Defense

high-volumetric energy density power sources. As a result, to

meet its unique needs, DOD likely will have to increase its dependence on nuclear power and support R&D that investigates ways

to use hydrogen to synthesize hydrocarbon fuels in an environmentally compliant fashion. Several suggestions and recommendations will be made in this regard.

Hydrogen as a Fuel

Hydrogen is a much-studied element, large quantities of which

are produced today for industrial applications. Most of this hydrogen

is a chemical commodity rather than an energy commodity. There

are, of course, some specialized uses of hydrogen as a fuel, such as in

rocket propulsion. Given the high-energy content of hydrogen and its

intrinsic non-pollutant properties, it is reasonable to ask: why has it

not been used widely as a fuel? Table 1 indicates some of the reasons.

In this table, various fuels have been normalized to a typical

gasoline. The comparison is done on a mass and volume basis. The

second column of table 1 shows that, on a pound-for-pound basis,

Overview

Energy issues have been at the center of the national security

debate for some time, and the current situation in the Persian

Gulf underscores the strategic importance of sound energy policy.

Activities or developments—geopolitical, environmental, technological, or regulatory—that materially change the energy security equation are, naturally, of great interest to the Department

of Defense (DOD). The announcement by President George Bush

in his State of the Union address that he intends to accelerate

research and development (R&D) for hydrogen-powered vehicles

toward the objective of total U.S. energy independence has great

potential impact on DOD. This paper examines a number of technical issues connected with energy independence through hydrogen and how they might affect DOD. We conclude that the move

to a hydrogen economy will be a massive undertaking, requiring

large investments and decades to accomplish. We will show that,

with few exceptions, pure hydrogen is not a viable fuel for DOD

missions, primarily because of the DOD requirement for compact,

Hydrogen as a Fuel for DOD

by Timothy Coffey, Dennis R. Hardy, Gottfried E. Besenbruch, Kenneth R. Schultz,

Lloyd C. Brown, and Jill P. Dahlburg

A publication of the

Center for Technology and National Security Policy

National Defense University

NOVEMBER 2003

Number 36

Horizons

November 2003 Defense Horizons 1

Table 1. Energy content (versus mass and volume) of various fuels referenced to gasoline

Fuel Energy (per unit mass) Energy (per unit volume) Temperature ( ̊C) Mass (per unit volume)

Gasoline 1.0 1.0 25 1.0

JP–5 .97 1.1 25 1.0

Methanol .44 .51 25 1.1

Ethanol .61 .69 25 1.1

Liquid hydrogen 2.6 .27 -253 .1

Metal hydride .046 .36 25 2.5

Methane (@ 3,000 psi) 1.1 .29 25 .25

Hydrogen gas (@ 3,000 psi) 2.6 .06 25 .02

Liquid propane (@ 125 psi) 1.0 .86 25 .73

Methane (@ 10,000 psi) 1.1 .97 25 .81

Hydrogen gas (@ 10,000 psi) 2.6 .2 25 .08

Lithium ion battery .019 .035 25 2.03

Sources: <http://www.methanol.org/methanol/fact/sumprop.cfm>; <http://www.airliquide.com/en/business/products/gases/gasdata>; <http://webbook.nist.gov/cgi/cbook.cgi?ID=C64175&Units=SI&Mask=2#Thermo-Condensed>;

<http://www.cea.fr/gb/publications/Clefs44/an-clefs44/clefs4470a.html>; L. Schlapbach and A. Zuttel, “Hydrogen-Storage Materials for Mobile Applications,” Nature 414, no. 15 (November 2001); <http://www.atsdr.cdc.gov/toxprofiles/

tp121-c3.pdf>.
hydrogen has a higher heating value than the other fuels shown. This

well-known fact is often touted as one of the great advantages of

hydrogen. However, the volume comparison (third column) shows

that hydrogen has the lowest heating value per unit volume among

the fuels listed (excluding the lithium ion battery). Even liquid

hydrogen at -253  ̊C has only one-fourth the volumetric energy content of gasoline. Furthermore, liquid hydrogen requires complex

cryogenics, while gasoline is liquid at room temperature and can be

stored and transported easily in inexpensive containers. 

The volumes required for the storage and transportation of

fuels and the costs of the fuel storage containers are big issues and

significant factors in why hydrogen has not emerged as a generalpurpose fuel to date. 

There are important fuel properties other than energy density.

Among these are the limits of flammability, flame speed, minimum

ignition energy, auto ignition temperature, ignition properties in the

presence of catalysts, and environmental impact. Hydrogen has very

wide limits of flammability (4–75 percent hydrogen concentration)

and a very high flame speed. It also has a low spark ignition energy

(0.0182 millijoules [mJ]) and an auto-ignition temperature somewhat higher than hydrocarbon fuels. However, unlike hydrocarbon

fuels, hydrogen can ignite at low temperatures in the presence of

catalysts such as rust, and the ensuing flame is nearly impossible to

detect with the naked eye. On the positive side, hydrogen is an environmentally benign fuel, producing mainly water when combusted or

used in fuel cells. All of the fuel properties of hydrogen impact both

positively and negatively on its viability as a fuel. 

Another important consideration in evaluating a fuel is the

ease of storage and distribution. Because of its low volumetric

energy density, hydrogen can be viable as a fuel only in a liquid state

or at very high pressures. Yet using liquid hydrogen as a fuel has disadvantages from purely energetic considerations. About 30 percent

of the energy content of hydrogen is required just to liquefy it. This

energy is not recoverable in a practical sense. For special applications where costs are not a consideration, liquid hydrogen indeed

may be viable as a fuel. However, for large-scale energy applications,

a requirement for liquefaction would seem to put hydrogen at a great

disadvantage. 

Compressing hydrogen gas also requires energy, but only a fraction of that required for liquefaction. For example, table 1 shows that

hydrogen at 10,000 pounds per square inch (psi) has a volumetric

energy density approaching that of liquid hydrogen. Compressing

hydrogen from atmospheric pressure to 10,000 psi requires about 11

percent of the hydrogen energy content. This is a more reasonable

energy penalty but does involve dealing with fuel at very high pressures. Progress is being made in producing relatively light-weight

composite containers for this purpose. Containers are now available

to store hydrogen compressed to 5000 psi at about 11 percent hydrogen by weight.1 The total container volume, however, is about twice

the hydrogen storage volume. This exacerbates the hydrogen storage

problem and presents DOD with some unique safety problems, especially in combat situations. 

The above discussion implies that the best distribution of

hydrogen from centralized source to user would be through gas

pipelines. Liquefying hydrogen and then transporting the liquid

would seem to be viable only for special applications such as space

launch. Trucking highly compressed gas over long distances would

not be economically viable due to the low volumetric energy content

of the compressed hydrogen. A key question regarding pipeline distribution of hydrogen will be how much power must be supplied to

overcome pressure drops along the pipeline. For fully turbulent flow,

the required power can be shown as 

= ((v2/2)(4L /D)f)(D2 v/4)

where:  is the gas density; v is the gas velocity; L is the pipeline

length; D is the pipeline diameter; and f is the friction coefficient.2

Since the current pipeline standards have been set by the natural gas distribution system, it is useful to compare the power that

must be supplied to hydrogen relative to that which must be supplied

to natural gas (mostly methane) for the same energy flux down the

pipeline. This ratio is: 

H/M = (DH/DM)(vH/vM)3(H /M)(fH/fM)

where the subscripts H and M refer to hydrogen and methane respectively. If one were to use the same pipeline diameter (DH = DM) and

the same pressure and then increase the velocity to obtain the same

energy flux through the pipeline, the pipeline energy loss for hydrogen would be about three times that for methane. This is not a very

attractive approach, especially for long pipelines. As another option,

if one were to pump at the same pressure and velocity but increase

the pipeline diameter to obtain the required energy flux, then the

hydrogen energy loss would be about 15 percent of the methane

energy loss. Changing the parameters yet again, if one used the same

diameter pipe and pumped at the same velocity but increased the

pressure, the hydrogen loss would be about 30 percent of the

methane loss. Another factor to be considered is Graham’s Law,

which indicates hydrogen will leak at about three times the rate of

natural gas, thereby creating potential safety problems unless special attention is paid. 

The conclusion here is that the use of the current natural gas

pipeline infrastructure (beyond the existing rights of way) is probably not viable in the long term for a move to a hydrogen economy. A

pipeline infrastructure specifically designed for hydrogen will be

required. This is not a surprising result, but it will require a substantial long-term investment. For example, a 12-inch diameter

pipeline designed for hydrogen costs about $1 million per mile.3

In light of the above, table 2 provides an examination of hydrogen as a fuel by rating its properties as an energy source, a coolant,

and a medium to be stored and distributed. Table 2 illustrates how

2 Defense Horizons November 2003

Timothy Coffey (coffeyt@ndu.edu) holds the Edison Chair of Science and

Technology in the Center for Technology and National Security Policy at the

National Defense University (NDU) and is a senior research scientist at the

University of Maryland. Dennis R. Hardy (hardy@ccf.nrl.navy.mil) is head of

the fuels section in the chemistry division, U.S. Naval Research Laboratory

(NRL). Gottfried E. Besenbruch (besenb@gat.com) is associate director of the

division of inertial fusion technology (IFT) in the energy group at General

Atomics (GA). Kenneth R. Schultz (ken.schultz@gat.com) is deputy for

operations in the energy group at GA. Lloyd C. Brown (lloyd.brown@gat.com) 

is a senior technical advisor in IFT at GA. Jill P. Dahlburg (dahlburg@

utopia.nrl.navy.mil), director of IFT at GA through May 2003, is senior scientist

for science applications at NRL.
many of the features that make hydrogen desirable from one perspective make it undesirable from another perspective.

Despite some of the known, unfavorable qualities inherent in

hydrogen, it is important to note that hydrogen is produced and distributed safely in large quantities today and that procedures have

been developed to overcome many of its negative attributes at these

quantities. However, tables 1 and 2 suggest that, all other things

being equal, if hydrogen were readily plentiful, combining it with

carbon to make hydrocarbon fuels would be the most desired option

because of the logistic simplicity and high-volumetric energy density

found in hydrocarbon fuels. In light of this, why even consider moving to a hydrogen fuel economy? At least two reasons support such a

move: the ultimate depletion of oil and natural-gas reserves, and

environmental considerations such as the production of carbon dioxide as a greenhouse gas. While there is considerable disagreement

over when fossil fuel resources will be depleted, there is little disagreement that eventually they will run out.

In the case of oil reserves, the expected time frame of depletion

ranges from 20 to perhaps 100 years. The American Petroleum Institute suggests a 95 percent probability that the world’s remaining oil

reserves will last another 56 years and a 5 percent probability that

they will last another 88 years.4 If this is the case and hydrogen is to

be the replacement fuel, then making it viable must be an immediate

priority. With regard to the issue of greenhouse gases, the timeframe

to watch is set by the time at which the CO2 concentration in the

atmosphere reaches a level where it produces irreversible climate

effects. The predictions in this regard are based upon complex computer models and have considerable uncertainty associated with

them. Most project U.S. temperature increases ranging between 3 and

4  ̊C over the next 100 years.5 Such rises in average temperature

would have significant climatic impact. Therefore, within the current

level of understanding, actions required to address oil reserve depletion and greenhouse gases would need to be effected on a similar

timescale—that is, about 50 years.

DOD as a User of Hydrogen

DOD has been involved in examining hydrogen as a fuel since

at least 1944, when the Navy Bureau of Aeronautics began serious

consideration of orbiting spacecraft.6 This decision led to the 1940s

design of liquid-hydrogen-fueled rockets. Many of these designs and

the test data collected later played a significant role in the space

program.

In the mid-1950s, the Air Force ran a major classified program

called Suntan, the objective of which was to eclipse the Central

Intelligence Agency-developed U–2 aircraft by means of the development of a hydrogen-powered aircraft. While this airplane never

materialized, the facilities constructed during this project were key

to the subsequent space program. In about the same timeframe, the

National Advisory Committee for Aeronautics undertook unclassified

design studies for hydrogen-powered aircraft. One mission involved

airplanes using turbojet engines flying at a speed of Mach 4 and an

altitude of 30,500 meters (m) while carrying a payload of 4,500 kilograms (kg). When designed for hydrogen, the airplane turned out to

be 91 m long with a gross mass of 130,000 kg, of which one-third was

hydrogen. The airplane using JP–4 fuel was half as long, but had a

mass 40 percent greater than the hydrogen configuration, with the

JP–4 making up 60 percent of the mass. The hydrogen-fueled airplane had a range just over 5,000 km compared to 3,000 km for the

JP–4 airplane. 

Studies also were done on hydrogen-fueled ramjet missiles,

which outperformed the turbojets. This work on hydrogen-powered

aircraft came to a close with the launch of Sputnik. Attention then

turned to rockets, which became the approach to launch spacecraft.

The designs the Navy Bureau of Aeronautics had considered 15 years

earlier became important during this early phase. After much jockeying the newly created National Aeronautics and Space Administration pursued the use of hydrogen for rocket propulsion, leading to

the Saturn rockets for the manned moon missions and eventually the

space shuttle program of today. DOD benefited from this for launch

November 2003 Defense Horizons 3

Table 2. Scoring hydrogen versus desirable properties of a fuel

Desirable Property Hydrogen as an energy source Hydrogen as a coolant Storage and distribution

High volume energy density Poor Poor

High mass energy density Good Good

High exhaust velocity Good

Low combustion temperature Good Poor

High thermal stability Good Good

High specific heat/ conductivity Good

Low vapor pressure Poor Poor

Low critical temperature Good

High reaction rate Good Poor

High flame speed Good Poor

Low ignition energy Good Poor

Wide flammability limits Good Poor

Low environmental impact Good Good
of its own satellites, but DOD itself focused on ballistic missiles,

where the need for readiness argued for the use of solid propellants. 

Chronologically, the next serious look DOD took at hydrogen

seems to have occurred during the 1973 oil crisis. A useful document

in this regard was prepared by Carhart et al.,7 which examined the

potential utility of hydrogen for Navy applications. Many of the

points made in that study remain valid today.

The 1950s high-altitude hydrogen aircraft designs are informative with respect to DOD missions and the role of hydrogen. For missions with long legs where one can afford large aircraft, hydrogen,

because of its energetic combustion properties, can be the best performer. However, for missions constrained by volume—true for most

DOD missions—hydrogen, with its low volumetric energy density, is

problematic. Also, the cryogenic requirements for liquid hydrogen

and the very high-pressure requirements for gaseous hydrogen further complicate design scenarios.

Navy ships powered by fuel oil provide an example of the complications inherent with hydrogen as a fuel source. If liquid or highly

compressed hydrogen were substituted for the fuel oil, fuel volume

would quadruple to achieve the same number of steaming days

between refuelings. This volume simply is not available on present

Navy ships. The other option—refueling four times as often—is

incompatible with the Navy mission. Therefore, while hydrogen

could fuel gas turbines, a direct replacement of fuel oil with hydrogen is very unlikely. This situation could be improved by expected

progress in fuel cells. Fuel cells project conversion efficiencies of 80

percent compared to the 35 percent conversion efficiencies of gas

turbines. By combining fuel cells with highly efficient (greater than

90 percent) electric motors, hydrogen fuel storage demands could be

reduced from four times the current fuel volume requirement to

about twice the volume requirement for the same mission. Perhaps

with redesigned Navy ships, including substantial manning reduction through automation, mission capability could be maintained

with hydrogen fuel. However, even if the volume storage problem

could be solved, serious safety problems are involved with storing

several hundred thousand cubic feet of liquid hydrogen at -253  ̊C or

similar volumes of hydrogen gas pressurized to 10,000 psi. This is

quite evident from table 2. The confined nature of Navy spaces and

the low ignition energy for hydrogen could lead to an untenable situation, even in the absence of combat. 

The situation is similar for high-performance military aircraft.

At present, to accomplish the same mission with hydrogen, fuel storage volumes would have to be increased by a factor of four. Hydrogen

fuel stored in the wings would not be practical, because the large

surface-to-volume ratio would increase the boil-off of liquid hydrogen and thereby further reduce range. The use of cryogenic or highpressure storage tanks that also serve structural purposes does not

appear to be viable. Wing pods, while addressing the above problems,

greatly increase air drag and reduce rapid maneuverability. This

leaves the option of storing the hydrogen in the fuselage by increasing its diameter or its length, as was considered in the 1950s. For low

altitude aircraft, the drag would be increased, thereby reducing performance. As a result, it does not appear hydrogen would be a viable

fuel for the high-performance low altitude aircraft central in DOD

present capability. 

For long-range missions such as reconnaissance, where high

maneuverability is not a requirement, the situation may be different.

In this case, expanding the fuselage to accommodate the required

extra fuel storage volume may be feasible, and the low fuel weight of

hydrogen may be an advantage. Currently, designs are being undertaken to examine this approach for commercial aviation.8 Here the

primary issues likely will be cost of flight and airport safety, rather

than engines or fuselage parameters.

The use of hydrogen as a fuel for DOD aircraft missions that

operate in the upper atmosphere is also potentially viable. At high

altitudes, the atmospheric drag is low and aircraft tend to be large in

order to obtain the necessary lift. In this case, hydrogen, with its

light weight and high energy per unit mass, is intrinsically attractive.

Hydrogen also could be attractive for DOD missions that are

powered by batteries. Table 1 shows the volume energy density of liquid hydrogen to be nearly eight times that of lithium ion batteries

while the mass per unit volume of liquid hydrogen is about 5 percent

that of lithium batteries. Similar numbers apply for hydrogen compressed to 10,000 psi. If hydrogen were used to power a fuel cell that

then provided the electric power in lieu of batteries, considerable

mission enhancement might result. For example, the Unitized

Regenerative Fuel Cell, coupled with lightweight hydrogen storage,

demonstrated about 450-watt hours/kg, which is more than twice the

energy available from lithium ion batteries and 10 times that of lead

acid batteries.9 It is quite likely, therefore, that the use of hydrogen

powered fuel cells will greatly increase the mission capability of such

platforms as electric-powered unmanned vehicles. The importance

of extending the battery life for mobile computers, global positioning

system tracking devices, and other such devices was noted during

Operation Iraqi Freedom.

10 Hydrogen-powered fuel cells may prove

useful here, particularly when coupled with a lightweight and disposable storage medium, such as glass microshells.11

The majority of DOD missions likely cannot be met by the use

of pure hydrogen as a fuel, primarily because of its low volumetric

energy density. Replacing or replicating the performance of hydrocarbon fuels, especially for high-performance aircraft, will be difficult. Yet, given the eventual depletion of oil reserves and the need to

eliminate the addition of carbon dioxide to the atmosphere, DOD will

need to make accommodations. In this situation, it is quite likely

most Navy platforms would become nuclear powered, since nuclear

power demonstrably meets the Navy mission and generates no carbon dioxide. Nuclear power, however, is not a solution for aircraft.

Alternative means to fuel aircraft need to be found, and appropriate

R&D will need to be done. Potential solutions do exist, such as 

CO2-neutral generation of synthetic carbon-based fuels using materials readily available in marine environments. The ocean, for example, has an almost uniform carbon dioxide concentration of about 

0.1 gram per liter of water (0.01 percent by weight).12 The atmosphere is another readily available source of carbon dioxide (0.056

percent by weight).12 If an efficient process could be found to make

hydrogen from seawater, and if the carbon dioxide could be recovered from seawater at sufficiently high rates, it might be possible to

synthesize hydrocarbon fuels, with no net production of CO2 in the

4 Defense Horizons November 2003
atmosphere, through chemistry such as the Fischer-Tropsch

process.13 Should such a scenario prove viable, it would resolve the

continuing DOD need for high-performance hydrocarbon fuels in an

environmentally compliant fashion. 

Scale of Undertaking and Production Issues

To better grasp the issues of moving to a hydrogen economy, the

ultimate scale of such a move must be understood. Today, the United

States consumes about 4 x 1016 British thermal units (BTUs) worth

of oil per year.14 In terms of average power consumption this is about

1,200 gigawatts. To put this in perspective, this is larger than the

average total electrical power output of the United States. Using a

higher heating value of 142 MJ/kg for hydrogen shows U.S. consumption of oil to be the equivalent of 300 million tons of hydrogen

per year. While this production rate can be envisioned (it is within a

factor of thirty of the present U.S. hydrogen production rate of 11

million tons per year), one must recognize the implications of the

fact that hydrogen does not exist in its elemental form on the earth.

It cannot be pumped out of the ground like oil or natural gas. It must

be extracted from other materials such as oil, water, natural gas, or

biomass. This extraction, in turn, typically requires more energy than

is returned when the hydrogen is used as fuel. Therefore, even before

getting into a detailed analysis of production, storage, and distribution for a hydrogen economy, it should be obvious that such a move

will be a massive undertaking, requiring many decades and huge

investments to produce the required infrastructure. How the nation

moves in this direction undoubtedly will have a great impact on the

ultimate success of the move. DOD should be a serious player in this

undertaking because it will be greatly impacted by its outcome.

Today, hydrogen is produced in large quantities as a chemical

commodity. It is used principally in fertilizer manufacture and for

hydrogenation of hydrocarbon fuels to increase their energy content

and to improve their emission properties. It is expected that demand

for hydrogen as a chemical commodity will grow for the foreseeable

future. However, as long as ample oil and natural gas reserves are

present, the volumetric energy comparisons (table 1) will incline

the economy heavily in favor of hydrocarbon fuels even as environmental concerns increase. The same argument applies to energy

security. Very strong national security arguments have been made in

favor of fuels that are not vulnerable to geopolitical instability.

Unfortunately, a near-term solution to this problem is unlikely, and

an economy that is largely non-fossil-fuel based is decades away.

Ultimately, however, a solution must be found. Competition for

diminishing oil and natural gas reserves will increase in the coming

years. If hydrogen is deemed to be the proper course, then, considering the massive task of moving toward a hydrogen economy, the

groundwork to move in this direction needs to begin soon. To do this,

many impediments—technical, environmental, economic, social,

and political—will need to be resolved in ways that contribute to

practical near-term needs while, at the same time, preparing the way

for long-term solutions. 

Hydrogen is produced, stored, transported, and distributed to

end-users in large quantities today, so a great deal already is known

in these areas. The areas where efforts should be focused are

straightforward to identify, although not as straightforward to

resolve. Six of the methods for producing hydrogen, some still in the

design phase, are discussed in more detail below. 

Steam Reforming of Methane

The vast majority of hydrogen (95 percent) is produced by the

process of steam reforming of methane (SMR), which involves the

endothermic reaction of methane with high-temperature steam

according to the reaction:

CH4 + 2H2O + energy = 4H2 + CO2

According to this reaction, each gram of hydrogen requires 

2.4 g of methane and 6.0 g of steam and produces 7.3 g of CO2. If the

energy is provided by burning natural gas, the net result is to produce about 3 moles of H2 per mole of CH4 used. This would increase

the amount of methane used and the amount of CO2 released per

gram of hydrogen produced by a factor of 4/3. To produce the energy

equivalent of the oil consumed by the United States each year would

require about 3 x 1014 grams of hydrogen (300 million tons), so the

SMR process to produce this hydrogen would consume 7.8 x 1014

grams of CH4 and 1.8 x 1015 grams of water and produce 2.2 x 1015

grams of CO2. Burning methane to get the equivalent energy would

consume about 25 percent less methane and produce about 25 percent less CO2. Therefore, based purely on energy considerations,

using steam reforming of fossil hydrocarbons to make hydrogen from

which to produce energy does not make a lot of sense. It does not

reduce significantly either the consumption of hydrocarbon fuel or

the production of CO2 (unless one considers sequestration of the

CO2, which process could be equally well coupled to current stationary-site fossil fuel energy production methods), yet it introduces the

complexities of a hydrogen fuel.

Use of hydrogen, however, does make possible the use of fuel

cells for conversion of the fuel energy to useful work. Fuel cells offer

the potential for high efficiency as well as the possibility of sequestration of vehicle propulsion-related CO2, because the hydrogen for

the fuel cells would be produced at stationary sites. The primary current application of steam reforming of fossil hydrocarbons is to produce hydrogen as a chemical commodity. Some of this hydrogen

could and should be used as a fuel to test methods for hydrogen storage, transportation, and delivery to the energy end user, but SMR is

not the solution to long-term hydrogen production for a hydrogen

economy, nor is it an appropriate path to address the unique longterm needs of DOD. 

Other approaches must be explored if the long-term issues of

oil and natural gas reserve depletion are to be addressed and the

greenhouse gas problem that results from CO2 emission is to be

resolved. It is not possible in this paper to examine all possible alternate hydrogen production technologies. However, to gain some perspective, we will discuss briefly several different approaches for the

production of hydrogen and comment on the appropriateness of DOD

participation in their development. In particular, we will discuss

electrolysis; gasification of coal; gasification of biomass; photonic (or

comparably, wind) processes; and thermo-chemical processes.

November 2003 Defense Horizons 5
Electrolysis

Electrolysis is a well-known process using electricity to produce hydrogen from water. Electrolysis has the desirable feature of

producing no greenhouse gases unless the method of producing electricity for the electrolysis generates them. In addition, modern electrolyzers are highly efficient. They produce about one cubic meter of

hydrogen with an energy value of 3.2 kW-hour for an electrical

energy investment of 3.9 kW-hour (80 percent efficiency).15 Since a

cubic meter of hydrogen has a higher heating value of 11.7 MJ, about

3.4 x 1012 m3 of hydrogen would be required to provide for the annual

U.S. oil consumption. To produce the required hydrogen by electrolysis would require about 1,500 gigawatts average electrical power, an

amount that exceeds the entire electrical generating capacity of the

United States. Where will this electricity come from? If electrolysis

is a solution attractive to DOD, then electricity from nuclear power

also would be of interest to DOD. Additionally, it has been suggested

that generation of the electricity from ocean thermal gradients may

be of interest to DOD.16

Photonic Processes

A number of schemes are available that use photonic processes

to create hydrogen directly from sunlight. These include photovoltaic cells coupled to electrolyzers, photo-electrochemical cells,

and photo-biological systems using algae. 

To interpret these photonic systems, one metric that can be

applied is to examine the total area of solar collection required. The

peak solar flux reaching the earth's surface is about 1,000 W/m2

. This

leads to an average flux (averaging over day, night, solar angle, etc.)

of about 200 W/m2. The U.S. oil consumption power equivalent is

about 1.2 x 1012 W. Therefore, a collection area of about 6 x 109 m2

(about 2,400 square miles) would be required in order to provide the

solar energy equivalent, neglecting any photovoltaic infrastructural

fill factors. Furthermore, this estimate does not include conversion

efficiencies for producing hydrogen, which, for example, are

presently at about 6 percent using photovoltaic cells plus electrolyzers.17 This implies a minimum solar collection area of about 1011

square meters or 40,000 square miles. Since DOD is responsible for

about 2 percent of U.S. oil consumption, a DOD-unique solution

would require about 800 square miles or 512,000 acres. While DOD

has ample land to house such a facility (for example, China Lake in

California is about one million acres), the likelihood of DOD wishing

to manage and maintain such a large physical plant is low, especially

in view of the fact that other approaches could lead to very compact

solutions for DOD requirements. Photoelectrochemical cells claim

an efficiency for the production of hydrogen of about 10 percent,18

which corresponds to a minimum collection area of about 480 square

miles for DOD-unique requirements, again probably not a promising

area for DOD-unique solutions. Further, since the approximate conversion factor for land mass requirements from photovoltaic to wind

power is 4.9,19 using wind power to generate the energy for DODunique requirements is even less promising.

Currently, proposed photo-biological approaches do not seem

sufficiently developed to make the simple calculations above. One of

the more recent and supposedly promising approaches uses a variant

of green pond algae (C Reinhartii) to produce 2 milliliters (ml) per

hour of hydrogen from a one-liter culture.20 The optical depth of this

system is less than 5 centimeters (cm), implying a surface area of

200 cm2 to produce 2 ml of hydrogen per hour. The hydrogen equivalent to the United States oil consumption requires about 4 x 1014 ml

of hydrogen per hour. This indicates a minimum solar collection area

that exceeds the total landmass of the United States. While

researchers in this area project a ten-fold increase in production

with a mutant strain of the algae presently under development, substantially more work needs to be done on this process for it to be

competitive.

The above simple analyses suggest that photonic approaches to

the production of hydrogen are probably not well suited for DODunique requirements.

Gasification

Another area of potential interest for the production of hydrogen is the gasification of solids such as coal or biomass, a process in

which a carbon-based feedstock is reacted with steam and oxygen or

air under high temperature and pressure to produce a gaseous mixture that contains H2, CO, and CO2.

21 Of the possible hydrocarbon

feedstocks, coal is the leading candidate. It is a readily available,

long-term, highly concentrated energy source. The cost of producing hydrogen from coal is dominated by the capital and operating

costs associated with handling solids. Of greater concern are the

environmental issues of mine site restoration, residual ash disposal,

and the capture and sequestration of waste CO2. Biomass may be a

partial solution because waste biomass is easily available, but the

amount of hydrogen generated from this source will be small compared with the needs of the hydrogen economy. The environmental

concerns related to the large land tracts required for biomass

energy plantations further make it an unlikely candidate. Ultimately, these processes probably are not well suited for DOD-unique

solutions. 

Thermochemical Cycles

A final process for consideration involves thermochemical

cycles. A number of thermochemical hydrogen-producing cycles

have been considered for splitting water to make hydrogen. One of

the best developed of these schemes is the sulfur-iodine (S-I) thermochemical cycle.22 This closed scheme reacts water and sulfur

dioxide with iodine to produce sulfuric acid and hydrogen iodide.

The sulfuric acid is decomposed to sulfur dioxide, water, and oxygen,

with the sulfur dioxide then returned to the process. The hydrogen

iodide is decomposed to produce iodine and hydrogen, the hydrogen

is collected, and the iodine is recycled. The process requires a hightemperature heat source. Design studies indicate that a continuous

thermal source at about 950  ̊C peak temperature, providing heat

over the range of 500–950  ̊C would result in a thermal to hydrogen

energy efficiency of 50 percent.23 Under these conditions a 30

megawatt (MW) thermal energy source would provide 10 tons of

hydrogen per day. Since the hydrogen is produced from water, such

a system would provide hydrogen without producing greenhouse gas.

The question here becomes: what provides the thermal energy? It

would seem that solar collection or nuclear power would be viable

for this. From a DOD viewpoint, the solar (or wind) approach suffers

from the same large real estate requirements identified for photonic

6 Defense Horizons November 2003
processes. Moreover, researchers still are investigating the efficiency

of the S-I cycle in an environment that has diurnal temperature variability. This would seem to leave only the nuclear option for the use

of this scheme for DOD-unique requirements.

In 1997, SYNTECH, Inc., prepared a report that compared

hydrogen production costs for a number of the processes discussed

above, including SMR, electrolysis, coal gasification, and biomass

gasification.24 Table 3 is derived

from this report along with data provided by General Atomics (GA)

regarding the thermochemical

process mentioned above using a

modular helium gas reactor (MHR)

to provide heat for the thermochemical processes and/or electricity for

the electrolysis process discussed in

the SYNTECH study. The table presents capital costs and annual operating costs for each method per

annual ton of hydrogen produced. The costs are expressed in 1997

dollars to be consistent with the SYNTECH report.

The highest capital cost results for the electrolysis plus the gas

turbine-MHR plant. The gasification of biomass approach led to the

second most costly plant and the most costly hydrogen. The thermochemical approach (MHR S-I) and coal gasification had comparable

capital costs, with coal gasification leading to somewhat higher

priced hydrogen. Yet one must be careful in taking the absolute numbers in such analyses too seriously. The results can be very sensitive

to the cost of feedstock, prevailing interest rates, and taxes. One also

should expect continued progress in the various approaches to

hydrogen production. For example, the intensive research program

under way on fuel cells for automotive applications undoubtedly will

substantially lower the cost of fuel cells. This will have a direct effect

on the cost of electrolysis cells, since they use the inverse of the fuel

cell process, thereby making electrolysis more competitive than is

indicated in table 3. Nevertheless, the analysis does give a sense of

the ranking of the various approaches and of the scale of the move

to a hydrogen economy. 

The SMR approach listed in table 3 can be ruled out, because it

does not resolve the natural gas depletion problem or the CO2 problem. Among the remaining options, coal gasification and thermochemical approaches each have capital costs of about $4,500 per

annual ton of hydrogen produced. About 3 x 108 tons of hydrogen per

year would be required to provide the energy equivalent of the oil

consumed by the United States each year. This results in a capital

investment requirement of about $1.5 trillion just for these sorts of

hydrogen production facilities, with electrolysis being approximately

1.5 times higher. The remaining required infrastructure is likely to

have comparable costs. These are huge costs, but they are not surprising and are representative of

the investments that have been

made by the oil industry to date.25

Conversion to a hydrogen economy

will take decades to put in place,

just as did the oil infrastructure

that it would be structured to

replace.

In consideration of the above

analysis, it seems that DOD should

pay particular attention to the nuclear option because of its relatively compact land requirements, high-volumetric energy density,

and the inevitable long-term commitment to nuclear power for DOD

missions. In the next section we will explore that option in somewhat

more detail.

The Nuclear Option

Water-splitting, the separation of water into hydrogen and oxygen, can provide an environmentally clean source of hydrogen if the

primary source of energy is not a source of greenhouse gases. Solar

or nuclear energy will likely be the most appropriate source, considering the massive energy requirements identified above for the conversion to a hydrogen economy. 

As previously noted, two approaches can be used for hydrogen

production from water using nuclear energy, electrolysis, and thermochemical cycles. The first is to use electricity generated by

nuclear power to separate water into hydrogen and oxygen by electrolysis. For light water reactors (LWRs), this is a low-temperature

approach with about 25 percent net efficiency. Essentially, LWRs are

a proven technology, with most of the issues being economic. With a

November 2003 Defense Horizons 7

conversion to a hydrogen 

economy will take decades to 

put in place, just as did the 

oil infrastructure that it

would be structured to replace

Table 3. Annual capital and operating costs associated with adding the ability to produce an additional ton 

of hydrogen production capability each year for various technologies

Capital cost Operating cost

Technology ($ per annual ton) ($ per annual ton) Cost $/kg† @20% ROI Cost $/kg† @ 12.7% ROI

Steam Methane Reforming†† 1,196 500 .93 .81

MHR S-I 4,675 397 1.86 1.43

Coal Gasification 4,348 832 2.26 1.85

Biomass Gasification 5,555 308 3.42 2.58

Electrolysis††† + Gas Turbine MHR 6,967 668 2.83 2.21

† Assumes 5 percent per year depreciation on capital costs and 20 percent and 12.7 percent return on capital investment (ROI), and full recovery of operating costs. Analysis based upon “Hydrogen Production Costs—A Survey” prepared by 

SENTECH, Inc., December 1997, and on GA data.

†† Assuming natural gas cost of 2.167 $/GJ.

††† Uses SYNTECH estimates for the electrolysis plant and GA estimates for a gas turbine MHR electric power plant to supply the electricity.
high-temperature heat source (600–950  ̊C), such as produced by an

MHR, net hydrogen producing efficiencies as high as 40–50 percent

could be obtained by using high-temperature electrolysis, a developing technology that could provide higher efficiency by using both

heat and electricity from the reactor.26

The second major approach to nuclear production of hydrogen,

suited primarily to a high-temperature, gas-cooled reactor system, is

to use high-temperature nuclear-generated heat directly to drive a

thermochemical water-splitting cycle, a set of chemical reactions

that separates water into hydrogen and oxygen at moderate temperatures. A significant research effort worldwide in the 1970s discovered more than 100 different possible thermochemical water-splitting cycles. Researchers at GA invented several of these cycles,

among them the sulfur-iodine (S-I) cycle.27 This cycle also was studied in Japan, where a complete laboratory-scale test loop was operated.28 A team consisting of GA, Sandia National Laboratories (SNL),

and the University of Kentucky, identified S-I from among 115 known

thermochemical cycles as the best suited for coupling to nuclear

power.29 SNL also carried out an evaluation and determined that

helium gas-cooled reactors, like the MHR, are best for coupling to

the S-I thermochemical water-splitting cycle.30 A complete flow

sheet design for the S-I cycle with this reactor predicts good efficiency at reasonable cost.31 While previous studies provide evidence

that the S-I cycle is technically feasible, work is now under way to

prove the cycle is also practical.32

The Electric Power Research Institute recently has completed

a study of various hydrogen production technologies.33 Their results

show that comparison of the economics of alternative means of

hydrogen production depends on

such factors as capital charge rate,

cost of feedstock, value of oxygen

sale, and cost or penalty for CO2

capture and sequestration. That

study estimated the cost of hydrogen for a number of possible methods of production, including fossilfired steam reformation of

methane, nuclear-heated steam

reformation of methane, and the

nuclear-heated S-I cycle. Both of

the latter processes made use of the MHR, which has high gas outlet

temperatures and can operate safely in the temperature regime

needed for efficient S-I cycle hydrogen production.34 The economic

parameters used in the computation were capital rates for a typical

public utility, $20/ton oxygen sales credit, and $30/ton CO2 capture

and sequestration cost. The results indicate that, with reasonable

credit for oxygen sales and moderate CO2 cost, S-I water-splitting

could be economically competitive with steam reformation of

methane at current natural gas costs ($4/million BTU for largescale, long-term contracts).35

In the general sense, one of the advantages of nuclear energy is

the large energy resource that uranium represents.36 While only 0.7

percent of uranium is fissile U–235 isotope, the other 99.3 percent

U–238 is “fertile” and can be converted to fissile Pu–239 by capture

of a neutron in the core of a reactor. Similarly, fertile thorium–232

can be converted to fissile U–233. The nuclear energy resources are

summarized in table 4.

Used in today’s LWRs, the known reserves of uranium, could

provide our current nuclear electricity needs along with our current

hydrogen needs by electrolysis for almost 200 years. Even our current known reserves of “low-cost” uranium would supply all current

nuclear electricity and hydrogen needs for the next 34 years.

LWR nuclear reactors burn U–235 and convert some U–238 to

Pu–239 with a conversion ratio (CR) of about 0.5 atoms produced per

atom consumed. This means that they can extend the reserves of

U–235 by up to about a factor of 2. (Fuel consumption scales as

1/(1–CR).) To extend the life of our nuclear fuel resources, reactors

with higher conversion ratio are needed. The helium gas-cooled reactor, which has higher neutronic efficiency than LWRs and, thus, the

potential to operate with a CR of about 0.75, would extend the U–235

reserves by another factor of 2.

To extend nuclear fuel resources even further and ultimately

make all the resources of both U–238 and Th–232 accessible will

require breeder reactors or reactors with a CR greater than unity.

(That is, they produce more than one atom of fissile fuel from fertile

materials in the core for every fissile atom they consume.) Experimental breeder reactors successfully have operated on both the

U–238/Pu–239 and the Th–232/U–233 cycles. An important feature

of these reactors is that they could be used to fuel other reactors. For

example, a breeder reactor with a CR of 1.25 could produce enough

excess fuel to support a burner reactor of the same thermal power

with a CR of 0.75. In this way, breeder reactors that might not be well

suited for the high temperatures

needed for thermochemical watersplitting could provide the fuel for

high-temperature reactors that

could produce hydrogen efficiently.

In order to take advantage of

the fuel resource extension obtained by high conversion ratio burner

reactors and breeder reactors,

reprocessing and recycling of

nuclear fuel will be required. Currently, the United States has a policy not to reprocess and recycle fuel

but, instead, to dispose of the leftover fuel, both fissile and fertile, as waste. This policy is contrary to

what other countries with significant nuclear energy programs

(France, Britain, Japan, China and others) are doing and is expected

to change.

Fissioning one atom of uranium or plutonium produces two fission product atoms. These are almost always radioactive, with a high

initial level of radioactivity that will, for the most part, decay to

harmless levels in about 300 years. Since the fission process produces thermal energy, the efficiency with which it is transformed

into electricity or hydrogen impacts the total amount of waste produced. For example, it is estimated that an MHR making hydrogen at

50 percent efficiency by thermochemical water-splitting will produce one-half the fission product waste as an LWR making hydrogen

8 Defense Horizons November 2003

used in today’s LWRs, the

known reserves of uranium,

could provide our current

nuclear electricity needs along

with our current hydrogen

needs by electrolysis for

almost 200 years
by electrolysis at 25 percent net efficiency. A more detailed analysis

show that in the absence of any reprocessing, an MHR producing

hydrogen by means of the S-I cycle would produce a factor of 6 less

spent fuel waste and actinides than a LWR producing the same quantity of hydrogen by electrolysis. With reprocessing and recycling, the

total quantity of waste would be reduced still further.

While LWRs could meet all current U.S. energy needs in terms

of nuclear electricity and hydrogen production for about 190 years,

and the use of advanced reactors could extend this period or expand

this use considerably, longer-term options are still needed.

The ultimate form of nuclear energy is fusion energy. If fusion

energy is eventually developed, it can be used to produce hydrogen

by either electrolysis or thermochemical processes. It is expected

that fusion will be well suited for production of hydrogen by thermochemical water-splitting. In the D–T fusion reaction, 80 percent of

the energy produced is carried by 14 MeV neutrons. These neutrons

can penetrate a cooled, low-temperature structural boundary and

deposit the energy in the hot, non-structural interior. In principle,

very high temperatures are then possible and would yield high thermochemical cycle efficiency. Fusion does have some constraints with

regard to hydrogen production. Some of the fusion neutrons must be

used to breed tritium—one atom of tritium for each fusion event—

to continue the fusion process. In addition, tritium must be kept out

of the product hydrogen. The tolerance for radioactive tritium in the

product hydrogen is very low, and removal of tritium from the hydrogen would be impractical. 

Serious design studies were performed using fusion energy for

the production of hydrogen in the early 1980s.37 Helium gas temperatures as high as 1,250  ̊C were obtained using a portion of the fusion

energy. Lower temperatures were required for the tritium production portion of the energy. Coupled to the S-I thermochemical

water-splitting cycle, these thermal energy streams allowed production of hydrogen at a net fusion energy-to-hydrogen energy efficiency approaching 50 percent, similar to that obtained with the

nuclear-matched S-I cycle described above. By use of ceramic heat

exchangers—required by the high temperatures in any case—tritium contamination of the product hydrogen was projected to be

kept to very low allowable levels. Fusion energy, therefore, does

appear to be promising as a very long-term source of hydrogen.

Hydrocarbon Fuel Synthesis 

It seems unlikely that DOD missions that require high-performance fuels can be met by pure hydrogen fuels. However, the emergence of a hydrogen economy will require the development of efficient methods for the production of large quantities of hydrogen.

The existence of this hydrogen raises the possibility of a direct

hydrogenation of gases such as CO or CO2 to produce hydrocarbon

fuels. If CO2 could be provided from the atmosphere or the ocean as

a feedstock for this process, then it might be possible to produce

high-performance hydrocarbon fuels (for example, jet fuel) in a

fashion that adds no additional CO2 to the atmosphere. If this could

be accomplished on a sufficiently large scale, it would provide a

means for DOD to participate in the hydrogen economy and still

meet its high-performance fuel requirements. 

Several processes for direct hydrogenation are well established.

One of the most successful was developed in Germany in the 1920s

by Franz Fischer and Hans Tropsch.38 In 1938, early German plants

produced 591,000 metric tons per year of oil and gasoline using the

Fischer-Tropsch process. Recent work by the University of Kentucky

has demonstrated the important role played by CO2 in this process

when an iron catalyst is employed.39

In order to scope out the required capabilities for DOD, consider the case of an aircraft carrier, which uses about 100,000 gallons

of jet fuel a day. The hydrogen contained in this fuel is about 47 tons.

Producing this much hydrogen in a 24-hour period using the nuclear

S-I process discussed above would require about a 150 MWth, 900  ̊C

reactor. This is modest by nuclear reactor standards. The hydrogen

also could be produced by electrolysis, which might be better suited

for shipboard production. In the case of electrolysis, the reactor

would need to be approximately twice the capacity. 

Nuclear production of the required hydrogen looks to be relatively straightforward. However, the carbon required for the fuel synthesis would be about 250 tons per day and would need to be

obtained such that the process would be CO2-neutral when the synthesized fuel is burned. Several options are possible for obtaining

this carbon. One would be to obtain it from biomass where the carbon comes from atmospheric CO2. This approach may involve the

burning of environmentally neutral biomass and capturing the CO

and CO2 released. Another approach might be to obtain the carbon

from the CO2 dissolved in the air or the ocean. 

November 2003 Defense Horizons 9

Table 4. Nuclear fuel resources

Years at current world nuclear Years at current world nuclear 

Conventional nuclear fuel electricity generation rate generation rate, plus current total 

Technology resources (TW-hr) (i.e., at 355 GWe, 2,540 TWe-hr) world hydrogen production rate†

Current LWR, no recycle 827,000 326 189

Gas-cooled reactor, no recycle 1,240,000 489 317

LWR with recycle 930,000 366 212

Advanced gas-cooled reactors with recycle 1,860,000 1,098 713

Fast breeders + advanced gas-cooled reactors 26,000,000 10,000 6,500

Sources: R. Price and J.R. Blaise, “Nuclear Fuel Resources: Enough to Last?” Nuclear Energy Agency Updates, NEA News 2002 no. 20.2, accessed at <http://www.nea.fr/html/pub/newsletter/2002/ 20-2-Nuclear_fuel_resources.pdf>. Also see

“Supply of Uranium” and “Supply of Thorium,” World Nuclear Association, accessed at <http://www.world–nuclear.org/info/inf75print.htm> and <http://www.world–nuclear.org/info/inf62print.htm>.

† LWR (Light Water Reactor) is assumed to use electrolysis, advanced gas reactor is assumed to use thermochemical water-splitting.
Near the ocean's surface, CO2 is distributed uniformly, with a

concentration of about 0.1 g per liter of seawater.40 Carbon constitutes 27 percent of the mass of CO2. Therefore, it would take about

8 x 109 liters of seawater to supply the carbon if the CO2 could be

removed efficiently. This volume of water corresponds to a cube 200

m on a side. To access this volume of water over a 24-hour period by

pumping would require a pump rate of 3,500 ft3/second. Pumps that

operate at these rates have been designed as a part of the Ocean

Thermal Energy Conversion (OTEC) program.41 For a pipe with a 10-

meter diameter and 100-meter length, the pumps would consume

about 1 MW of power. Further, the CO2 would have to be extracted

from the seawater at sufficient rates. This might be accomplished by

applying a modest vacuum to the water as it is pumped. OTEC noted

the presence of copious amounts of CO2 in the vacuum manifolds

during relevant seawater pumping

experiments they conducted.42 The

CO2 also could be obtained from seawater by means of chemistry, for

example, reacting seawater with calcium oxide to produce calcium carbonate, followed by roasting the calcium carbonate to produce

concentrated CO2 and regenerated

calcium oxide.

An outstanding question with

the approach described above is

whether the CO2 released by burning

the synthesized fuel would return to

the ocean rapidly enough to prevent

a CO2 buildup in the atmosphere. It may be possible in such a case to

get the CO2 from the air instead of from seawater. Seawater is 0.01

percent CO2 by weight, whereas air is 0.056 percent by weight (0.037

percent by volume) and rising. There is, of course, a trade-off. One

would need to handle one-fifth the mass of air but 140 times the volume. Recovery of CO2 from gases is very highly developed compared

with recovery from water, with a caveat that the CO2 concentrations

for many present commercial applications, such as stack scrubbing,

are much higher than for CO2 recovery from the atmosphere. 

If an approach like that described above proved viable, a one

gigawatt thermal H-2 MHR nuclear plant would be able to supply the

aviation fuel for all U.S. aircraft carriers in the context of a hydrogen

economy, in an environmentally acceptable fashion, and with total

independence from imported oil. Of course, this approach will

require a significant R&D program to resolve some key issues. Among

these are complete testing of the S-I process, demonstration of the

H-2 MHR, efficient extraction of CO2 from seawater or air, and identification and development of an efficient fuel synthesis process. 

Conclusion 

While there is no near-term fuel crisis facing DOD, this situation is likely to change over the coming decades as fossil fuel

reserves deplete and world demand for them grows. DOD will be confronted with some significant challenges, ranging from protecting

U.S. interests as supply and demand come into increasing conflict, to

resolving defense-unique fuel requirements as the Nation moves to

alternate fuels. The current trend toward a hydrogen economy presents DOD with some special challenges, because a pure hydrogen

fuel likely will not satisfy many DOD requirements. The resolution of

this problem will take decades. DOD should engage on this issue in

the near term in order to influence and leverage the national hydrogen initiative and to have in place an infrastructure to assure that

DOD energy needs are met, in particular those related to fuel

requirements for low-altitude, high-performance aircraft missions. 

The wider DOD requirement for compact, high-volumetric

energy density power sources will likely increase DOD dependence

on nuclear power and require the development of technology for the

CO2-neutral synthesis of high-performance hydrocarbon fuels. DOD

should consider establishing an R&D program to assess and resolve

defense-unique issues connected

with hydrogen generation, carbonbased fuel synthesis, and the development of a CO2-neutral feedstock.

For the limited and unique needs of

DOD, serious consideration should

be given to the use of nuclear power

to drive the electrolytic or thermochemical generation of hydrogen.

The extraction of CO2 from the

atmosphere or from the upper ocean

should be examined as a possible

CO2-neutral means of supplying the

necessary feedstock of carbon for

synthesis of fuel for high-performance jet aircraft. Studies of various fuel synthesis methods capable

of meeting the unique DOD needs should be undertaken. The elementary analysis presented here suggests that a system based upon

pressurized water reactors might be compatible with aircraft carrierbased synthesis of jet fuel or that a single shore-based system using

high-temperature nuclear reactors might be capable of producing

the jet fuel for all U.S. carriers. If this turns out to be correct, then

the extension to meet all DOD-unique, high-performance fuel

requirements would be in sight and would be compatible with and

contribute to the larger hydrogen economy initiative.

10 Defense Horizons November 2003

DOD should consider

establishing an R&D program

to assess and resolve defenseunique issues connected 

with hydrogen generation,

carbon-based fuel synthesis,

and the development of a CO2-

neutral feedstock

The authors gratefully acknowledge helpful discussions

with David Baldwin, Walter Simon, Arkel Shenoy,

Carmello Rodriguez, E. Michael Campbell, Bhakta B.

Rath and Sergei Krashenninikov. Drs. Coffey and Hardy

performed this work under the auspices of Office of

Naval Research funding, and Drs. Besenbruch, Schultz,

Brown, and Dahlburg acknowledge the support of

General Atomics.
Notes1 Andrew Haaland, “High Pressure Conformable Hydrogen Storage for Fuel Cell

Vehicles,” Proceedings of the 2000 Hydrogen Program Review, NREL/CP–570–28890. 2 R. Byron Bird, Warren E. Stewart, and Edwin N. Lightfoot, Transport 

Phenomena (New York: John Wiley & Sons, 1960), 180–190. 3 Hydrogen Distribution Infrastructure, accessed at <http://www.jlab.org/

hydrogen/talks/Mintz.pdf>. 4 “Oil Supplies—Are We Really Running Out?” accessed at <http://www.api.org/

oilsup.htm>. 5 National Assessment Synthesis Teams, U.S. Global Change Research Program,

“Climate Change Impacts on the United States,” accessed at <http://www.gcrio.org/

NationalAssessment/aIntro.pdf>. 6 “Liquid Hydrogen as a Propulsion Fuel, 1945–1959,” accessed at <www.hq.

nasa.gov/office/pao/History/SP-4404/Content.htm>. 7 H.W. Carhart, W. A. Affens, B. D. Boss, R. N. Hazlett, and S. Schuldiner, “Hydrogen as a Navy Fuel,” NRL Report 7754, June 12, 1974. 8 “The Cryoplane Project,” Air International, November 1997; “ NASA Launches

Hydrogen Airplanes Study,” Hydrogen and Fuel Cell Letter, September 2000, accessed

at <http://www.hfcletter.com/letter/september00/feature.html>. 9 “The Unitized Regenerative Fuel Cell,” accessed at <http://www.llnl.gov/str/

Mitlit.html>. 10 J. Davis, “If We Run Out of Batteries, This War is Screwed,” Wired Magazine,

accessed at <http://www.wired.com/wired/archive/11.06/battlefield_pr.html>. 11 Glenn D. Rambach, “Hydrogen Transport and Storage in Engineered Glass

Microspheres,” 6th Annual National Hydrogen Association Meeting, Alexandria, VA,

March 7–9, 1995. Preprint: Lawrence Livermore National Laboratory report

UCRL–JC–120054, February 28, 1995. 12 Taro Takahashi, “Carbon Dioxide in the Atmosphere and in Atlantic Ocean

Water,” Journal of Geophysical Research 66 (1961), 477–494. 13 Franz Fischer and Hans Tropsch, “The Preparation of Synthetic Oil Mixtures

(Synthol) from Carbon Monoxide and Hydrogen,” Brennstoff Chem. 4 (1923), 276–285. 14 Table E2, “World Petroleum Consumption (BTU), 1992–2001,” accessed at

<http://www.eia.doe.gov/emeu/iea/tablee2.html>. 15 Stuart Energy website, “Electrolysis 101,” accessed at <http://www.

stuartenergy.com/main_tech.html>. 16 See <http://www.seasolarpower.com/otec.html>.

17 J. R. Bolton, “Solar Photoproduction of Hydrogen,” International Energy

Agency Report IEA/H2/ TRR–96, September 1996. 18 Ibid.

19 David Pimentel, Megan Herz, Michele Glickstein, Matthew Zimmerman,

Richard Allen, Katrina Becker, Jeff Evans, Benita Hussain, Ryan Sarsfeld, Anat 

Grosfeld, and Thomas Seidel, “Renewable Energy: Current and Potential Issues,”

BioScience 52, no. 12 (2002), 1111–1120. 20 Anastasios Melis, Liping Zhang, Maria Ghirardi, and Michael Seibert, “Sustained Photobiological Hydrogen Gas Production upon Reversible Inactivation of 

Oxygen Evolution in the Green Alga Chlamydomonas reinhardtii,” Plant Physiology

(January 2000), 122, 127–135. 21 R.H. Williams, “Toward Zero Emissions for Transportation Using Fossil Fuels,”

presented at the VIII Biennial Asilomar Conference on Transportation, Energy, and

Environmental Policy, November 14, 2001. 22 G. E. Besenbruch “General Atomic sulfur-iodine thermochemical water-splitting process,” American Chemical Society, Division of Petroleum Chemistry, 271

(1982) 48–53. Also J. H. Norman, G. E. Besenbruch, L. C. Brown, D. R. O’Keefe, and C.

L. Allen, “Thermochemical Water-Splitting Cycle, Bench-Scale Investigations and

Process Engineering: Final Report for the Period February 1977 through December 31,

1981,” Report Nos. DOE/ET/26225–1 and GA–A16713, May 1982. 23 S. Herring et al., “Development of a High Temperature Solid Oxide Electrolyser System,” Hydrogen, Fuel Cells, and Infrastructure Technologies Program 2003

Review, May 19–22, 2003, Berkeley, CA; accessed at <http://www.eere.energy.gov/

hydrogenandfuelcells/2003_merit_review.html>. 24 L. Basye and S. Swaminathan, “Hydrogen Production Costs—A Survey,” prepared by SYNTECH, Inc. December 4, 1997, under DOE/GO/10170–T18. 25 Based upon data presented in J.H. Gary & G.E. Handwerk, “Petroleum Refining, Technology and Economics,” Marcel Dekker, January 2001; J. P. Riva, “World Oil

Production After Year 2000,” Congressional Research Service Report for Congress 

95–925 SPE, August 1995.

26 Herring et al. 

27 Besenbruch .

28 H. Nakajima et al., “A study on a closed-cycle hydrogen production by thermochemical water-splitting IS process,” Proceeding of the Seventh International Conference on Nuclear Engineering (ICONE–7), Tokyo, April 1999, ICONE–7104. 29 L. C. Brown, J. F. Funk, and S. K. Showalter, “High Efficiency Generation of

Hydrogen Fuels using Nuclear Power,” annual report to Department of Energy, General Atomics report GA–A23451, July 2000. Also see L. C. Brown et al., “High Efficiency

Generation Of Hydrogen Fuels Using Thermochemical Cycles And Nuclear Power,”

American Institute of Chemical Engineers 2002 spring meeting, March 11–15, 2002. 30 A. C. Marshall, “An Assessment of Reactor Types for Thermochemical Hydrogen Production,” report to Department of Energy, Sandia National Laboratories report

SAND2002–0513, February 2002. Also see L. C. Brown, J. F. Funk, and A. C. Marshall,

“High Efficiency Generation of Hydrogen Fuels using Nuclear Power,” annual report to

Department of Energy, General Atomics report GA–A24187, November 2002. 31 L. C. Brown et al., “Alternative flowsheets for the sulfur-iodine thermochemical hydrogen cycle,” American Institute of Chemical Engineers 2003 spring meeting,

March 31–April 4, 2003, and L. C. Brown, J. F. Funk, and A. C. Marshall, “High Efficiency Generation of Hydrogen Fuels using Nuclear Power,” final report to Department of Energy, General Atomics report GA–A24285, June 2003. 32 P. Pierrard et al., “An International Laboratory-Scale Demonstration of the

Sulfur-Iodine Thermochemical Water-Splitting Cycle,” American Institute of Chemical Engineers 2003 spring meeting, March 31–April 4, 2003. 33 “High-Temperature Gas-Cooled Reactors for the Production of Hydrogen: An

Assessment Support of the Hydrogen Economy,” Electric Power Research Institute

(EPRI), Palo Alto, CA, report 1007802, April 2003. 34 M.P. LaBar, “The Gas-Turbine-Modular Helium Reactor: A Promising Option

for Near-Term Deployment,” International Congress on Advanced Nuclear Power

Plants, June 2002, Hollywood, Florida. 35 “High-Temperature Gas-Cooled Reactors for the Production of Hydrogen.” 36 R. Price and J.R.Blaise, “Nuclear Fuel Resources: Enough to Last?” Nuclear

Energy Agency Updates, NEA News 2002, no. 20.2; accessed at <http://www.nea.fr/

html/pub/newsletter/2002/ 20-2-Nuclear_fuel_resources.pdf>. Also see “Supply of

Uranium” (August 2002) and “Supply of Thorium” (July 2001), World Nuclear Association: <http://www.world–nuclear.org/info/inf75print.htm> and <http://www.world–

nuclear.org/info/inf62print.htm>. 37 K. R. Schultz, “Production of Hydrogen by Fusion Energy: A Review and Perspective,” 15th Topical Meeting on the Technology of Fusion Energy, November 18–21,

2002, Washington DC. 38 Fischer and Tropsch.

39 Burt Davis, “Fischer-Tropsch Synthesis, the CAER Perspective,” Energeia 8

(1997), 1–2; accessed at <http://www.caer.uky.edu/energeia/PDF/vol8-3.pdf>. 40 Takahashi, 477–494; Taro Takahashi, “Ocean: a dynamic reservoir for carbon

dioxide,” Proceeding of the 2d North American Conference on Preparing for Climate

Change, Climate Institutes, December 6, 1988, 136–141; Taro Takahashi, W.S.

Broecker, and A.E. Bainbridge, “The alkalinity and total carbon dioxide concentration

in the world oceans,” in Carbon Cycle Modeling, ed. B.Bolin (New York: SCOPE 16,

Wiley & Sons, 193), 271–276. 41 See <http://www.seasolarpower.com/otec.html>.

42 William H. Avery and Chih Wu, Renewable Energy from the Ocean: A Guide to

OTEC (New York: Oxford University Press, 1994), 436–438.

November 2003 Defense Horizons 11

Defense Horizons is published by the Center for Technology and National Security Policy through the

Publication Directorate of the Institute for National Strategic Studies, National Defense University.

Defense Horizons and other National Defense University publications are available online at

http://www.ndu.edu/inss/press/nduphp.html.

The opinions, conclusions, and recommendations expressed or implied within are those of the

contributors and do not necessarily reflect the views of the Department of Defense or any other

department or agency of the Federal Government.

Center for Technology and National Security Policy

Hans Binnendijk

Director
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