CRS Report for Congress
Hydrogen: Technology and Policy
The idea of using hydrogen as a fuel is not a new one, but interest in it has grown in recent years. The Federal hydrogen research budget in FY95 is higher than ever before. In accordance with the Spark M. Matsunaga Hydrogen Research, Development, and Demonstration Act of 1990 (PL 101-566) the Department of Energy (DOE) has issued a five-year program plan and a five-year implementation plan and formed a technical advisory panel. This report discusses technologies for hydrogen production, distribution, and use, and addresses a number of policy issues of interest to the Congress.
Unlike most other fuels, hydrogen cannot be produced directly by digging a mine or drilling a well. It must be extracted chemically from hydrogen-rich materials such as natural gas, water, coal, or plant matter. Accounting for the energy required for the extraction process is critical in evaluating any hydrogen use option. Production techniques now used include steam reforming of natural gas, cleanup of industrial by-product gases, and electrolysis of water. A number of other technologies are being studied, including several that produce hydrogen from water or biomass using solar or other renewable energy.
At present, fuel hydrogen is mostly distributed in tankers as a cryogenic liquid. Expanded use would probably mean distribution in pipelines as a gas, but few hydrogen pipelines now exist and any large-scale distribution system would also require techniques for bulk storage.
In the United States today, the only major non-experimental user of hydrogen as a fuel is the space program, for propulsion and as an on-board source of electricity. Aircraft applications have been widely studied, particularly for supersonic and hypersonic planes. Cars, trucks, and buses can burn pure hydrogen in an internal combustion engine, use it in a fuel cell to drive an electric motor, or burn a hydrogen-containing mixture to reduce the environmentally harmful emissions from another fuel.
Questions related to hydrogen's impact on the Nation's broad energy picture, such as the possible benefits for the economy, the environment, and energy security, should be considered in long-term context.
Since the passage of the Matsunaga Act, the DOE hydrogen RD&D program has sharpened its focus and benefitted from higher congressional appropriations, which stand at $10 million for FY 1995. The Hydrogen Future Act of 1995 (H.R.655, H.Rept.104-95) would greatly increase funding authorizations for the hydrogen program during fiscal years 1996 through 1998, while intensifying the focus on basic R&D. It would require elevated hydrogen spending to be matched by reduction in spending for other programs such as fusion energy R&D, nuclear fission R&D, renewable energy R&D, or fossil energy R&D.
TABLE OF CONTENTS
HYDROGEN: TECHNOLOGY AND POLICY
The idea of using hydrogen as a fuel has been around for many years. As early as 1874, a character in Jules Verne's novel The Mysterious Island suggested that when fossil fuel supplies run out, hydrogen "will furnish an inexhaustible source of heat and light''.(l) So far, however, this idea has generated much research but little commercial application. In September, 1992, the U.S. Department of Energy's new Hydrogen Technical Advisory Panel released a five-year program plan.(2) In October 1993, DOE's Office of Energy Management released a five-year implementation plan. Federal funding for hydrogen research in FY95 is at its highest, and legislation (H.R. 655) by Chairman Walker of the House Science Committee would authorize further major increases. An interagency panel to coordinate research efforts has been established. In light of these actions, this report discusses technologies for hydrogen production, distribution, and use, and addresses such policy issues as the economic and environmental consequences of hydrogen use, the question of safety, and the status of Federal research and development programs.
Although it is the universe's most abundant element, hydrogen is present in the atmosphere only in concentrations of less than one part per million. Most of the Earth's hydrogen is bound up in chemical compounds. Hydrogen for large-scale use must therefore be extracted from a source such as water, coal, natural gas, or plant matter. It cannot simply be produced from a mine or a well. Since considerable energy is consumed in the extraction process, hydrogen should properly be considered an energy carrier(3) rather than an energy source; the energy released when it is finally used is just the energy that was invested in its original manufacture (minus any losses). Recognizing this fact is of critical importance. Any analysis of how hydrogen is to be used must also consider how the hydrogen is to be produced.(4)
A substantial quantity of hydrogen is already produced each year for non-energy industrial uses. Nevertheless, widespread fuel use would require a considerable expansion of today's market. Although this report does discuss the production and distribution technologies now in use, many of today's technologies would be difficult or impossible to scale up to meet future demands, were hydrogen to become a major factor in the energy industry as a whole. A variety of alternative technologies are therefore also discussed.
Hydrogen production in the United States is about 8.5 billion kilograms per year.(5) If used as a fuel, this amount would represent about 1.1 quads (quadrillion British thermal units) of energy, 1.3 percent of total annual U.S. energy consumption. Most, however, is used in non-energy applications such as the production of chemicals. About 95 percent of the hydrogen used in the U.S. market is produced by a chemical process known as steam methane reforming.(6) Next most common is extraction from the gaseous byproducts of other industrial processes. Third is electrolysis. This section discusses the various production processes that are in use or under investigation.
Steam reforming is a chemical process that makes hydrogen from a mixture of water and a hydrocarbon feedstock, usually a fossil fuel.(7) The most common feedstock is natural gas, which consists primarily of methane. When steam and methane are combined at high pressure and temperature, a chemical reaction converts them into hydrogen and carbon dioxide. The energy content of the hydrogen produced is actually higher than that of the natural gas consumed, but considerable energy is required to operate the reformer, so the net conversion efficiency is typically only about 65 percent.(8) Hydrogen produced by this technique can cost as little as 65¢ per kilogram.(9)
Other feedstocks can be steam reformed in essentially the same way, after partial burning to convert them into gaseous form. Some alternatives require additional procedures such as the removal of sulfur or other impurities. Coal is a common feedstock choice, though more so in other countries than in the United States. (Town gas, a hydrogen-containing mixture produced from coal, was formerly used for cooking and other domestic applications much as natural gas is used today.(l0)) The use of biomass instead of fossil fuels has been demonstrated on a small scale, and is expected to be the most cost-effective renewable option at large plant sizes,(ll) but at a minimum will need further technological advances before it can become a major commercial hydrogen source. Substantially increased demand for natural gas for steam methane reforming would be likely to push prices up considerably. Scenarios for widespread use of fuel hydrogen are therefore likely to include steam reforming of gasified biomass or coal. Because of their cost, oil, methanol, and other feedstock options are used for bulk-scale production only in unusual circumstances.
After steam reforming, the next most common source of hydrogen at present is the cleanup of industrial off-gases. Numerous industries give off high concentrations of hydrogen in their waste streams petroleum refineries, blast furnaces, and some chemical plants, for example. Collecting and purifying these gases is often cost-effective, with costs typically ranging between 80¢ and $1.20 per kilogram.(l2) Most off-gas hydrogen is used on-site by the industry that produces it, so although off-gas cleanup is an important feature of today's market, it seems unlikely that it could be expanded enough to meet the increased demand that would result from widespread use of hydrogen as a fuel.
Electrolysis means passing an electrical current through water to split individual water molecules into their constituent hydrogen and oxygen. Energy losses during this process are relatively modest: 65 percent energy efficiency is common,(l3) and state-of-the-art large electrolyzers can be 80 to 85 percent efficient.(l4) Electrolysis has captured considerable attention, even though it accounts for only a small fraction of current hydrogen production, because it is a clean process and water is abundant. At present, however, the technique is only used at relatively small plants, with a cost of $2.40-$3.60 per kilogram of hydrogen produced.(l5) This high cost is expected to limit electrolysis to niche markets in the near and mid term.
In the long term, could electrolysis become more competitive? At present, natural gas reforming is more than three times more energy efficient than electrolysis if fossil-source electricity is used.(16) This is primarily because the electricity production step, i.e. the power plant, consumes a large amount of energy. Pollutant emissions are also lower for gas reforming, even though electrolysis itself is clean, since power plant emissions are significant. Cost-effective and environmentally sound bulk-scale electrolysis, therefore, would require cheap electricity from a non-hydrocarbon source such as nuclear, hydropower, wind, or direct solar. With the exception of hydropower, which is in limited supply, none of these options is likely to be "cheap" in the foreseeable future. The availability of cheap hydropower has contributed to the strong Canadian interest in hydrogen as a fuel. The use of solar power has been discussed extensively and has come to be known as the "solar hydrogen" scenario (see below). The unfavorable economic position of electrolysis for bulk-scale production seems unlikely to change except possibly in the very long term. Small-scale electrolyzers, at or near the point of end use to avoid distribution costs, may show more promise, since scale economies are very different for electrolysis and for other techniques. It has been suggested, for example, that a small electrolyzer serving a single neighborhood or single filling station could compete favorably with steam reforming, since steam reforming's cost advantages only hold for large production volumes.(17) Electrolysis may also play a role in making the transition to increased hydrogen use.
A number of other ways of producing hydrogen have been studied, including photoprocesses, thermochemical processes, and radiolysis. None of these techniques has yet been used for hydrogen production outside the laboratory. (18)
Photoprocesses use the energy and other special properties of light (usually sunlight) to produce hydrogen from either water or biomass. There are three broad categories of photoprocess. Photobiological techniques are based on the photosynthesis cycle used by plants and by some bacteria and algae. The efficiency of photobiological hydrogen production is only 1 to 5 percent, but researchers hope to increase it to 10 percent or more. Photochemical processes mimic natural photosynthesis using synthetic molecules. This technique is only about 0.1% efficient now, but could in principle be much improved. Photoelectrochemical techniques use layers of semiconductor material separated by water. When exposed to light, the semiconductor layers produce an electrical voltage that splits the water into hydrogen and oxygen. The best prototypes yet demonstrated in the laboratory are about 13 percent efficient, but the maximum theoretical efficiency is believed to be more than 35 percent. It has been estimated that an efficiency in the field of 10 to 15 percent might be economical, but such estimates depend strongly on projections of equipment costs.(19) Note that since all these photoprocesses use light as their primary energy source, their efficiencies should not be used directly in cost comparisons with processes that use hydrocarbon fuels or electricity. Photoprocesses are a major component of current research programs.
Thermochemical processes use heat to split water into hydrogen and oxygen. The conceptually simplest version of this technique is direct thermal conversion, i.e. heating water to extreme temperatures, perhaps 3400 kelvin (K) or 5661°F. Because of the high temperatures required, however, direct thermal conversion is as yet impractical outside the laboratory. Chemical reactions can be employed to reduce the required temperature. Several alternatives have been studied, often involving complex multistep processes. Hybrid techniques that incorporate electrolysis into one or more of the reaction steps have also been investigated. There has been little recent work on thermochemical techniques.
Radiolysis is the splitting of water molecules by collisions with high energy particles produced in a nuclear reactor. Since the hydrogen and oxygen atoms thus produced quickly recombine to produce water again, radiolysis would probably be only about 1 percent efficient. Most experts agree that radiolysis is less promising than other techniques.
In its original and simplest form, the solar hydrogen scenario envisions producing electricity from sunlight using photovoltaic (PV) cells, electrolyzing water to produce hydrogen, and substituting this hydrogen for the oil and other fossil fuels in general use today. The term is now often used more broadly to include electrolysis based on other renewable sources of electricity, such as wind.(2l) This idea has received considerable attention largely because of the environmental benefits (see below) of using hydrogen instead of fossil fuels. It also addresses two barriers to the ultimate achievement of large-scale use of solar energy: that solar electricity cannot be used directly for non-electric applications, such as combustion engines, and that electricity is difficult and expensive to store.
Evaluating the cost-effectiveness and environmental impact of this scenario requires considering the broader energy system.(22) If hydrogen is needed, is solar energy the best source for it? Or would the solar energy be better used to produce electricity for the national power grid to reduce fossil fuel requirements at conventional power plants, with the hydrogen obtained elsewhere, perhaps by steam reforming of natural gas? The answer to these questions depends on the efficiency (in both energy and economic terms) of four conversion processes:
Hydrogen production from solar PV electricity has the advantage that electrolysis requires low-voltage direct current (DC), which is just what PVs provide, whereas the power grid operates on high-voltage alternating current (AC). on the other hand, producing hydrogen from fossil fuels has the advantage that steam reforming is more efficient than even the most modern fossil-fired power plants. These issues are being investigated but are not yet fully resolved. They are complicated by the fact that technologies for PVs, electrolysis, and advanced power plants are all still evolving in both cost and efficiency.
What are the prospects for solar hydrogen? In the near and mid term it is only likely to be practical in special-purpose niche markets or possibly as a storage technique for solar electricity. For the longer term, the outlook is still controversial, and depends on the future evolution of not only PV and electrolysis technologies, but also the competing technologies for producing hydrogen and electricity from fossil fuels, biomass, winds nuclear fission and fusion, and other sources.
The vast majority of the hydrogen produced today is transported only a short distance before use. Short-distance distribution is by pipeline, similar to the method used for natural gas. At present, long-distance distribution is primarily in liquefied form in large tanks. Both options pose certain technical challenges. Techniques for central bulk storage are also important for the distribution infrastructure. (Small-scale storage techniques for the point of end use are discussed in the next section.) If fuel use of hydrogen is to be expanded significantly, a shift of emphasis seems likely, from tanker to pipeline.
Distribution as a Liquid
At atmospheric pressure, liquid hydrogen (known as LH2) boils at 20K (-423°F), making liquefaction, storage, and distribution challenging. Liquefaction is also very energy-intensive. Nevertheless, greatly reduced space requirements compared with gaseous hydrogen make the use of LH2 an attractive option in some cases.
Hydrogen is usually liquefied in a complex, multi-stage process that includes the use of liquid nitrogen and a sequence of compressors.(23) Special procedures are required throughout the process to control the proportions of the two types of hydrogen molecule, known as ortho and para.(24) If this were not done, ortho hydrogen in the distribution and storage tanks would slowly but spontaneously convert to para hydrogen over a period of days or weeks, releasing enough heat to revaporize most of the liquid.
There are over 10,000 bulk shipments of LH2 per year in the United States, to over 300 locations; NASA is by far the largest customer.(25) Three main techniques are used for transportation: barges, truck trailers, and railcars. All these vehicles carry the hydrogen in pressurized, vacuum-insulated tanks, holding tens or hundreds of thousands of gallons (3500-70,000 kg). Until 1988, all liquid hydrogen available in the United States was produced domestically by just two companies. Since then two Canadian exporters have entered the market.(26)
The cost of distribution in tanks is likely to remain higher for LH2 than for other liquid fuels such as gasoline. This is because hydrogen takes up several times more space than an energy-equivalent amount of other fuels. It also requires special insulating equipment to keep it liquid.
Distribution as a Gas(27)
Compared with the hundreds of thousands of miles of existing natural gas network, the hydrogen pipeline system is very small, totalling only about 460 miles.(28) Air Products and Chemicals, Inc., has two gaseous hydrogen pipelines in the United States, one near Houston and one in Louisiana. Their total length is approximately 110 miles, and they carry an average of 190,000 kilograms of hydrogen per day to more than 20 customers at refineries and chemical plants. Air Products also operates a 30-mile, 50,000-kg/day pipeline in the Netherlands.(29) Praxair, Inc., operates pipelines near Houston and in Indiana, totalling 160 miles and delivering about 200,000 kg/day to refineries, chemical plants, and steel manufacturers. Several other shorter lines deliver "over the fence" to individual industrial customers.(30)
If the use of hydrogen pipelines were to be expanded, possible embrittlement problems would have to be considered. Pipes and fittings can become brittle and crack as hydrogen diffuses into the metal of which they are made. The severity of this problem depends on the type of steel and weld used and the pressure in the pipeline. The technology is available to prevent embrittlement, but depending on the configuration being considered, distribution costs may be affected.
The capacity of a given pipeline configuration to carry energy is somewhat lower when it carries hydrogen than when it carries natural gas. In a pipe of a given size and pressure, hydrogen flows about three times faster, but since it also contains about three times less energy per cubic foot, a comparable amount of energy gets through the pipe. Since compressors operate on the volume of a gas, however, not its energy content, the capacity of the compression stations (on an energy basis) is about one third less with hydrogen. In a pipeline system optimized to carry hydrogen, the pipe's dimensions and the size and spacing of the compressors would be changed to accommodate these factors. All told, transmission costs might be about 50 percent higher than for natural gas.
Some segments of the small hydrogen pipelines mentioned above were originally designed to carry natural gas. Could the existing natural gas networks be used to carry hydrogen on a larger scale, even though they are not optimized to do so? This question requires further study (see "Recent Legislation", below) but probably each pipeline segment would have to be considered on a case-by-case basis. Some steels and welds would be compatible, but others might be subject to embrittlement, particularly the welds in older segments. Compressors would generally have to be refitted with new seals and valves.(3l) Department of Transportation safety standards for hydrogen and natural gas pipelines are the same.
Any large-scale hydrogen distribution system must address the problem of bulk storage, to provide a buffer between production facilities and fluctuations in demand. Low-cost and efficient bulk storage techniques are a major research goal.
One can store hydrogen as either a gas or a liquid. The most widely studied options for storing gaseous hydrogen are underground caverns and depleted underground natural gas formations.(32) Although hydrogen is more prone to leak than most other gases,(33) leakage has been shown not to be a problem for these techniques. For example, town gas (a mixture containing hydrogen) has been stored successfully in a cavern in France, and helium, which is even more leak-prone than hydrogen, has been stored in a depleted natural gas field near Amarillo, Texas. The energy consumed in pumping gas in and out of such storage facilities may be significant, however. Above-ground storage tanks at high pressure are another option.
A certain amount of gaseous storage can be achieved by allowing modest pressure changes in the distribution pipeline system. In the case of natural gas, this technique is used to help manage transient demand fluctuations, such as the morning and evening peaks in residential demand in urban areas.(34) Though the same technique might be useful for hydrogen, its potential is limited, particularly if the hydrogen is to be produced from intermittent sources such as solar or wind.
Storage in liquid form uses tanks similar to those used for liquid hydrogen distribution. Kennedy Space Center uses an 850,000-gallon sphere near the launch pad, and can transfer fuel from this tank to the space shuttle at up to 10,000 gallons per minute.(35) Storage at liquefier plants is in vacuum-insulated spherical tanks that usually hold about 400,000 gallons.(36) The energy required for liquefaction may not be a barrier if the hydrogen is to be transported as a liquid anyway, or if the end-use application requires its fuel to be in liquid form.
Most of the common applications of hydrogen in the United States today do not involve its use as a fuel. Hydrogen is widely used as a feedstock in the production of ammonia, the refining of petroleum products, and the production of methanol. It is also used in smaller quantities for the production of other chemicals, for food hydrogenation, in making steel and glass, and in the electronics industry. Overall, demand for such uses of hydrogen in the commercial sector is expected to grow at about 5 percent per year in the near term.(37) These non-fuel applications are likely to help stimulate further development of general hydrogen-related technologies and infrastructure, but they will not be discussed further in this report.
There are two distinct ways in which hydrogen can be used as a fuel.(38) One is combustion, much like any other fuel. Since every fuel behaves somewhat differently, some redesign is often needed when converting a device to burn hydrogen. The second technique is the fuel cell. A fuel cell is an electricity-producing device, similar to a battery but operating on externally supplied fuel rather than on its own components. Several different types of fuel cells have been developed.(39) All of them could be hydrogen fueled, but most are aimed more at high-efficiency generation of electricity from natural gas and other hydrocarbons.
The space program is so far the only major non-experimental user of hydrogen for fuel purposes. Spacecraft use hydrogen in two main ways: they burn it for propulsion, and they use it in fuel cells to produce electricity. In fact, the major impetus for development of practical fuel cells was the need for onboard power for the Apollo program. The space shuttle takes off with 100,000 kg of LH2 in its fuel tanks, and it uses an alkaline fuel cell (65 percent efficiency) for its onboard electricity needs. These applications also have secondary benefits: fuel cells produce water as a byproduct, and LH2 can be used to keep the rest of the spacecraft cool.(40)
Considerable work has been done on the use of hydrogen as an airplane fuel.(41) Certain special features of this application appear to make it particularly attractive. First is hydrogen's high energy content for its weight. The weight of fuel that must be carried is an important factor for aircraft. Among other consequences, reduced weight would allow engine downsizing, reducing not only cost but possibly also engine noise—often a contentious issue near airports. The use of liquid (or slush) hydrogen would allow the fuel itself to be used to cool engine parts and, particularly in supersonic and hypersonic planes, the airplane structure itself.(42) Hydrogen's high flame propagation speed is also an important feature for hypersonic aircraft. One drawback is hydrogen's relatively low energy content for its volume, leading to larger (though lighter) fuel tanks. The major technical problems to be addressed are not in the engine, but in handling the cryogenic liquid fuel.
The National Aero-Space Plane (NASP), currently being developed by NASA and the Defense Department, is to be hydrogen-fueled. Plans are to store the fuel on board in slush form, i.e. part liquid and part solid. Though this requires even lower temperatures than liquid storage, it reduces the necessary fuel tank volume and further enhances the ability to use the hydrogen as a heat sink.(43)
Cars, Trucks, Buses
Cars, trucks, and buses can either burn hydrogen in an internal combustion engine (ICE) similar to a conventional gasoline engine, or they can use a fuel cell to power an electric motor. The fuel cell option is generally considered preferable for the long term, because although it requires more changes to existing vehicle designs, it allows considerably higher efficiency, and hence a longer range on the same amount of fuel. Fuel cells are one way to make "zero emission vehicles" (ZEVs) which will have to constitute 2 percent of new vehicle sales in California beginning in 1998.(44) For the nearer term, a number of prototype hydrogen ICE vehicles have been built and tested. Adding a small fraction of hydrogen to another fuel, such as gasoline or natural gas, is another option.
Tailpipe pollutant emissions from hydrogen-fueled vehicles are minimal Hydrogen ICE vehicles emit nitrogen oxides (NOx), but their emissions rate can be lower than in a similar gasoline-fueled vehicle because the ignition characteristics of hydrogen are more easily suited to the "lean burn" technique.(45) Hydrogen fuel cells have virtually no emissions even of NOx.(46) Vehicles that mix hydrogen with other fuels can also achieve environmental benefits. For example, one study estimates that adding 5 percent hydrogen to natural gas (to make "hythane") would reduce NOx emissions by 6 to 8 times more than converting 5 percent of the fleet to run on pure hydrogen.(47) This has been referred to as "environmental leverage".
The difficulty of onboard storage is the main barrier to fueling vehicles with hydrogen. Because it is a gas, hydrogen at room temperature and pressure takes up about 3,000 times more space than an energy-equivalent amount of gasoline.(48) This obviously means that compression, liquefaction, or some other technique is essential for a practical vehicle. So far, storage requirements tend to severely limit range. Several techniques are being studied to overcome this problem.(49) The four main contenders are compressed gas, cryogenic liquid, metal hydride, and carbon adsorption. Of these, the first two appear most promising for the near term. Metal hydrides are also relatively mature, but require further R&D to be competitive. Carbon adsorption is not yet a mature technique, but it appears very promising if R&D goals can be met. Other techniques are being studied, but as yet are ''insufficiently characterized for evaluation at the systems level".(50) It is likely that different techniques will turn out to be most appropriate for different applications -- buses are less size-sensitive than cars, for example.
Compressed gaseous hydrogen storage is at room temperature in a high-strength pressure tank. Including the weight of the tank, compressed gas storage holds about 1 to 7 percent hydrogen by weight, depending on the type of tank used.(5l) Lighter, stronger tanks, capable of holding more hydrogen with less weight, are more expensive. Compressing the hydrogen gas at the filling station requires about 20 percent as much energy as is contained in the fuel.(52)
Cryogenic liquid storage is at 20K (-486°F) in a heavily insulated tank at ordinary atmospheric pressure. As a liquid, hydrogen contains almost three times more energy than an equal weight of gasoline, and takes up only about 2.7 times as much space for an equal energy content.(53) Including the tank and insulation, this technique can hold as much as 16 percent hydrogen by weight.(54) on the other hand, liquefaction at the filling station requires about 40 percent as much energy as is contained in the fuel.(55) Another disadvantage is the so-called "dormancy problem": despite the insulation, some heat leaks into the tank, eventually boiling off the hydrogen. A "cryopressure" system stores liquid hydrogen in a pressure vessel like that used for compressed gaseous storage, allowing containment of the boiled-off gas. This helps with dormancy, but increases weight and size.
Metal hydride systems store hydrogen in the interatom spaces of a granular metal. Various metals can be used. The hydrogen is released by heating. Metal hydride systems are reliable and compact, but can be heavy and expensive. Varieties now under development can store about 7 percent hydrogen by weight.(56) Unlike the compressed gas and cryogenic liquid techniques, metal hydrides require little or no "overhead" energy when refueling. They do require energy to release the fuel, however. For low-temperature varieties this energy may be available as waste heat from the fuel cell or engine. For high-temperature varieties, which tend to be the less expensive ones, as much as half of the vehicle's energy consumption may go to releasing the fuel from the metal.(57)
The carbon adsorption technique stores hydrogen under pressure on the surface of highly porous superactivated graphite. Some varieties are cooled, others operate at room temperature. Current systems store as much as 4 percent hydrogen by weight. Researchers hope to increase this to about 8 percent, even for the room temperature variety.(58) Carbon adsorption is very similar to compressed gas storage except that the pressure tank is filled with graphite; the graphite adds some weight but allows more hydrogen to be stored at the same pressure and tank size.
Glass microspheres are small, hollow, glass micro-balloons whose diameters vary from about 25 microns to 500 microns (1/1000 inch to 20/1000 inch), and whose wall thicknesses are about 1 micron. They can be used in large beds to store hydrogen at high pressures. The microspheres are filled with hydrogen gas at temperatures of 200 to 400 degrees Centigrade. The high temperature makes the glass walls permeable, and the gas fills the spheres. Once the glass is cooled to room temperature, the hydrogen is trapped inside the spheres. The hydrogen can be released as needed by heating the spheres. The spheres can also be crushed to release hydrogen. This option precludes sphere recycling, but is desirable for applications where weight is important.(59)
Onboard partial oxidation reactor is a concept proposed to help bring about a transition from conventional automobiles to cars powered by hydrogen fuel cells. First, a shift would be made from the internal combustion engine to the fuel cell using a conventional hydrocarbon fuel such as gasoline or diesel coupled to an onboard partial oxidation process and a water gas shift reaction process. The partial oxidation process yields 30 percent hydrogen gas directly and 20 percent carbon monoxide. Then, the carbon monoxide is chemically reacted with steam to produce additional hydrogen and carbon dioxide gas, which is readily usable by a hydrogen fuel cell. This fossil-to-hydrogen fuel system would be used as a "bridge" until R&D yields a commercially ready advanced hydrogen storage system or a suitable hydrogen carrier.(60)
Other techniques are still in the early stages of development. One uses powdered iron and water. At high temperatures these react to produce rust and hydrogen. Other methods are similar to the metal hydride option, but substitute certain liquid hydrocarbons (also known as "recyclable liquid carriers") or other chemicals for the metal.
Although hydrogen-burning appliances have not received as much attention as some other types of application, most appliances that burn natural gas can be converted to hydrogen fairly easily. For example, a home in Provo, Utah, has used hydrogen to fuel its oven, heater, range, barbecue, fireplace "log", and other equipment for several years.(61) The main modification needed is the use of special burners to reduce the flame temperature and limit NOx formation. Simply burning hydrogen to produce low-grade heat, however, is usually an inefficient use.
Hydrogen end-use applications that have been suggested for the electric utility industry include energy storage, power production using fuel cells, and long-distance energy transmission.
The idea of hydrogen-based energy storage is to produce hydrogen with excess power, presumably by electrolysis, then use a fuel cell to convert it back into electrical energy when needed. This would reduce generating costs by levelling the load on conventional power plants. Most analysts now believe that this would be less cost-effective than other storage technologies such as batteries, compressed air, pumped hydro, superconducting magnetic storage, and so on.
Since hydrogen is not a primary fuel, but must rather be produced from some other energy source, generating power with utility-scale hydrogen fuel cells is essentially equivalent to using hydrogen for energy storage. Using smaller fuel cells for dispersed generation near centers of electricity demand has also been suggested.
Hydrogen could be used for electrical transmission by replacing long-distance transmission cables with a system of electrolysis plants, hydrogen pipelines, and a fuel cells. Electricity at the source would be used to produce hydrogen, which would be piped to the demand center and used to produce electricity again. Some analysts expect this method to be more efficient than conventional overhead power lines for long transmission distances, starting somewhere between 1000 and 2250 kilometers.(62) The rationale is that gas losses in pipelines are enough lower than resistive losses in power lines to outweigh energy losses in the electricity-hydrogen-electricity conversion process. Other possible advantages of hydrogen pipelines might include improved ability to control and direct the flow of energy.
This section addresses a number of policy questions about hydrogen that may be of interest to the Congress. Those relating to hydrogen's impact on the Nation's broad energy picture, such as its effect on the economy, the environment, and energy security, are relevant for the long term.(63) Others, such as the current Federal research and development program, are more immediate. The question of safety is also addressed, and recent hydrogen-related legislation is summarized.
Public perception of hydrogen's safety is tainted by images of the Hindenburg disaster,(65) but hydrogen is intrinsically no more dangerous than many other fuels. Its different characteristics require different safety equipment and procedures, but all fuels have some potential for accidents; if they didn't burn, they wouldn't be much use as a fuel. Hydrogen is already routinely and safely used worldwide in the petroleum and chemical industries and elsewhere. It was also routinely used in the United States as a fuel (a component of "town gas") before natural gas became widely available. Town gas is still used in some countries. One study has concluded that hydrogen ranks between propane and methane (natural gas) in safety.(66)
Hydrogen's physical properties do make its safety characteristics rather different from those of other fuels. Its low density means that it tends to rise and disperse into the atmosphere in the event of a leak, rather than remaining in a "puddle" near the ground. This increases safety in well ventilated applications. Its low density also means that a hydrogen explosion releases less energy in a given volume than an explosion of other fuels, and compared to gasoline or natural gas, hydrogen requires much higher concentrations in the air to produce an explosion rather than just a flame. On the other hand, hydrogen's low ignition temperature and flammability over a wide range of concentrations make leaks a significant fire hazard, especially in confined spaces such as a garage. Because it is clear and odorless, leaking hydrogen is also more likely to go undetected than a leak of gasoline or most other fuels. Even the flame of burning hydrogen is invisible.
Techniques of leak detection have been and continue to be an R&D priority. A simple approach is to add an odorant like that added to natural gas, or possibly a colorant, or both.(67) Any addition may detract somewhat from the environmental cleanliness inherent to pure hydrogen, however, and additives would need to be chosen with care to avoid destroying other important features. For example, contaminants may reduce the efficiency and/or lifetime of a fuel cell.
As with most fuels, the fire and explosion hazards discussed above are the main safety concerns. In some situations there may be other safety issues, for example in applications that involve hydrogen storage under high pressure or at extreme low temperatures. These problems can be minimized with proper equipment design and operating procedures, however, and are generally agreed to be of less concern than hydrogen's flammability.
Hydrogen is currently more expensive than other fuel options, so it is likely to play a major role in the economy only in the long term, if technology improvements succeed in bringing down costs. The costs of various production methods have been discussed above. Note that higher prices for fossil fuels would not necessarily make hydrogen more cost-competitive in the short term. Since fossil fuels are currently the main source of heat, feedstock, and electricity for hydrogen production plants, rising prices for gas, oil, or coal would also drive up the price of hydrogen.
Since hydrogen can be produced in many different ways, from many different sources, most hydrogen-related international commerce is likely to be not of fuel but of technology: plant components, engineering services, construction know-how, and so on. These areas could potentially represent new export markets.
The use of hydrogen as a fuel is inherently very clean. Hydrogen consumed by either combustion or a fuel cell produces only water as an end product. The high temperatures involved in combustion may stimulate some nitrogen oxide (NOx) production from nitrogen and oxygen in the air, but this problem is familiar from other fuels and can be controlled. Unlike other fuels, hydrogen contains no other pollutant-producing elements, so it has no potential to produce sulfur dioxide, carbon monoxide, carbon dioxide, volatile organic chemicals, etc.
The environmental consequences of hydrogen production must also be considered, however. As mentioned above, production from fossil fuel feedstocks by steam reforming leads to carbon dioxide emissions greater than those from simply using the feedstock itself as a fuel. Steam reformers must also somehow dispose of feedstock impurities such as sulfur. Electrolysis is responsible for the emissions of whatever power plants are used to generate the needed electricity. Production of hydrogen from sustainably harvested biomass, solar energy, or other renewable sources might considerably reduce production emissions, but (as described above) these techniques are not yet fully developed.
The Department of Energy has examined the full-cycle environmental effects of various scenarios for hydrogen production and use. It concludes that "substantial emissions can be generated when hydrogen is produced from certain energy sources",(68) namely fossil fuels. The details depend on the full pathway from production to end use, and analysis of various possible pathways is continuing.
In the near term, hydrogen will have little or no impact on energy security, i.e. on the United States' dependence on foreign sources of energy; hydrogen is a longer-term option. If it were eventually to become a major factor in the broad energy picture, however, there could be a significant positive effect on energy security, particularly since there are many oil-substituting applications, such as fueling cars and planes. As mentioned above, international commerce in a hydrogen-based energy industry would likely be more in technology than in the fuel itself. Hydrogen itself can be produced using a variety of primary energy sources that are domestically available. This could reduce the dominance of resource-rich nations in international energy markets.
Federal Research and Development(69)
Hydrogen research and development (R&D) activities at the Department of Energy (DOE) are coordinated by the Office of Conservation and Renewable Energy's Office of Energy Management, which chairs the Hydrogen Energy Coordinating Committee. A number of other offices in DOE are also involved, as shown in the table below. Most of DOE's hydrogen R&D work is performed at the National Renewable Energy Laboratory. The recently formed Hydrogen Technical Advisory Panel, consisting of experts from industry, academia, and other organizations, advises DOE in carrying out the program. In FY95, DOE's budget for hydrogen R&D is $10 million. Other hydrogen-related research at DOE is distributed among a variety of programs, and it is difficult to separate a "hydrogen" spending figure for them. One related development is utility-scale fuel cell research in the Office of Fossil Energy. Although fuel cell technology could be crucial to the future of hydrogen, this program fucuses primarily on the use of natural gas and coal, with hydrogen appearing only temporarily as an intermediate processing step. The proper definition of "hydrogen-related" is a matter of continuing controversy within the professional community involved with hydrogen technologies.
Hydrogen-Related Research Areas at the Department of Energy
Research at NASA on the use of hydrogen as a fuel is driven by the specific needs of major programs such as the Shuttle, the National Aerospace Plane, and others. Most of the work on these systems is unique to the specific application under development, but some of the technology is also of general use, particularly in the areas of storage and distribution, leak detection, and safety practices. NASA's budget for hydrogen R&D is spread over a number of programs and is difficult to separate from general engineering work on those programs. The Kennedy Space Center in Florida supplies liquid hydrogen for all other Federal users as well as that used by NASA itself.(70) on January 31, 1995, NASA officials dedicated a new fuel cell testbed at Edwards Air Force Base in California for development of a regenerative fuel cell system that directly converts hydrogen fuel and oxygen into electricity and water. The water produced is stored and then regenerated back to hydrogen and oxygen by means of a solar-powered electrolyzer.
In the Department of Defense, the annual budget for hydrogen production and storage research is estimated to be less than $1.5 million. This amount is distributed over several research centers, under both the Navy and the Air Force.
DOE is a member of the Hydrogen Implementing Agreement of the International Energy Agency (IEA). Participation in IEA's programs on Hydrogen Production and Hydrogen Conversion, Storage, and Safety is intended to help monitor international research results and factor them into U.S. efforts.
The Spark M. Matsunaga Hydrogen Research, Development, and Demonstration Act of 1990 (PL 101-566) led DOE to prepare a comprehensive 5-year management plan and 5-year implementation plan for hydrogen R&D. The Act also directs DOE to conduct an R&D program (consistent with the management plan), demonstration projects, and a technology transfer program. It established the Hydrogen Technical Advisory Panel and provides for interagency coordination and consultation.
Section 2026 of the Energy Policy Act of 1992 (PL 102-486) authorizes the DOE hydrogen R&D program for five years.(71) It directs that the program be in accordance with the Matsunaga Act and that it include work on  renewable production of hydrogen,  transportation of hydrogen via the existing natural gas pipeline system,  hydrogen storage for vehicle use,  fuel cells for hydrogen-powered vehicles, and  other topics as necessary. The Matsunaga Renewable and Ocean Energy Technology Center, established by section 2119, is to include among its R&D activities the production of hydrogen from renewable energy.
During the second session of the 103d Congress, the Hydrogen Energy Research Program was introduced as Title I of H.R. 4908, the Hydrogen, Fusion, and High Energy and Nuclear Physics Research Act of 1994 (72) The bill authorized $132 million over four years. The main goal was to demonstrate by the year 2000 the practicality of utilizing hydrogen for transportation, industrial, residential and utility applications on a broad scale. It specified that DOE should conduct at least 12 technical demonstration projects by the year 2000 covering new production sources, storage, transportation, and uses in fuel cells and other applications. The bill passed the House, but received no action in the Senate.
The Hydrogen Future Act of 1995 (H.R. 655) was introduced by Chairman Walker of the House Science Committee on January 24, 1995. At introduction, it was nearly identical to H.R. 4908 from the 103d Congress. At the Science Committee's hearing on February 1, criticism was expressed by DOE and some Committee Members of the emphasis on, and specificity of, demonstration projects in the bill.(73) As a result, the Chairman revised the bill, refocusing it more on basic research and development. Chairman Walker introduced an amendment in the nature of a substitute at a markup hearing held on February 10. Incorporating amendments approved at the markup, the Committee reported (H.Rept. 104-95) a further amended version of the bill on March 30.
According to Chairman Walker, this is now a basic research and development bill that also allows for technical demonstrations of theories and processes. It leaves the task of commercial development to the private sector. H.R. 655 requires 20 percent cost-sharing for R&D projects and 50 percent cost-sharing for demonstration projects. A progress report to Congress is required after 18 months. Advice from academia and the private sector is expected to ensure that the economic benefits of the program accrue to the United States. The bill authorizes $25 million in FY 1996, $35 million in FY 1997, and $40 million in FY 1998. Also, for fiscal years 1996 through 1998, it would limit the total DOE authorization for energy supply research and development activities to the amount obligated in FY 1995.
Based on DOE testimony and Committee discussion at the February 1 and 10 hearings, the primary remaining issue appears to the authorization cap that would be set on DOE energy R&D spending. Such a cap would require that any increase for the hydrogen program be drawn from other DOE energy R&D supply programs such as fusion energy R&D, nuclear fission R&D, renewable energy R&D or fossil energy R&D.
Different sources use a variety of ways of measuring hydrogen production, distribution, and consumption. For consistency, this report has used weight, in kilograms (kg), throughout. Many of the figures quoted in the text have been converted from the units of the cited source. Here is a list of conversion factors:
l. Jules Verne, The Mysterious Island (New York: Signet Classics, 1986), p. 256.
2. U.S. Dept. of Energy, Hydrogen Program Plan: FY 1993-FY 1997 (June 1992).
3. Other terms commonly used are energy sector and energy currency.
4. In this sense, hydrogen is somewhat like electricity, which must also be produced from some other energy source
5. R. B. Moore and D. Nahmias, "Gaseous Hydrogen Markets and Technologies", in Proceedings: Transition Strategies to Hydrogen as an Energy Carrier—First Annual Meeting of the National Hydrogen Association (Electric Power Research Institute: Palo Alto CA, March 1991), p. 11-2.
6. National Hydrogen Association, "A Practical Hydrogen Development Strategy", June 1990, p. 3.
7. A hydrocarbon is a chemical compound made up of hydrogen and carbon atoms.
8. A. John Appleby, "Hydrogen as a Transportation Energy Vector", First NHA Meeting, p. 7-6.
9. Moore and Nahmias, "Gaseous Hydrogen Markets and Technologies", p. 11-7. Their estimate is based on a plant producing 250,000 kg per day, with a natural gas cost of $2 per million Btu. See the appendix for a note on units.
10. Town gas is still used in parts of Europe, South America, and Asia where natural gas is unavailable or expensive. (Joan Ogden and Joachim Nitsch, "Solar Hydrogen", in Renewable Energy: Sources for Fuels and Electricity (Island Press, Washington DC, 1993), p. 936)
l l. Eric D. Larson and Ryan E. Katofsky, "Production of Hydrogen and Methanol via Biomass Gasification'', in Advances in Thermochemical Biomass Conversion (Elsevier, London, 1992).
l2. Moore and Nahmias, "Gaseous Hydrogen Markets and Technologies", p. 11-7. These figures are based on a 25,000 kg/day plant.
13. DOE, Program Plan, p. C-3.
l4. Alexander K. Stuart, "A Perspective on Electrolysis", First NHA Meeting, p. 13 4. Stuart states that efficiencies may climb to as much as 90 percent "over time". Losses in the electrolyzer's ancillary electrical equipment, however, may reduce the net efficiency by a few percent below these figures. (Debbi L. Smith, National Hydrogen Association, personal communication, January 21, 1993.)
15. Moore and Nahmias, "Gaseous Hydrogen Markets and Technologies", p. 11-7. These figures are based on a 2,500 kg/day plant, with electricity costs of 2-4 cents per kilowatt-hour. Stuart, "A Perspective on Electrolysis", p. 13-9, estimates a cost of only $1.34/kg. The latter figure incorporates substantially lower estimates of fixed and capital costs, and includes credits of 70e/kg for byproduct sales of oxygen and heavy water. If electrolysis became a major hydrogen source, the valu e of the byproducts would be expected to fall as supply outpaced demand.
16. DOE, Program Plan, p. 12. The overall efficiency disadvantage of electrolysis is due primarily to the large energy losses in converting fossil fuel to electricity. Note that most electricity in the United States indeed originates from fossil fuels.
l7. Joan Ogden, Princeton University Center for Energy and Environmental Studies, personal communication, December 21, 1992.
18. Except where noted, the main source for this section is Stanley Bull and Art Nozik, "Hydrogen Production by Photoprocesses", First NHA Meeting, section 16.
19. U.S. Dept. of Energy, The Potential of Renewable Energy: An Interlaboratory White Paper (March 1990, SERI/TP-260-3674), p. I-4.
20. See, for example, Joan M. Ogden and Robert H. Williams, Solar Hydrogen: Moving Beyond Fossil Fuels (World Resources Institute: Washington DC, October 1989), and Ogden and Nitsch, "Solar Hydrogen".
21. The major nonelectric renewable source of hydrogen, gasified biomass, is also sometimes included, but will not be in this report. It has been described above in the discussion of steam reforming.
22. This discussion does not address the separate question of whether increased use of solar energy is likely and/or desirable. It considers only the relative merits of using any solar power that may be available either as electricity or as hydrogen.
23. See R. A. Beddome, "Liquid Hydrogen Manufacturing and Distribution Technology", First NHA Meeting, section 12. An alternative technique is discussed in Stephen F. Kral et al., "Industrial Magnetic Refrigeration for Hydrogen Liquefaction", in A Blueprint for Hydrogen's Future (proceedings of the third annual meeting of the National Hydrogen Association, March 18th-20th, 1992), p. 4-2S4-33.
24. Both forms consist of a pair of hydrogen atoms. The difference is in the alignment of the electrons' "orbits" about the two atoms.
25. Addison Bain, "Hydrogen Infrastructure—USA", paper presented at the 1991 Society of Automotive Engineers Aerospace Atlantic meeting, Dayton OH, April 2S, 1991, p. 4.
26. Barbara Heydorn, "Hydrogen Industry and Markets", First NHA Meeting, p. 21-6.
27. Except where noted, the sources for this discussion are Ogden and Nitseh, pp. 934-5; David Nahmias, Air Products and Chemicals, personal communications February 22, 1993; and Renny Norman, Gas Research Institute, personal communication, February 24, 1993.
28. Robert L. Mauro, "Hydrogen Technology Assessment", in Hydrogen Applications for a Sustainable Energy Future (proceedings of the second annual meeting of the National Hydrogen Association, March 13th-15th 1991), p. 3-3. In the original: 750 kilometers.
29. Moore and Nahmias, "Gaseous Hydrogen Markets and Technologies", p. 11-13.
30. Debbi Smith, National Hydrogen Association, personal communication, January 21, 1993
31. This applies to reciprocating compressors. Centrifugal compressors would not work on hydrogen at all and would have to be replaced entirely. Roth types are common in the natural gas pipeline system.
32. See Christopher F. Blazedket a Underground storage and Transmission of Hydrogen", Third NHA Meeting, p. 4-203-4-221.
33. Hydrogen molecules are smaller than most others, so they tend to slip more easily through tiny pores in the containing material. For example, a hydrogen-filled balloon goes flat more quickly than an ordinary air-filled one.
34. Renny Norman, Gas Research Institute, personal communications February 24, 1993.
35. Addison Pain, "Space Shuttle Program", First NHA Meeting, p. 4-2.
36. Beddome, "Liquid Hydrogen Manufacturing and Distribution Technology", p. 12-2.
37. Bain Hydrogen Infrastructure—USAGE p. 4.
38. Hydrogen could also be the fuel for fusion energy systems. since it is a nuclear rather than a chemical process, this report will not consider fusion.
39. See, for example, John H. Hirschenhofer, Latest Progress in Fuel Cell Technology" IEEE AES Systems Magazine, November 1992, p. 18.
40. Bain "Space Shuttle Program", p. 4-2.
4 l. See, for example, G. Daniel Brewers Hydrogen Aircraft Technology (CRC Press, Coca Raton FL, 1991).
42. The term "hypersonic" usually refers to flight at Mach 6 or faster. Hydrogen's cooling properties and other features make it the only practical fuel for speeds above Mach 5. (Brewer, Hydrogen Aircraft Technology, p. 10)
43. For more information, see John P. Thomas, Jr., KNAPP and the U.S. Hydrogen Industry" Third NHA Meeting, p. 2-19-2-26.
44. For further details, see California Air Resources board, "Regulations for Low-Emission Vehicles and Clean Fuels", September 1990.
45. Ingersoll, "Energy Storage Systems", p. 445
46. At high temperatures, NOx is formed from the nitrogen and oxygen in the air, regardless of the fuel. Fuel cells, however, particularly those likely to be used in vehicles, operate at much lower temperatures than a combustion engine.
47. DOE, Program Plan, p 13. For more information on hythane, see S. Foute et al., tithe Denver Hythane Project -- Update", Third NHA Meeting, p. 5-21-5-33.
48. lngersoll, Energy storage Systems p 344
49. For more details, see David H. Swan, Overview of Hydrogen storage Options, Third NHA Meeting, pp. 4-35-4-42; and U.S. Department of Energy, Office of Propulsion Systems, "Feasibility Study of Onboard Hydrogen Storage for Fuel Cell Vehicles", January 1993
50. DOE, "Feasibility Study", p. 5.
51. Appleby, "Hydrogen as a Transportation Energy Vectors p. 7-3; DOE, "Feasibility Study", p. 13.
52. Ibid., p. 10.
53. Appleby, "Hydrogen as a Transportation Energy Vector" p. 74.
54. DOE, "Feasibility Study", p. 13
55. Ibid., p. 10.
56. P J. Skerrett, "Solid Progress in Hydrogen Storage", Technology Review February/March 993 p. 15.
57. DOE, "feasibility Study", p. 22.
58. Ibid., p. 26.
59. Personal communication with Dr. Glenn Rambach, Lawrence Livermore National Laboratory, Jan. 25, 1995.
60. U.S. Congress. House. H.R. 655--The Hydrogen Future Act of 1995. 104th Cong., 1st Sess., Feb. 1, 1995. Testimony of Dr. Robert Williams, p. 81 and 93.
61. Ingersoll, "Energy Storage Systems", p. 344.
63. Some analysts believe that the use of hydrogen mixtures such as hythane, rather than pure hydrogen, may be a nearer-term proposition.
64. Applicable regulations and industry standards are summarized in Daniel Lynch, "Hydrogen System Design Safety", Second NHA Meeting, p. 21-3.
65. Since hydrogen burns with an invisible flame, the flames seen in pictures of this event are actually those of burning diesel fuel from the engines. The hydrogen used for buoyancy burned also, but invisibly. In fact, "because hydrogen dissipates quickly, no Hindenburg fatality was the result of a burn from hydrogen" (National Hydrogen Association, Handling Hydrogen Safely).
66. Michael Swain, "Hydrogen Safety", First NHA Meeting, p. 10-1.
67. The term illuminant is sometimes used instead of colorant.
68. DOE, Program Plan, p. 16
69. Except where noted, this section is based on DOE, Program Plan, pp. 29-33, 40-43.
70. Most of this paragraph is based on personal communication with Addison L. Bain, NASA Manager of Hydrogen Programs, May 1st 1992.
71. The Renewable Hydrogen Energy Research and Development Act of 1991 (S. 1269 of the 102d Congress, by Senator Harkin) included provisions similar to those of section 2026 of PL 102-486, but was considerably more detailed. It would also have established a program of hydrogen R&D joint ventures.
72. H.R. 4908 (Lloyd) was introduced in the second session of the 103d Congress. On July 14, 1994, the House Science Committee's Subcommittee on Energy held a hearing on H.R. 4908, Overview of DOE's Hydrogen R&D Program [No. 154]. on July 21, 1994, the Subcommittee held a Markup Hearing, The Hydrogen and Fusion Research Authorization Act of 1994 [No. 156].
73. U.S. Congress. House. Committee on Science. H.R. 655--The Hydrogen Future Act of 1995. Hearing, 104th Cong., 1st Sess. Feb. 1, 1995. 147 p. [No. 2]