated during off-peak hours. Technology Options Current electrolysis technologies fall into two basic categories: (1) solid polymer using a proton exchange membrane (PEM) and (2) liquid electrolyte, most commonly potassium hydroxide (KOH). In both technologies, water is introduced into the reaction environment and subjected to an electrical current that causes dissociation, after which the resulting hydrogen and oxygen atoms are put through an ionic transfer mechanism that causes the hydrogen and oxygen to accumulate in separate physical streams. A PEM electrolyzer is literally a PEM fuel cell operating in reverse mode. When water is introduced to the PEM electrolyzer cell, hydrogen ions (protons) are drawn into and through the membrane, where they recombine with electrons to form hydrogen molecules. Oxygen gas remains behind in the water. As this water is recirculated, oxygen accumulates in a separation tank and can then be removed from the system. Hydrogen gas is separately channeled from the cell stack and captured. Liquid electrolyte systems typically use a caustic solution to perform functions analogous to those of a PEM electrolyzer. In such systems, oxygen ions migrate through the electrolytic material, leaving hydrogen gas dissolved in the water stream. This hydrogen is readily extracted from the water when directed into a separating chamber. The all-inclusive costs of hydrogen from PEM and KOH systems today are roughly comparable. Reaction efficiency tends to be higher for KOH systems because the ionic resistance of the liquid electrolyte is lower then the resistance of current PEM membranes. But the reaction efficiency advantage of KOH systems over PEM systems is offset by higher purification and compression requirements, especially at small scale (1 to 5 kilograms per hour). Further details are provided in Appendix G. Electrolysis may be particularly well suited to meeting the early-stage fueling needs of a fuel cell vehicle market. Electrolyzers scale down reasonably well; the efficiency of the electrolysis reaction is independent of the size of the cell or cell stacks involved. The compact size of electrolyzers makes them suitable to being placed at or near existing fueling stations, and they can use existing water and electricity infrastructures, minimizing the need for new infrastructure. Future Electrolysis Technology Enhancements The DOE goal for electrolysis is a capital cost of $300/kW for a 250 kg/d plant (at 5000 pounds per square inch [psi] with 73 percent system efficiency, lower heating value basis [DOE, 2003b, p. 3-15]). Such a plant could be integrated with a renewable energy source to produce hydrogen at $2.50/kg by 2010. A large, central station plant could then produce hydrogen at $2.00/kg (DOE, 2003b, p. 3-16). The DOE research program focuses on ways to reduce costs, improve efficiency, and integrate electrolysis plants with renewable electricity sources. The DOE is also continuing development of reversible solid oxide electrolyzer materials, which can operate at higher temperatures than PEMs can, and at potentially very high efficiencies. The DOE reported that its FY 2004 budget request included approximately $3.2 million for electrolysis-to-hydrogen research.5,6 The committee finds it plausible that PEM electrolyzer capital costs can fall by a factor of eight—from $1000/kW in the near term to $125/kW over the next 15 to 20 years, contingent on similar cost reductions occurring in PEM fuel cells. Should capital costs decrease to this level, the committee estimates that hydrogen could be produced for about $4/kg using grid electricity and electrolysis, making it attractive during the transition period 2010–2030, until centralized facilities and the required distribution system are built. The DOE’s multi-year research, development, and demonstration plan (DOE, 2003b) includes a technical plan on fuel cells, which addresses technology and cost barriers—barriers that, if overcome, will benefit electrolyzers as well. Elements of the fuel cell plan include, for example: development of high-temperature membranes for PEM fuel cells, development of lower-cost polymer membranes having higher ionic conductivity, and development of alternative catalyst formulations and structures. In addition, electrolyzer system efficiencies may rise from the current 63.5 percent to 75 percent (lower heating value) in the future. Among research priorities that can improve the efficiency and/or reduce the cost of future electrolysis fueling devices and could become part of the DOE’s electrolysis program are the following: Reducing other (parasitic) system energy losses. A variety of parasitic loads, such as power conditioning, can be reduced through system redesign and optimization. Reducing current density. Conversion efficiencies are a function of electric current density, so the substitution of more electrolyte or more cell surface area has the impact of reducing overall power requirements per unit of hydrogen produced. Development of electrolysis/oxidation hybrids. The hybrid concept uses the oxidation of natural gas as a means of intensifying the migration of oxygen ions through the electrolyte and thereby reducing the effective amount of electric energy required to transport the oxygen ion. The concept 5 Pete Devlin, Department of Energy, “DOE’s Hydrogen RD&D Plan,” presentation to the committee, June 11, 2003. 6 The committee understands that of the $78 million subsequently appropriated for hydrogen technology for 2004 in the Energy and Water appropriations bill (Public Law 108-137), $37 million is earmarked for activities that will not particularly advance the hydrogen initiative.
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs appears to offer the potential for significantly improved net electrochemical efficiency, but will require several technical breakthroughs in harnessing solid oxide technology. Recommendations Recommendation 8-9. The Department of Energy’s electrolysis technology program should continue to target cost reduction, enhanced system efficiency, and improved durability for distributed-scale hydrogen production from electricity and water. These technology objectives can be advanced through research into (1) lower-cost membranes, catalysts, and other cell and system components; (2) membranes and systems that can operate at higher temperatures and pressures; and (3) improved system design and integration with an eye toward low-cost manufacturing. Specifically, the DOE should increase emphasis on electrolyzer development with a target of $125 per kilowatt and a significant increase in efficiency toward a goal of over 70 percent (lower heating value basis). Recommendation 8-10. The Department of Energy should emphasize component development and systems integration to enable electrolyzers to operate from inherently intermittent and variable-quality power derived from wind and solar sources. HYDROGEN PRODUCED FROM WIND ENERGY The production of hydrogen from renewable energy sources is often stated as the long-term goal of a mature hydrogen-based economy (Turner, 1999). Of all renewable energy sources, using wind-turbine-generated electricity to electrolyze water, particularly in the near to medium term, has arguably the greatest potential for producing pollution-free hydrogen. The issues for its successful development and deployment are threefold: (1) further reducing the cost of wind turbine technology and the cost of the electricity generated by wind, (2) reducing the cost of electrolyzers, and (3) optimizing the wind turbine-electrolyzer with a hydrogen storage system. The current study considered only distributed-scale wind-to-hydrogen production systems. For a more in-depth discussion, see Appendix G. Wind energy is one of the most cost-competitive renewable energy technologies available today, and in some places it is beginning to compete with new fossil fuel electricity generation. A principal parameter determining the economic success of wind turbines is the annual energy output, which is most sensitive to wind speed and the on-stream capacity factor. The current cost of generating electricity from wind at good wind sites falls in the range of 4 to 7 cents per kilowatt-hour (kWh) (without financial incentives), with capacity factors of about 30 percent. Analysts generally forecast that these costs will continue to drop and capacity factors increase as the technology improves further and the market grows. There are obvious advantages to hydrogen produced from wind energy. It is essentially emission free, producing no CO2 or criteria pollutants, such as oxides of nitrogen (NOx) and sulfur dioxide (SO2), and it is a domestic source of energy. Thus, it addresses both of the main concerns motivating the current drive toward a hydrogen economy. But wind energy is not free of problems. There are environmental, siting, and technical issues that must be dealt with. Wind energy’s most serious drawback continues to be its intermittence and mismatch with demand, an issue both for electricity generation and hydrogen production. Hydrogen Production by Electrolysis from Wind Power The committee’s analysis considered wind-energy-to-hydrogen systems deployed on a distributed scale, which thus bypasses the extra costs and requirements of hydrogen distribution. For distributed wind-electrolysis-hydrogen production systems, it is estimated that using today’s technologies, hydrogen can be produced at good wind sites (class 4 and above, without financial incentives) for approximately $6.64/kg H2. The committee’s analysis considers a system that uses grid electricity as backup for when the wind isn’t blowing to alleviate the capital underutilization of the electrolyzer. This hybrid wind-to-hydrogen production system has pros and cons. It reduces the cost of producing the hydrogen, which without grid backup would be $10.69/kg H2, but it also incurs CO2 emissions from what would otherwise be an emission-free hydrogen production system. In the future, the wind-electrolysis-hydrogen system could be substantially optimized. The wind turbine technology will improve, with a resulting decrease in the cost of electricity generated and an increase in the turbine’s capacity factor, and the electrolyzer’s efficiency will increase and its capital costs decrease (see the section above, entitled “Hydrogen from Electrolysis”). With the assumptions used in this study, the committee finds that the wind energy system and the electrolyzer can be designed to be large enough that sufficient low-cost hydrogen can be generated and stored when the wind is blowing, without grid backup. This is a lower-cost option than using a smaller electrolyzer and purchasing grid-supplied electricity when the wind turbine is not generating electricity. With future estimated improvements in the technology, hydrogen produced from wind without grid backup is estimated to cost $2.86/kg H2, while for a system with grid backup it is $3.38/kg H2 (all without financial incentives). Furthermore, this stand-alone system has the added advantage of a hydrogen production system that is CO2-emission-free. The results of the committee’s analysis are summarized in Table 8-2. Wind-electrolysis-hydrogen production systems are currently far from optimized. For example, better integration of the wind turbine and electrolyzer power control system
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs TABLE 8-2 Results from Analysis Calculating Cost and Emissions of Hydrogen Production from Wind Energy Current Technology Future Technology With Grid Backup No Grid Backup With Grid Backup No Grid Backup Average cost of electricity (cents/kWh) 6 6 4 4 Wind turbine capacity factor (%) 30 30 40 40 Hydrogen ($/kg) 6.64 10.69 3.38 2.86 Carbon emissions (kg C/kg H2) 3.35 0 2.48 0 is needed, as is hydrogen storage tailored to the wind turbine design. Furthermore, there is the potential to optimize coproduction of electricity and hydrogen, which under the right circumstances could be more cost-effective and provide broader system utility. Conclusions Wind energy has some very clear advantages as a source of hydrogen. It fulfills the two main motivations that are propelling the current push toward a hydrogen economy, namely, reducing CO2 emissions and reducing the need for hydrocarbon imports. In addition, it is the most affordable renewable technology deployed today, with expectations that costs will continue to decline. Of all renewable energy technologies, wind is the closest to practical widespread utilization with the technical potential to produce a significant amount of hydrogen in the future. Yet, it still faces many barriers to deployment and therefore deserves continued as well as more focused attention in the DOE’s hydrogen program. In particular, there is a need to partner with industry to develop optimized wind-to-hydrogen systems and to help identify the R&D needed to advance such systems to the next level. Energy security and environmental quality, including the reduction of carbon dioxide emissions, are strong factors motivating a hydrogen economy. These two goals can both be addressed by wind-energy-to-hydrogen systems. Thus, wind has the potential to play an important role in a future hydrogen economy, particularly during the transition and potentially in the long term. Wind technology is likely to continue to improve. Such improvements would include enhanced performance at variable wind speeds, thereby permitting capture of the maximum amount of wind according to local wind conditions, and better grid compatibility, matching supply with demand. These advancements can occur through better turbine design and optimization of rotor blades, more efficient power electronic controls and drive trains, and better materials. Wind-electrolysis-hydrogen systems have yet to be fully optimized. There are integration opportunities and issues with respect to wind energy systems, electrolyzers, and hydrogen storage that need to be creatively explored. For example, coproduction of electricity and hydrogen can potentially reduce costs and increase the function of the wind-energy-to-hydrogen system. This could facilitate the development of wind energy systems that are more cost-effective and have broader utility. Department of Energy’s Research, Development, and Demonstration Plan There is little mention of hydrogen production from wind throughout the entire June 2003 draft entitled “Hydrogen, Fuel Cells and Infrastructure Technologies Program: Multi-Year Research, Development and Demonstration Plan” (DOE, 2003b), or in the July 2003 Hydrogen Posture Plan: An Integrated Research, Development, and Demonstration Plan (DOE, 2003a). An RD&D program for hydrogen production from wind power needs to be developed and integrated into the overall hydrogen strategic RD&D plan. Clear and strong crossover is needed between the research program on renewable-based electricity generation, such as wind energy, and the hydrogen production R&D program. Recommendation 8-11. Wind energy for hydrogen production does not appear at present in the Department of Energy’s multi-year research, development, and demonstration plan. Wind-energy-to-hydrogen systems need to be an important element in the DOE’s hydrogen program and need to be integrated into the hydrogen production strategy. The plan should address the technical issues related to costs and capacity factor, particularly wind sites in class 3 and below. Recommendation 8-12. The Department of Energy’s multi-year research, development, and demonstration plan should address how best to partner with industry to create robust, efficient, and cost-effective wind-electrolysis-hydrogen systems that will be ready for deployment as the distributed hydrogen infrastructure begins to develop. This is particularly important as there needs to be a research and development emphasis on optimizing wind-electrolysis-hydrogen
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs systems. The role that the coproduction of hydrogen and electricity from wind can play needs to be further analyzed and integrated into future hydrogen production strategies so that potential synergies can be better understood and utilized. HYDROGEN PRODUCTION FROM BIOMASS AND BY PHOTOBIOLOGICAL PROCESSES Renewable solar energy is the primary energy source for hydrogen production from biomass or by direct photobiological processes (Turner, 1999). Two types of biomass feedstock are available to be converted into hydrogen: (1) dedicated bioenergy crops and (2) less expensive residues, such as organic waste from regular agricultural farming and wood processing (biomass residues). In direct photobiological hydrogen production, water is directly cleaved by photosynthetic (micro)organisms, without biomass formation as intermediate. Hydrogen production by these biological means is attractive because solar energy is a renewable energy source. Biomass Costs and Availability Hydrogen production from biomass is a thermodynamically inefficient and expensive process, in which approximately 0.2 percent to 0.4 percent of the total solar energy is converted to hydrogen at a price of currently about $7.05/ kg H2 by gasification in a midsize plant (see Figure 5-2 in Chapter 5 and Appendix E). This price reflects higher feedstock, distribution, and fixed and capital costs relative to other production methods such as natural gas reforming (Figure 5-2). In its economic analysis, the committee did not consider fertilizer costs and the environmental impact associated with the production, harvest, and transport of biomass. In addition, the analysis did not quantify any potential degradation in land quality associated with intensive bioenergy crop farming. All renewable technologies and feedstocks for hydrogen production compete for land area with other societal needs, such as agricultural goods and services, recreation, and land conservation. To minimize this competition, biological processes for H2 production need to be thermodynamically efficient and kinetically fast to reduce land use. In the committee’s possible future technology case, crop yield is projected to improve by 50 percent, and efficiency is projected to improve to 40 percent, up from 26 percent in the current technology case (inclusive of conversion, distribution, and dispensing energy efficiencies). In a future, all-fuel-cell-vehicle economy, the amount of biomass required to satisfy 100 percent of the hydrogen demand would require roughly 282,000 square miles (mi2) for bioenergy crop farming.7 (See also Figure 6-15 in Chapter 6.) This comprises an area of land that is approximately 40 percent of cropland currently used for crops in the United States.8 Farming of bioenergy crops on such a scale is likely to have significant environmental impacts on soil, water sources, biodiversity, and eutrophication, and might also affect the price for agricultural goods. The committee estimates the possible future technology price for hydrogen from gasification of biomass to be $3.60/kg H2, which is noncompetitive relative to other hydrogen production technologies (see Figure 5-4). Biomass Conversion Current technologies for converting biomass into molecular hydrogen include gasification or pyrolysis of biomass coupled to subsequent steam reformation.9 The main conversion processes are (1) indirectly heated gasification, (2) oxygen-blown gasification, (3) pyrolysis, and (4) biological gasification (anaerobic fermentation). Plants dedicated for biomass gasification are designed to operate at low pressure and are limited to midsize-scale operations,10 due to the heterogeneity of biomass, the localized production of biomass, and the relatively high costs of gathering and transporting biomass feedstock. Therefore, in addition to the relatively high feedstock costs, dedicated biomass gasification plants are associated with capital costs that, in the current technology case, the committee estimates to be $2.44/kg H2, compared with about $0.46/kg H2 for large, central station coal gasification (see Figure 5-2). The committee considered possible improvements in biomass gasification technology in its possible future technology case and projected capital costs of about $1.20/kg H2, which would be still more than twice that for current coal gasification (see Figure 5-4). In addition, the energy efficiency of the biomass gasification plants for converting feedstock into hydrogen will be lower than that of coal plants. After capital costs (which include the gasifier), feedstock costs and distribution costs are the two largest cost components for the production of hydrogen from biomass by gasification, in the committee’s analysis (see Figures 5-2 and 5-4). The size of these two cost components is an inherent consequence of the low density of biomass as collected from 7 Calculated using the biomass “possible future technology case” (and its higher efficiency and crop yield). 8 The U.S. Department of Agriculture’s National Agricultural Statistics Service (NASS, 2003) estimated that 349 million acres (545,000 mi2) of cropland were used for crops (i.e., cropland harvested, crop failure, and cultivated summer fallow) in 1997, the most recent year for which data were available. 9 Roxanne Danz, Department of Energy, “Hydrogen from Biomass,” presentation to the committee, December 2, 2002. 10 Biomass gasification has been demonstrated at 100 to 400 tons of biomass per day (Margaret Mann and Ralph Overend, National Renewable Energy Laboratory, “Hydrogen from Biomass: Prospective Resources, Technologies, and Economics,” presentation to the committee, January 22, 2003). The committee’s midsize biomass-to-hydrogen gasification technology cases fall within this range (see Appendix E).
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs bioenergy crop farming, the distributed nature of biomass residue collection, and the cost of transportation to the biomass gasification plant. Because of the costs associated with harvesting low-density bioenergy crops, biomass gasification plants will be limited to a midsize scale. Consequently, such gasification plants will not make use of the economy of scale, which will keep the costs for distribution high and will inherently limit the plant’s energy efficiency. Coproduction (biorefinery) of, for example, phenolic adhesives, polymers, waxes, and other products with hydrogen production from biomass is being discussed in the context of biomass gasification plant designs to improve the overall economics of biomass-to-hydrogen conversion.11 The technical and economic viability of such coproduction plants is unproven and was not considered in this analysis. Biomass Gasification as a Means for Net Reduction of Atmospheric Carbon Dioxide Biomass gasification could play a significant role in meeting the DOE’s goal of greenhouse gas mitigation. It is likely that both in the transition phase to a hydrogen economy and in the steady state, a significant fraction of hydrogen might be derived from domestically abundant coal. In co-firing applications with coal, biomass can provide up to 15 percent of the total energy input of the fuel mixture. The DOE could address greenhouse gas mitigation by co-firing biomass with coal to offset the losses of carbon dioxide to the atmosphere that are inherent in coal combustion processes (even with the best-engineered capture and storage of carbon). Since growth of biomass fixes atmospheric carbon, its combustion leads to no net addition of atmospheric CO2 even if vented. Thus, co-firing of biomass with coal in an efficient coal gasification process, affording the opportunity for capture and storage of CO2, could lead to a net reduction of atmospheric CO2. The co-firing fuel mixture, being dilute in biomass, places lower demands on biomass feedstock. Thus, cheaper, though less plentiful, biomass residue could supplant bioenergy crops as feedstock. Using residue biomass would also have a much less significant impact on the environment than would farming of bioenergy crops. Advanced Direct Photobiological Hydrogen Production Hydrogen production by direct oxidative cleavage of water, mediated by photosynthetic (micro)organisms, without biomass as intermediate, is an emerging technology at the early exploratory research stage.12 By circumventing biomass formation and subsequent gasification, the yield of solar energy conversion to hydrogen by direct photobiological processes is theoretically more efficient than is biomass gasification by 1 to 2 orders of magnitude. The direct photobiological hydrogen release could be on the order of 10 percent (see Appendix G), compared with efficiencies of 0.5 to 1 percent for biomass-to-hydrogen conversion. It is conceivable that bioengineering efforts on the light harvesting complex and reaction center chemistry (see Appendix G) could improve this efficiency severalfold over the coming decades, and thereby bring the overall efficiency (solar-to-hydrogen) of direct photobiological hydrogen production into the range of 20 to 30 percent. However, substantial, fundamental research needs to be undertaken before photobiological methods for large-scale hydrogen production are considered. Department of Energy Research and Development Program According to the draft (June 3, 2003) “Hydrogen, Fuel Cells and Infrastructure Technologies Program: Multi-Year Research, Development and Demonstration Plan” (DOE, 2003b), the DOE’s Office of Energy Efficiency and Renewable Energy is focused on biomass gasification/pyrolysis and has set technical targets for the years 2005, 2010, and 2015 to reduce costs for biomass gasification/pyrolysis and subsequent steam reforming. Specific goals include reduction of costs for (1) biomass feedstock, (2) gasification operation (including efficiency), (3) steam reforming, and (4) hydrogen gas purification. The DOE reported that its FY 2004 budget request included approximately $5.4 million for biomass-to-hydrogen research. While the breakdown of this amount was not further specified, the DOE did list its six priority items for hydrogen production, included among which was the following biomass-to-hydrogen priority item: “Low cost and high efficiency gasifier/pyrolyser and reforming systems.”13 The technical targets that the DOE has set for biomass gasification and biomass pyrolysis are ambitious; they include cost reduction from $3.60 to $2.00/kg H2 by 2015 for gasification and from $3.80 to $2.40/kg H2 by 2015 for pyrolysis (DOE, 2003b). The EERE program seems to support photobiological hydrogen research, but the DOE does not specify the amount beyond noting a total FY 2004 request for photolytic systems of $3.2 million—a total that includes photoelectrochemical hydrogen production methods in addition to photobiological methods.14 The DOE’s R&D targets for increasing the utilization efficiency of absorbed light and hydrogen production are very ambitious (a factor-of-four improvement to 20 percent by 2010) (DOE, 2003b). 11 Margaret Mann and Ralph Overend, National Renewable Energy Laboratory, “Hydrogen from Biomass: Prospective Resources, Technologies, and Economics,” presentation to the committee, January 22, 2003. 12 Catherine E. Grégoire Padró, National Renewable Energy Laboratory, “Hydrogen from Other Renewable Resources,” presentation to the committee, December 2, 2002. 13 Pete Devlin, Department of Energy, “DOE’s Hydrogen RD&D Plan,” presentation to the committee, June 11, 2003. 14 Pete Devlin, Department of Energy, “DOE’s Hydrogen RD&D Plan,” presentation to the committee, June 11, 2003.
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs Challenges The most significant challenges for hydrogen production by biological technologies are these: The low thermodynamic efficiency of biomass-to-hydrogen conversion, the high costs of bioenergy crop production and biomass gasification, and the significant demand for and impact on land use and natural resources for bioenergy crop farming; and The engineering of (micro)organisms and of processes for direct photobiological hydrogen production without biomass as an intermediate at high themodynamic efficiency and high kinetic rates. Recommendation 8-13. The committee recommends that the Department of Energy deemphasize the current biomass gasification program and refocus its bio-based program on more fundamental research on photosynthetic microbial systems to produce hydrogen from water at high rate and efficiency. The DOE should encourage innovative approaches and should make use of important breakthroughs in molecular, genomic, and bioengineering research. Research and development for co-firing of biomass, for example, with coal, coupled to subsequent carbon sequestration should continue. The DOE should resist pressure for premature demonstration projects of developing technologies. HYDROGEN FROM SOLAR ENERGY It has been estimated that solar energy has the potential to meet global energy demand well into the future (Turner, 1999). Hydrogen from solar energy can be produced through two methods. In one method, solar energy is converted into electricity using a photovoltaic (PV) cell and then hydrogen is generated through the electrolysis of water. In the alternate method, photoelectrochemical cells are used for the direct production of hydrogen. The photoelectrochemical methods are still in the early stages of development. Approximately 85 percent of the current commercial PV modules are based on single-crystal or polycrystalline silicon. A second type of PV technology is based on deposition of thin films of amorphous as well as microcrystalline silicon, and on compounds based on group II-VI and group I-III-VI elements of the periodic table. Thin-film technology appears to hold greater promise for cost reduction. However, in spite of its promise, the thin-film technology has been unable to reduce the cost of solar modules, owing to low deposition rates. This problem translates to low solar cell production rates. The current low film deposition rates lead to a decreased rate of solar cell production and directly translate into a significant cost because of the lower productivity of the expensive deposition machines. As yields and throughputs are low, the plants need better inline controls and easier and faster deposition techniques enhancing reproducibility. Also, there is a substantial drop in efficiency of the solar cell from the laboratory scale to the module scale. The current cost of solar modules is in the range of $3 to $6 per peak watt (Wp). For solar cells to be competitive with the conventional technologies for electricity production alone, the module cost has to come down below $1/Wp. The committee estimated the cost to produce hydrogen using electricity from solar PV devices to power electrolyzers. In the current technology case, with a favorable installed cost of about $3.28/Wp, the electricity cost is estimated to be about $0.32/kWh and the hydrogen cost to be $28.19/kg (scenario Dist PV-C and Dist PV Ele-C of Chapter 5 and Appendix E). In the possible future technology case, the installed capital cost of $1.011/Wp provides an electricity cost of $0.098/kWh and a hydrogen cost of $6.18/kg (scenario Dist PV-F and Dist PV Ele-F). The $6.18 possible future cost of hydrogen, in the committee’s analysis, is the sum of $4.64/kg for PV-generated electricity and $1.54/kg, mostly for capital charges associated with producing (via electrolysis), storing, and dispensing hydrogen. The total supply chain cost is thus about a factor of four higher than that of the central station coal plant in its possible future case (CS Coal-F), which the committee estimates to be $1.63/kg H2, inclusive of delivery and dispensing. For the PV-electrolyzer combination to be competitive in the future, either the cost of PV modules has to be reduced by an order of magnitude from current costs, or the electrolyzers’ cost has to come down substantially from the low cost of $125/kW already assumed in the committee’s future technology case. A factor contributing to this need for low electrolyzer cost is the low utilization of the electrolyzer capital (solar energy is taken to be available 20 percent of the time). Therefore, while electricity at $0.098/kWh from a PV module can be quite attractive for distributed applications in which electricity is used directly at the site, hydrogen costs via PV-electricity and electrolysis will not be competitive. Energy is consumed in the manufacture of solar modules. It has been estimated by the National Renewable Energy Laboratory (NREL) that for a crystalline silicon module, the payback period of energy is about 4 years. For amorphous silicon modules this period is currently around 2 years, with the expectation that it will eventually be less than 1 year. Various developments are likely to improve the economic competitiveness of solar PV technology. The current research on thin-film deposition techniques is leading to higher deposition rates and efficiencies. Better barrier materials to eliminate moisture ingress in the thin-film modules will prolong the module life span. Robust deposition techniques will increase the yield from a given type of equipment. Inline detection and control methods will help to reduce the cost. Some of this advancement will require creative tools and methods. The anticipated improvements from this thin-film technology research were included in the possible future technology case calculations. Alternate concepts to thin films, such as dye-sensitized solar cells, also known as Grätzel cells, are being explored
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs (O’Regan and Grätzel, 1991). In these cells, a dye is incorporated in a porous inorganic matrix such as TiO2, and a liquid electrolyte is used for positive charge transport. This type of cell has a potential to be low-cost. However, the efficiencies at present are quite low, and the stability of the cell in sunlight is unacceptable. Research is needed to improve performance in both respects. Another area of intense research is that on the integration of organic and inorganic materials at the nanometer scale into hybrid solar cells. The current advancement in conductive polymers and the use of such polymers in electronic devices and displays provides the impetus for optimism. The nano-sized particles or rods of the suitable inorganic materials are embedded in the conductive organic polymer matrix. Once again, the research is in the early phase and the current efficiencies are quite low. However, the production of solar cells based either solely on conductive polymers or hybrids with inorganic materials has much potential to provide low-cost solar cells. It is hoped that one would be able to cast thin-film solar cells of such materials at a high speed, resulting in low cost. Research is being done to create aqueous photoelectrochemical cells for direct conversion of solar energy to hydrogen (Grätzel, 2001).15 In this method, light is converted to electrical and chemical energy. A solid inorganic oxide electrode is used to absorb photons and provide oxygen and electrons. The electrons flow through an external circuit to a metal electrode, and hydrogen is liberated at this electrode. The candidate inorganic oxides are SrTiO3, KTaO3, TiO2, SnO2, and Fe2O3. If successful, such a method holds the promise of directly providing low-cost hydrogen from solar energy. It seems that a photoelectrochemical device in which all of the functions of photon absorption and water splitting are combined in the same equipment may have better potential for hydrogen production at reasonable costs. However, a quick “back of the envelope” analysis shows that in order to compete with the hydrogen produced from fossil fuels, photoelectrochemical devices should recover hydrogen at an energy equivalent of $0.4 to $0.5/Wp. This cost challenge is similar to that for electricity production from solar cells. Challenges and Research and Development Needs Large-scale use of solar energy for a hydrogen economy will require research and development efforts on multiple fronts: In the short term, there is a need to reduce the cost of thin-film solar cells. To do this will require the development of deposition techniques of thin films such as microcrystalline silicon and other materials that are robust and provide high throughput rates without sacrificing film efficiencies. In the short run, thin-film deposition methods can potentially gain from a fresh look at the overall process from the laboratory scale to the manufacturing scale. The research in this area is expensive. For such research, some additional centers in academia with industrial alliances could be beneficial. It will be necessary to collect interdisciplinary teams from different science and engineering disciplines for such studies. In the midterm to long term, organic polymer-based solar cells hold promise for mass production at low cost. They have an appeal for being cast as thin films at very high speeds using known polymer film casting techniques. Currently, the efficiency of such a system is quite low (in the neighborhood of 3 to 4 percent or lower), and stability in sunlight is poor. However, due to the tremendous development in conducting polymers and other electronics-related applications, it is anticipated that research in such an area has a high potential for success. Similarly, the search for a stable dye material and better electrolyte material in dyesensitized cells (Grätzel cells) has a potential to lead to lower-cost solar cells. There is a need to increase the stable efficiency of such cells. In the long run, the success of directly splitting water molecules by using photons is quite attractive. Research in this area can be very fruitful. Department of Energy Programs for Solar Energy to Hydrogen The current DOE target for photoelectrochemical hydrogen production in 2015 is $5/kg H2 at the plant gate.16 Even if this target is met, solar-energy-to-hydrogen is unlikely to be competitive. Therefore, a much more aggressive cost target for hydrogen production by photoelectrochemical methods is needed. Since photoelectrochemical hydrogen production is in an embryonic stage, a parallel effort to reduce the cost of electricity production from PV modules must be made. A substantial reduction in PV module cost (lower than $0.5/Wp) coupled with similar reductions in electrolyzer costs (about $125/kW at reasonable high efficiency of about 70 percent on a lower heating value basis) can provide hydrogen at reasonable cost. The potential research opportunities listed in the preceding subsection for PV solar cells along with electrolyzers must be actively explored. Summary All of the current methods and the projected technologies for producing hydrogen from solar energy are much more expensive (greater than a factor of three) when compared with hydrogen production from coal or natural gas plants. This is due partly to the lower annual utilization factor of about 20 percent (as compared with, say, wind of 30 to 40 percent). This creates enormous pressure to reduce the cost 16 Pete Devlin, Department of Energy, “DOE’s Hydrogen RD&D Plan,” presentation to the committee, June 11, 2003. 15 Nathan Lewis, California Institute of Technology, “Hydrogen Production from Solar Energy,” presentation to the committee, April 25, 2003.
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The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs of a solar energy recovery device. While an expected future installed module cost of about $1/Wp is very attractive for electricity generation and deserves a strong research effort in its own right, this cost fails to provide hydrogen at a competitive value. It is apparent that there is no one method of harnessing solar energy that is a clear winner. However, it appears possible that new concepts may emerge that would be competitive. In the future, if the cost of the fuel cell system approaches $50/kW, the cost of the electrolyzer is also expected to approach a low number (about $125/kW). Such low capital costs for electrolyzer units, together with levelized electricity costs in the neighborhood of $0.02 to $0.03/kWh, would result in a competitive hydrogen cost. It is also estimated that for a photoelectrochemical method to compete, its cost needs to approach $0.04 to $0.05/kWh. The order-of-magnitude reductions in cost for both hydrogen processes are similar. Recommendations Recommendation 8-14. Because of the large volume of hydrogen potentially available from solar energy and its carbon dioxide-free hydrogen, multiple paths of development should be pursued until a clear winning technology emerges for hydrogen production. There is a need for more basic research to provide a low-cost option. More specifically, alternate new technologies for harnessing solar energy should be developed, as well as new and novel methods to substantially reduce the manufacturing cost of some of the promising known technologies. Recommendation 8-15. While basic research in photoelectrochemical as well as other methods that directly convert solar energy to hydrogen should be actively pursued, the route of solar electricity generation coupled with use of an electrolyzer for hydrogen production should also be pursued in a balanced Department of Energy solar program. A more aggressive target for photovoltaic solar of about $0.02 per kilowatt-hour (roughly $200 to $300 per kilowatt for the solar module) requires research on new and novel approaches. This will be especially important if improvements in battery storage density and cost are not achieved and hydrogen usage becomes dominant.
Representative terms from entire chapter: