A Primer on Alternative 

Transportation Fuels 

Timothy Coffey 

Center for Technology and National Security Policy 

National Defense University 

September 2010 
ii

The views expressed in this article are those of the authors and do not reflect the official 

policy or position of the National Defense University, the Department of Defense, or the 

U.S. Government. All information and sources for this paper were drawn from 

unclassified materials. 

Timothy Coffey served as the Director of Research of the U. S. Naval Research 

Laboratory from 1982 to 2001. From 2001 until 2007 he held a joint appointment as 

Senior Research Scientist at the University of Maryland and as the Edison Chair for 

Technology at the National Defense University. He retired in 2001 and presently is under 

contract to the National Defense University as a Distinguished Research Fellow.
iii

Contents 

Executive Summary............................................................................................................ v 

1. Introduction..................................................................................................................... 1 

2. Mission Requirements that Drive System Considerations.............................................. 4 

3. Review of Engine Technologies ..................................................................................... 9 

4. Selecting the Power Plant ............................................................................................. 15 

5. The Role of Hydrogen .................................................................................................. 24 

6. Liquid Transportation Fuels from Reforming and Gasification ................................... 30 

Liquid fuels via steam reforming of methane........................................................... 32 

Liquid fuels from coal............................................................................................... 34 

Liquid Fuel via Biomass Gasification....................................................................... 39 

7. Enzymatic Approach to Producing Fuels from Biomass.............................................. 42 

8. Fuels from Biomass Oils............................................................................................... 46 

9. Synthetic Fuel from Atmospheric Carbon Dioxide ...................................................... 49 

10. Exploitation of Oil Shale ............................................................................................ 51 

11. Conclusion .................................................................................................................. 54 

Appendix A....................................................................................................................... 59 

Appendix B ....................................................................................................................... 66 

References......................................................................................................................... 70 
iv
v

Executive Summary 

A review is undertaken of several approaches to producing alternative transportation 

fuels using feedstocks that are under the control of the United States. The objective of the 

review is to provide the non-specialist reader with a general understanding of the several 

approaches, how they compare regarding process energy efficiency, their individual 

abilities to provide for national transportation fuel needs, and their associated capital 

costs. It is noted that, in principle, vehicle missions determine fuel and propulsion plant 

requirements rather than the other way around. In reality, of course, there is a tradeoff 

among desired mission capabilities and fuel and propulsion plant technologies. 

The review results suggest these conclusions about alternative transportation fuels: 

• If necessary, the United States can manufacture the transportation fuels it needs. 

• The capital investments needed to manufacture fuels beyond petroleum will be 

substantial, regardless of the particular alternative fuel selected. In this regard, 

the steam reformation of methane (SMR) processes, because of their higher 

efficiencies and substantially lower capital costs, would seem to warrant special 

attention. The associated fuels are not carbon free or carbon neutral. 

• The capital investments associated with the manufacture of renewable—carbon 

free or carbon neutral—fuels will be especially large. 

• Serious commercial investment in alternative fuels, in contrast to standard 

petroleum-based fuels, will be difficult to obtain as long as low-cost petroleum 

is available. 

True comparative evaluation of transportation fuel inextricably requires consideration 

of the vehicle and mission that the fuel is intended to power. A mission can place 

significant volume and weight constraints on its combined (power plant plus fuel) system 

for transportation. Consequently, power density, energy density, and propulsion plant 

energy efficiency become essential metrics for comparing various alternative 

transportation fuels. This review commences with a brief discussion regarding the 

relationship between mission requirements and vehicle kinematics and how these 

determine the requirements for fuel and propulsion plants. This is followed by a review 

of the characteristics (e.g., torque, horsepower, weight, volume, and fuel consumption) of 

several of the most popular engines, where it is shown that the various engines generally 

are best suited to different missions. We then focus our attention on fuel approaches 

where the required feedstocks are within the direct control of the United States. The 

specific topics discussed are: batteries and fuel cells, hydrogen, coal to liquid, natural gas 

and gas hydrate-derived fuels, bio-derived fuels, CO2-derived fuels, and oil shale. 

For batteries and fuel cells, this report starts from a broad discussion of considerations 

related to the selection of the entire propulsion plant, including fuels and engines. The 

Ragone chart of specific energy vs. specific power is introduced as a comparative means 

of placing the various propulsion plants into perspective. The vehicle mission places 
vi

simultaneous demands on specific power and specific energy. The power plant must be 

able to meet these independent requirements. Hence, the mission requirements when 

placed on the Ragone chart must lie within the performance characteristics of the selected 

technology. Each of the technologies considered occupies a particular area on the chart. 

The chart shows that, for all the available propulsion plants considered, the specific 

energy of the plant decreases as the specific power of the plant increases. The internal 

combustion power plants considered had the most robust capability to support both high 

specific power and high specific energy. The electric power sources considered in the 

chart include batteries and fuel cells. Importantly, the batteries and fuel cells were shown 

to have limited specific energy at the required specific power. As a result, there has been 

a very limited overlap between battery and fuel cell power and energy characteristics and 

transportation vehicle mission requirements. 

The problem with currently available or near-term battery and fuel cell technologies is 

that either the available energy or the available power is inadequate for the vehicle 

mission. In some cases, where the mission requires high power for only a small fraction 

of a vehicle’s mission, the introduction of an auxiliary pulse power system becomes 

viable. In this case the pulse power system can be “charged” at a low power that is 

compatible with the mission average power requirements. For a small fraction of the 

mission the pulse power system will deliver the necessary high power but low total 

energy. It is possible that battery and fuel cell technology combined with electric motors 

may progress to the point where this approach is viable for passenger vehicles where high 

power is typically required for less than ten percent of a vehicle mission. This could be an 

important development, because passenger vehicles account for about half of U.S. oil 

consumption. However, for high-energy, high-power missions, the chart shows that 

batteries and fuel cell are disadvantaged relative to the internal combustion engines 

considered. It seems unlikely that the disadvantage can be overcome for highperformance DOD, commercial, and industrial missions involving transportation fuels. 

As a result, internal combustion propulsion plants will likely remain the plants of choice 

for these missions for the foreseeable future, and with a concomitant essential need for 

“petroleum grade” fuel. 

Regarding transportation fuels themselves, a central objective is to provide some sense 

of the scale of the various undertakings, such as the capital investments that would need 

to be made to bring the various approaches to the point of providing transportation fuel 

independence and the impact that would result on the various feedstocks. Hence, the 

alternative fuel approaches considered include: hydrogen production, creation of 

synthesis gases from various feedstocks followed by a fuel synthesis process, enzymatic 

production of ethanol, the use of biomass oils for biodiesel production, fuel synthesis 

using atmospheric carbon dioxide as a feedstock, and the exploitation of oil shale. 

In order to undertake a stressful assessment of an alternative fuel’s viability as a 

solution to the transportation fuels problem, each alternative fuel was evaluated according 

to its ability to provide a fuel product with the energy equivalent of the 13.4x106 barrels 

per day (BPD) of petroleum currently used by the U.S. transportation system. In that 

regard, it was noted that, for the typical passenger vehicle, only about 18% of the fuel 

energy it consumes is actually used for the propulsion of the vehicle, with most of the 

remainder lost primarily as waste heat. Since passenger vehicles account for about two-
vii

thirds of the transportation fuel consumed, the energy that is actually required by vehicle 

kinematics is much less than the number mentioned above. A significant improvement in 

propulsion plant energy efficiency would reduce significantly the amount of 

transportation fuel needed thereby reducing—in a larger sense—the need for alternative 

fuel. 

A comparison of the findings for the various alternative fuel processes approaches 

considered is presented succinctly in table ES1 (next page). This table provides estimates 

of the process efficiencies and rough order of magnitude (ROM) estimates of capital 

costs associated with production of hydrogen and the liquid fuels considered, at a scale 

needed to produce 13.4x106 barrels per day (BPD) of oil equivalent product. The process 

energy efficiency was defined as the calorific energy content of the fuel product produced 

by the process divided by the sum of the calorific energy content of the feedstock 

consumed, plus any additional energy required to enable the process. The table is ordered 

by increasing capital costs, except for oil shale, which is qualitatively different from the 

other entries. 

As can be seen from table ES1, there are potentially many processes by which 

alternative fuels can be produced with the energy content required by the U.S. 

transportation system. There is a large spread in the energy efficiencies of the processes, 

ranging from 70% for SMR production of hydrogen to 18% for gasoline production from 

atmospheric carbon dioxide (CO2). Similarly, there is a large spread in the estimated 

capital costs associated with the various processes, ranging from a low of about 173 

billion dollars for hydrogen production using SMR to a high of about 4 trillion dollars for 

gasoline production from atmospheric CO2. It is clear from the table that increasing 

capital costs tend to correlate with decreasing energy efficiencies. This is not an 

unexpected result. 

Several of the processes shown in table ES1 can be eliminated for reasons of 

impracticality towards meeting the scalability goal. Corn-based ethanol and biodiesel 

have been included simply to show where they fall in the hierarchies of efficiency and 

cost. In reality, while both fuels may have important niche roles to play, neither of them 

is a serious candidate for solving the national transportation fuels problem. The necessary 

feedstocks are simply not available. It is also recommended that hydrogen be set aside 

from consideration, even though it has the lowest capital costs when produced by SMR 

techniques. It could be used as a fuel if it were absolutely necessary and could be 

produced in adequate quantity to meet national transportation fuel needs. If produced by 

nuclear or solar-powered thermochemical means or by electrolysis it would produce no 

greenhouse gas CO2. However, the logistical problems associated with the cryogenic 

systems or high-pressure systems required to employ hydrogen as a general-purpose 

transportation fuel make its use as a general-purpose transportation fuel or as a fuel for 

most DOD vehicles problematic. 
viii

Process Process energy 

efficiency 

ROM capital cost 

(billions of dollars) 

Comment 

Steam reforming of 

methane (SMR) to 

hydrogen 

70% 170 Commercial process,* 

doubles NG 

consumption 

Biodiesel 35% 200 Commercial process*** 

SMR to methanol 60% 250 Commercial process* 

SMR to gasoline via 

methanol 

54% 300 Commercial process* 

Corn ethanol 46% 400 Commercial process*** 

Hydrogen by 

biomass gasification 

46% 500 Commercial process** 

Hydrogen by coal 

gasification 

44% 500 Commercial process,* 

doubles coal 

consumption 

Coal to liquid 44% 900 Commercial process,* 

quadruples coal 

consumption 

Biomass to liquid 47% 900 commercial processes** 

Hydrogen by 

thermochemical 

50% 1,000 Process under 

development* 

Lignocellulose 

ethanol 

41% 1,500 Process under 

development** 

Hydrogen by 

conventional 

electrolysis 

25% 2,000 Commercial 

electrolyzer, 3’rd gen 

nuclear reactor* 

Atmospheric CO2 to 

gasoline 

18% 4,000 Commercial processes + 

3’rd gen nuclear 

reactor* 

Oil shale surface 

retort approach 

? 1,000 Involves massive mining 

and disposal 

Shell oil shale in situ

retort approach 

Less than 50% Greater than 500 electric power plant 

only* 

Table ES1. Summary estimates of the process efficiencies and ROM capital costs associated with 

production of hydrogen and several liquid fuels at a scale to produce 13.4x106 BPD Oil 

equivalent product. 

Key: *not renewable but can, in principle, meet the BPD goal, **renewable but available 

feedstock cannot sustainably meet BPD goal, ***renewable but available feedstock cannot meet 

BPD goal.) 
ix

Among the remaining alternative fuel processes identified here, the SMR processes are 

found to be the most energy efficient and have the lowest capital costs. They can also 

produce a variety of different fuels including hydrogen, alcohols, and hydrocarbons. A 

negative aspect is that their use would double the consumption of natural gas and add 

substantially to CO2 production. With regard to the increased consumption of natural gas, 

the recent advances in gas production using hydraulic fracture of shale and the vast 

reserves of gas hydrates that are believed to exist may play a role. The advances in 

hydraulic fracture of shale are estimated to increase the U.S. potentially available natural 

gas resources by one-third, resulting in about 100 years of natural gas supply at current 

usage rates. If gas hydrates could be safely and economically obtained, they would 

potentially provide a large supply of methane thereby allowing the manufacture of 

transportation fuels for generations. Unfortunately, at this time the viability of gas 

hydrates as a serious source of methane is unknown and it will likely be decades before 

their viability is quantified. Regarding the production of CO2, if it is deemed 

inappropriate to release it into the atmosphere, then the fact that it would be produced at 

large central sites would simplify its capture. Upon capture it could be processed into 

additional fuels by methods similar to those to be described for fuel production from 

atmospheric CO2. This would be an expensive undertaking as can be seen from table 

ES1. However, it would minimize CO2 production during fuels manufacture and also 

reduce the amount of methane needed. Ultimately, of course, the CO2 would be released 

into the atmosphere upon fuel combustion or reforming. As an alternative, the captured 

CO2 could also be sequestered if such schemes are allowed. Whether large-scale 

sequestration of CO2 will be viable is currently a matter of study. It is clear that, while 

SMR processes could supply the needed transportation fuels for an extended period, a 

number of issues must be resolved before the SMR approach to alternative fuel 

production can be properly assessed for implementation. 

The next process that shows up as being most process energy efficient and least capital 

intensive is the conversion of coal to liquid fuels (CTL). This process is considerably 

more costly than the SMR processes. Nevertheless, it too can produce a variety of fuels, 

including hydrogen, alcohols and hydrocarbons. Its use would nearly quadruple the 

consumption of coal and reduce the lifetime of the U.S. coal supply from the current 

value of 280 years to about 80 years (assuming that transportation fuel use did not 

increase from its current value). The use of CTL would double CO2 production. As with 

the SMR processes, at considerable expense that portion of the CO2 that results from the 

CTL process could be captured at the central production sites and converted to additional 

transportation fuel, thereby reducing the amount of coal that must be mined. Of course, 

this approach would increase the demands on the supply of uranium in the likely event 

that nuclear energy would provide the power needed to convert the captured CO2 into a 

transportation fuel. If permitted, here also the captured CO2could be sequestered. In this 

regard, one should keep in mind that after about 80 years one would have sequestered 

about half the carbon in the U.S. coal supply in the form of gaseous CO2. As with the 

SMR processes, the CTL process could supply the needed transportation fuels for an 

extended period. However, a number of issues must be resolved before the CTL approach 

to alternative fuel production can be properly assessed. 

The biomass to liquid fuels (BTL) process comes in at about the same process energy 

efficiency and capital cost as does the CTL process. The BTL process is generally 
x

described as renewable, because the source can be regrown. However, if it is to be 

sustainable, then the biomass harvest must be limited by the rate of regrowth of the 

biomass. Furthermore, there are other uses for the biomass that further limit the amount 

of biomass that can be used for alternative fuel production. It has been estimated that 

about 1.4 billion tons per year of biomass can be made available, in a sustainable fashion, 

for the production of alternative fuels. If this biomass were converted into fuel in the BTL 

process, it could provide for about 35% of the current transportation fuel needs. Thus, a 

full solution of the transportation fuels problem via the BTL approach does not seem to 

be viable. Of course, a 35% solution would be a significant contribution. The capital cost 

associated with the 35% solution would be about 300 billion dollars rather than the 900 

billion dollars indicated in table ES1 for a full solution. In this regard, it should be 

recalled that the SMR processes indicate that a full solution may be available for a capital 

investment of about 300 billion dollars. In support of the BTL process it is often 

suggested the BTL approach is CO2 neutral, because the carbon in biomass comes from 

the atmosphere and is returned to the atmosphere upon the combustion of the BTL fuel. 

This statement is true to the extent that the energy to make the biomass comes from the 

sun. However, to the extent that fossil fuel is required to grow/harvest the biomass, the 

statement is not true. As with the other processes, a number of issues must be resolved 

before the BTL contribution to alternative fuel production can be properly assessed. 

The next process to appear in the efficiency and capital cost sorting is lignocellulosic 

ethanol production. This process attempts to break down the cellulose and hemicellulose 

in biomass into fermentable sugars. This process is still under development and is much 

more difficult than the well-developed corn ethanol process. However, if successful, it 

has the advantage that it can access a much larger feedstock than can the corn ethanol 

process. In order to function in a sustainable fashion, it would target the same 1.4 billion 

tons of biomass as does the BTL process. This amount of biomass used as feedstock for 

the lignocellulosic ethanol process would yield about 30% of the ethanol required for a 

full solution. The capital investment required is estimated to be about 500 billion dollars. 

The situation regarding carbon neutrality is the same as for the BTL approach; the 

process has yet to be demonstrated at a scale where its contribution to alternative fuels 

can be properly assessed. 

The fuel synthesis schemes with the lowest energy efficiency and the highest capital 

cost involve the use of atmospheric CO2 as a feedstock. The process involves absorbing 

CO2 from the atmosphere and recovering it for reaction with hydrogen in order to make 

methanol. The process could stop with methanol, or the methanol could be further 

processed to make a higher energy density fuel such as gasoline. The recovery of CO2

and the production of the necessary hydrogen are energy intensive and would likely 

involve the use of nuclear reactors. The various steps of the process have been tested and 

involve well-understood technologies. In principle, the process should be capable of 

producing the quantities of fuel needed to solve the transportation fuel problem. For the 

case considered herein, this would require about 1600 nuclear reactors each providing a 

thermal power of about three gigawatts. The total capital cost for the production plants is 

estimated to be about four trillion dollars. Since the feedstocks for this process are 

atmospheric CO2 and water, and the supplemental power is from nuclear energy, the 

process is CO2 neutral. However, the uranium consumption resulting from the large 

number of nuclear reactors would be substantial and would likely deplete the reserves of 
xi

low-cost uranium ore in a few decades. The long-term viability of such a process would 

likely involve the introduction of advanced reactors, and ultimately of breeder reactors. 

Similar approaches could be applied to converting smokestack CO2 to fuel where the 

higher CO2 density would make the collection of CO2 easier. However, because the 

capital costs for fuel production are dominated by the recovery of the absorbed CO2 and 

the production of the required hydrogen, for the same amount of fuel the plant capital 

costs would be similar to that given above for fuel production from atmospheric CO2. 

There are clearly many issues that need to be resolved regarding this approach to 

alternative transportation fuels. 

The final topic considered was that of transportation fuel from oil shale. Oil shale 

processing is qualitatively different from the schemes discussed above. The organic 

carbon that would form the basis of fuels is obtained by heating the shale to about 700 oF 

and driving a liquid crude oil from the shale. This heating is performed in a vessel called 

a retort and the process is called retorting. The crude oil obtained is collected and sent to 

a refinery where it is turned into usable fuels much as is done with conventional 

petroleum. Retorting is done on the surface or in situ. It is estimated that U.S. oil shale 

formations could supply current U.S. transportation fuel needs for more than 140 years. 

However, the process for obtaining oil shale crude is very energy intensive. There are no 

recent studies that provide current data regarding the expected capital costs associated 

with producing shale oil crude. Studies done in the 1980s, when scaled to 2005 dollars, 

suggest that the capital costs associated with producing 13.4x106 BPD of oil shale crude 

by surface retorting would be about one trillion dollars. Regarding the capital costs 

associated with the in situ approach, in recent years, Shell Oil has been studying an in situ

retorting approach in which the heat needed to drive out the oil shale crude is provided by 

electric heaters placed within the shale deposits. This approach would avoid having to 

mine the shale. It can be shown that the electrical power system needed to provide the 

heat necessary to produce 13.4x106 BPD of oil shale crude would itself have a capital 

cost in excess of 500 billion dollars. There are many environmental concerns (e.g., 

ground water contamination) associated with producing oil shale crude. 

Finally, it is important to note that, on the basis of national security needs, the DOD 

could argue to use appropriated funds to pay for the development of an alternative fuel to 

supply its two percent of national transportation fuel usage. There are several 

methodologies that could supply DOD transportation fuel needs. However, such an 

undertaking should be approached with great caution. If DOD were to select a scheme 

that is not viable for the larger transportation system then DOD will be left with a costly 

proprietary system, will be unable to benefit from competitive forces in the larger 

marketplace, and could find itself short of fuel in a time of national emergency. It is 

certainly not clear at this time which is the best alternative fuel approach for DOD and for 

the nation. It will likely take decades to sort this out. DOD should be a participant in a 

national effort to clarify the choices from a perspective of mission requirements—to 

ensure that these requirements will be met—since it could be impacted substantially by 

the outcome. 

1

1. Introduction 

The Energy Information Agency (EIA) estimates that the United States presently 

imports 58% of its oil (petroleum) and that this will grow to about 68% by 2030.1This 

fact, combined with the recent escalation in world oil prices, has led to renewed interest 

in alternative fuels that might reduce or eliminate the growing dependence on foreign oil 

sources. Of particular concern are the applications that power the U.S. transportation 

system. Table 1 summarizes U.S. oil usage for 2007. 

Fuel Use Amount 

(million barrels per day) 

Motor Gasoline 9.29 

Jet Fuel 1.62 

Distillate (highway) 2.36 

Distillate (ships) .147 

Distillate (Other) 1.69 

Residual Fuel .72 

Other 4.82 

Total 20.65 

Table 1. U.S. oil usage for 2007 (Source: Annual Energy Outlook 2009 table 20, Energy 

Information Agency “Sales of distillate fuel oil by category 2009.” 

It can be seen from table 1 that about 65% (13.4 million barrels per day) of U.S. oil 

consumption relates to transportation fuels. This number is somewhat misleading in that 

the energy conversion efficiency of the typical transportation plant is about 18% (see 

figure A1 of appendix A). Thus, the energy that is actually needed for transportation 

propulsion is equivalent to about 2.4 million barrels of oil per day (BPD). The remaining 

11 million BPD emerges mostly as waste heat due to the underlying efficiency of the 

energy conversion process. In this paper we will use 13.4 million BPD as the goal that 

alternative fuels must meet. However, it should be kept in mind that a radical 

improvement in the energy efficiency of propulsion power plants would markedly change 

the transportation fuels requirement. 

The Department of Defense (DOD) is especially dependent on petroleum. Figure 1 

summarizes the DOD energy usage for 2005. 
2

0

100

200

300

400

500

600

700

800

Petroleum Electricity Natural Gas Coal Purchased

Steam and

Others

US Department of Defense Energy Consumption, Fiscal Year 2005

Trillion BTU

Figure 1. DOD energy usage during 2005 (Source DESC Fact Book FY 08). 

It is clear from figure 1 that petroleum is the dominant energy source for DOD. The 

DOD use of petroleum is primarily associated with transportation fuels. Since a barrel of 

oil has an energy content of about 5.8 million BTU, it follows from table 1 and figure 1 

that DOD is responsible for about 2% of U.S. petroleum consumption. This percentage is 

sufficiently small that DOD can reasonably expect to have access to the petroleum 

resources needed to meet its mission in a national emergency. However, DOD cannot be 

complacent regarding oil supplies. DOD must purchase the oil it uses and is therefore 

directly impacted by oil prices. More importantly, the missions that DOD will be tasked 

to undertake are likely to be impacted profoundly by international developments in the 

area of energy supplies. Furthermore, DOD has a big stake in the outcome of any attempt 

to move the nation to an alternative fuel. For example, some of the alternative fuels under 

consideration would be ill suited for DOD use, as will be discussed in sections 5 through 

10. There are other solutions that could meet DOD needs but would not scale to the larger 

national transportation fuel needs. If DOD selected one of these solutions it would put 

itself in the position of having to maintain a DOD-unique fuels infrastructure that would 

not benefit from the potential efficiencies of the larger national fuels infrastructure. 

Therefore, the large and growing dependence on imported oil and the growing national 

interest in alternative fuels are matters of both economic and military concern. This has 

led to increased interest within DOD and other agencies regarding whether and which 
3

alternative fuels could be produced from U.S. feedstocks on a scale that could lead to 

energy independence for the United States. 

From a policy and planning perspective, one of the difficulties with alternative fuels 

relates to the great variety of possibilities that are potentially available. Each of these 

possibilities has its own community and literature (some of which goes back 100 years or 

more). While there is a great deal known about most of the alternative fuels, it is difficult 

to find discussions that attempt to place various possibilities within the context of the 

national transportation fuel problem and with respect to each other. This report will 

attempt to make some progress in this regard. The objective here is to provide some sense 

of the scale of the various undertakings, such as the capital investments that would need 

to be made to bring the various approaches to the point of providing transportation fuel 

independence and the impact that would result on the various feedstocks. The paper is 

intended for the non-specialist for whom a broad understanding of alternative fuels would 

be helpful. In general, the paper will not delve into special technical issues, such as the 

best catalyst to employ in a particular situation. We will assume such matters can be 

resolved, and that it is technically feasible to produce the fuel. This report will provide 

rough order of magnitude (ROM) estimates of some of the consequences of moving 

beyond technical feasibility to a national solution that provides transportation fuel 

independence. A detailed discussion of the underlying chemistry and physics can be 

found in Probstein and Hicks.2

Transportation fuels are especially challenging, because they are typically carried by 

the vehicle that they power. This places significant volume and weight restrictions on the 

fuels and power plants that can be considered for transportation purposes. As a result, 

power density, energy density, and propulsion plant energy efficiency become essential 

metrics for comparing various alternative transportation fuels. We will focus our attention 

on approaches where the required feedstocks are within the direct control of the United 

States. The specific alternative fuel applications that we will discuss are: batteries and 

fuel cells, hydrogen, coal to liquid, natural gas and gas hydrate-derived fuels, bio-derived 

fuels, CO2-derived fuels, and oil shale. The place to begin such a discussion, however, is 

not with the fuels but with the mission requirements to which the fuels must respond. 

Section 2 will provide a brief discussion of some of the ways in which mission 

requirements influence fuel and power plant considerations. Section 3 is an overview of 

the characteristics (e.g., torque, horsepower, weight, volume, and fuel consumption) of 

several mission-essential engines. Comparative assessment of how the various engines 

generally are best suited to different missions, in section 4, includes discussion of the 

electric motor engine and the status of batteries and fuel cells in that context. We then 

focus our attention on the alternative fuel approaches, in sections 5 through 10. In section 

11, the review findings are summarized and conclusions are offered. 
4

2. Mission Requirements that Drive 

System Considerations 

While this is not a technical paper, a few basic technical concepts are needed for 

context. (It is a gratifying demonstration of the power of physics and chemistry that one 

can make serious progress evaluating alternative fuels by employing just a few simple 

concepts.) The most elementary concept of importance to this paper is that of mass. By 

definition, mass relates the motion of an object to a force applied to that object (as in 

“force equals mass times acceleration”). The subject of transportation fuels is ultimately 

about the ability to accelerate a vehicle of mass M to some desired speed (velocity)V , 

within some specified time and to dynamically control the speed so as to accomplish a 

desired mission. That mission may be as simple as moving a cargo from one point to 

another or as complex as conducting air combat operations. It is the mission that 

determines the dynamics required of a specific vehicle. These dynamics are independent 

(except for their mass) of the propulsion plant and the fuel that powers that plant. In this 

regard, a simplified dynamical model that relates mission requirements (e.g., required 

acceleration, required cruising speed, mission duration, vehicle mass and volume) to 

power plant properties (e.g., horsepower, weight, and volume) is useful. Such a model is 

presented in appendix A (A Simple Model for Vehicle Kinematics) for the case of land 

vehicles and some aspects of seagoing vehicles. We will apply this model to several 

vehicle types in order to gain some insight into the relationship between mission 

requirements and propulsion plant requirements. 

At the level of discussion appropriate to this paper, vehicle dynamics can be broken 

into two phases, an acceleration phase that moves a vehicle from one velocity to another 

and a cruising phase that involves motion at a constant velocity. Acceleration capability 

is usually a stated requirement in the performance specifications for a vehicle. In the case 

of acceleration from a stopped position, the most important forces are usually the inertial 

force, the gravitational force, and the rolling force. The rolling force results from energy 

that is lost during material deformation (e.g., of tires, treads, and pavement) as a vehicle 

moves. This force is approximately proportional to the weight of the vehicle and, 

therefore, explicitly involves the gravitational force. Equations (A2) and (A3) of 

appendix A are helpful in gaining insight into the impact of acceleration requirements on 

propulsion plant requirements. From these equations it is straightforward to estimate 

quantities such as horsepower, time required to reach a particular velocity, and the 

effective energy used during the acceleration process. The effective energy is a kinematic 

outcome of the mission requirements and is not the energy used by the power plant. The 

effective energy and the power plant energy are usually related by the efficiency of the 

propulsion system. 

As one might expect, there is often a tradeoff between a desired mission capability and 

the ability of technology to provide for that capability. In this regard, table 2 provides 

predictions for several land vehicles of the power and the effective energy that must be 

provided by the propulsion shaft when the requirement is to accelerate form a stop to 60 

mph (27 m/s) in 6 seconds over level asphalt. The table also gives the time to reach 60 
5

mph and the energy required to do so when the acceleration is accomplished using the 

horsepower that is actually available to each vehicle. The vehicles have been selected to 

cover the range from personal automobiles to heavy armored military vehicles. The 

vehicle characteristics used to construct table 2 are found in table A.1. The type of 

propulsion plant that was chosen for the various vehicles is indicated by parentheses in 

column 1. The effective energy that the chosen power plants must deliver in order to 

achieve 60 mph is given in the last two columns. 

Vehicle Vehicle 

weight 

(pounds) 

Effective 

horsepower 

needed for 

0 to 60 mph 

in 6 s 

Available 

horsepower 

(neglecting 

driveline 

loss) 

Time(s) to go 

from 0 to 60 

mph with 

available 

horsepower 

Effective 

energy (MJ) 

for 0 to 60 

mph in 6 s 

Effective 

energy (MJ) 

to achieve 60 

mph using 

available 

horsepower 

Tesla 

Roadster 

(electric) 

2723 215 288 4.4 .48 .48

Honda 

Accord 

(gasoline) 

3300 252 270 5.76 .58 .58

Jeep GC 

(gasoline) 

4470 363 195 11.5 .79 .83

Hummer 

(diesel) 

6600 520 240 12.5 1.16 1.24

MRAP 

(diesel) 

38,000 2887 330 67 6.2 9.2

Abrams 

tank (gas 

turbine) 

140,000 11,661 1500 103 24 58

Table 2. For several land vehicles, the horsepower and effective energy needed to go from 0 to 

60 mph in 6 seconds and also the time to reach 60 mph with the “as-built” horsepower and the 

effective energy required to do that. The acceleration occurs on a level asphalt surface. 

Of the vehicles considered, only the electric (Tesla Roadster) and the gasoline (Honda 

Accord) actually have the horsepower required to travel from 0 to 60 mph in 6 seconds. 

The other vehicles are underpowered to meet this objective. The last two columns 

compare the energy (in Mega Joules) needed to accomplish the acceleration in the two 

cases considered. The last two columns are essentially the same for the Roadster through 

the Hummer. This is because the energy needed to overcome the rolling force is small 

compared to the kinetic energy that was imparted to the vehicles. However, there is a 

notable difference in the last two columns for the MRAP and the Abrams. This is due to 

the large rolling force energy loss that results from the weight of the vehicles and the long 

times that are needed to accelerate these vehicles to 60 mph using the available 

horsepower. The third column demonstrates the impact on horsepower if a 6-second 
6

acceleration time is imposed as a mission requirement. For the MRAP (which can travel 

at 60 mph) meeting a 6-second requirement would require a nine-fold increase in the “asbuilt” engine power, mass and volume. For the Abrams tank, it would require an eightfold increase in the as procured engine power, mass, and volume. The heavy armor 

requirements associated with and the volumes available to these vehicles are not 

compatible with a six-second requirement using available propulsion technologies. It is 

straightforward to show from eq. (A2) that the 1500 horsepower Abrams tank can 

achieve a speed of about 20 mph in 6 seconds. (It should be noted here that, while the 

Abrams tank has the horsepower needed to reach 60 mph, it is restricted to speeds less 

than 42 mph.) 

 The acceleration calculations summarized above made use of the fact that the desired 

speed was achieved in distances that were short enough that the drag force had not 

become important to the energy consumption. In the cruise phase, however, the drag 

force usually plays an essential role. For land vehicles, one can gain some sense of the 

relative importance of the drag force and the rolling force by examining the ratio of drag 

force to rolling force versus velocity. Figure 2 displays this ratio for the vehicles 

considered in table 2 in the case of travel on asphalt roads. 

Figure 2. Ratio of drag force to rolling force vs speed (mph) for several vehicles

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 20 40 60 80 100 120

Speed (mph)

Ratio

Tesla Roadster

Honda Accord

Jeep GC

Hummer

MRAP

Abrams Tank

It is clear from figure 2 that the force that ultimately determines the velocity will vary 

dependent on the velocity and on the vehicle and its mission. For example, the drag force 

is not important for velocities of interest to the Abrams tank. For the other vehicles, the 

ratio becomes unity for velocities between about 50 mph and 70 mph. Over their speed 

ranges, the other vehicles must take into account both the drag force and the rolling force 

when traveling over an asphalt surface. This could change if the surface were to change. 

For example, if the MRAP calculation were done for travel on soft sand, then the rolling 

force coefficient would increase by about an order of magnitude due to the 

compressibility of the sand. In that case, the rolling force would dominate the drag force 

for all speeds of interest to the MRAP. 
7

Equation (A5) provides an expression for the horsepower required to maintain a 

vehicle at a particular speed during the cruising phase. In order to get a sense of that 

requirement relative to the horsepower requirement to provide for vehicle acceleration, it 

is informative to consider the ratio of the horsepower that is needed to maintain a vehicle 

at a particular speed over an asphalt surface to the horsepower available to that vehicle. 

This is done in figure 2 for the vehicles considered above. To obtain the absolute 

horsepower one multiplies the numbers in figure 2 by the available horsepower listed in 

table 2. 

Figure 3. Fraction of available horsepower needed to maintain speed vs speed 

(mph) for several vehicles

0

0.2

0.4

0.6

0.8

1

1.2

0 20 40 60 80 100 120

Speed (mph)

Fraction 

Tesla

Honda Accord

Jeep GC

Hummer

MRAP

Abrams

It is seen from figure 3 that, for most land vehicles, the available power exceeds what is 

needed to maintain the vehicles at a particular speed. For example, the average speed for 

private automobiles is estimated to be about 45 mph. To maintain that cruising speed, the 

Honda Accord, as shown in figure 3, requires about 6% of its rated horsepower. At its 

maximum allowed speed, the Abrams tank, in cruising mode, would require about half of 

its rated horsepower. The MRAP has a maximum rated speed of 69 mph. At that speed it 

would be operating at its maximum horsepower. In general, the horsepower of a land 

vehicle is determined by the acceleration requirements rather than the requirement to 

maintain a particular speed. 

The simplified model described in appendix A can also be used to provide estimates 

regarding the power and energy requirements of displacement-type seagoing vessels. In 

that case, the rolling force and the gravity force will be taken as zero. This leaves the 

inertial force and the drag force as the factors that determine power and energy 

requirements. The density of water is about one thousand times that of air, and the 

relevant area in the drag force is the ship wetted area. A simplified model for the wetted 

area and the drag force for displacement hull surface ships is presented in appendix A. 
8

For purpose of illustration, figure 4 provides estimates of the horsepower needed to 

maintain tanker class ships with lengths between 150 and 400 meters, at a particular 

speed. A drag coefficient of .004 was taken as being representative of the tanker ships 

(see Lin et al3

). 

Figure 4. Cargo ship required effective horsepower vs cruise speed in knots (150-400 

meter length)

0

50

100

150

200

250

0 5 10 15 20 25 30

Speed (knots)

Effective Horsepower (thousands)

150 meters

200 meters

250 meters

300 meters

350 meters

400 meters

As a point of comparison, the VLCC tanker Frank A Shrontz, with a length of about 

330 meters and a cruising speed of 16 knots, has a power plant of about 34,000 

horsepower. This is in reasonable agreement with the predicted value obtained from 

figure 4 and suggests that the power plants chosen for cargo ships are selected to be close 

to the power needed to maintain a desired cruising speed. Similar calculation can be done 

for fast ships (war ships, cruise ships) when the appropriate values of the drag coefficient 

and wetted surface areas are known. It is clear that ships involved in modern commerce, 

as well as upper end military vessels and cruise ships, have large power requirements. 

Since these vessels must travel long distances, fuel efficiency can be expected to be a 

significant factor in engine selection. The following sections will discuss, among other 

things, factors that influence fuel efficiency. 
9

3. Review of Engine Technologies 

The discussion so far has been focused on mission requirements and has been largely 

independent of the selection of power plants or fuels. Once mission requirements have 

been determined, then the selection of the engine most appropriate to the mission can be 

undertaken. While there are a large number of engine technologies available, most 

engines of interest to transportation fall into the categories of internal combustion (e.g., 

gasoline engines, diesel engines, and gas turbines), steam turbines, electric motors, and 

combinations of the above. This section will undertake a brief review of several of these 

engine technologies and the means used to select among them. 

The internal combustion engines and the steam turbines operate by creating a hot gas 

or vapor and subjecting that gas or vapor to a thermal cycle that converts heat energy into 

mechanical energy. This conversion may be accomplished by pushing pistons or rotating 

turbine blades. As a result, the efficiencies of the conversion processes are limited by the 

laws of thermodynamics. This efficiency is called the thermal efficiency and depends on 

the thermal cycle that characterizes each engine. The principal thermal cycles used are 

the Otto Cycle (gasoline engines), the Diesel Cycle, and the Brayton Cycle (gas and 

steam turbines). These cycles are usually described in terms of a closed curve on a 

pressure-volume chart. The Otto cycle, for example, involves a closed curve that 

connects two volumes (e.g., the piston down volume and the piston up volume). Energy 

is required to compress the fuel air mixture as one goes from the piston down state to the 

piston up state. A spark is used to ignite the fuel air mixture. This releases chemical 

energy in the form of heat, which raises the pressure in the compressed gas, thereby 

creating mechanical energy by pushing the piston so that it travels back to its down state. 

This mechanical energy is transferred to a flywheel that is used to provide torque to 

power the wheels and energy to recompress the gas. Heat that is left in the gas after the 

down stroke is removed, the cylinder is recharged and the cycle is repeated. The thermal 

efficiency of this process is just the energy supplied by combustion minus the heat that is 

removed when the cylinder returns to the down state divided by the energy that was 

supplied by combustion. This efficiency is found to be a function of the ratio of the 

uncompressed volume to the compressed volume and increases as this ratio increases. 

Because of the properties of gasoline, the permitted ratio is usually less than 10:1, and the 

ideal thermal efficiency is about 47%. No thermal cycle is ideal. The non-ideal factors 

reduce the Otto cycle thermal efficiency to about 37%. The Diesel cycle is slightly more 

complicated than the Otto cycle in that it operates between a constant volume and a 

constant pressure. Its thermal efficiency, however, also involves a volume compression 

ratio, which, because of the nature of the diesel compression and of diesel fuel, can be 

much greater than the Otto cycle compression ratio. Compression ratios of 20:1 can be 

achieved. This leads to diesel engines usually being about 30% more efficient than 

gasoline engines. The ideal Brayton cycle operates between two pressures, and its 

thermal efficiency can be shown to be determined by the pressure ratio. Pressure ratios up 

to 40:1 have been used and can lead to ideal thermal efficiencies of about 60%. Those 

interested in the details of these thermal cycles will easily find descriptions via an 

Internet search. 
10

While the thermal efficiencies are important, from a mission viewpoint, the principal 

propulsion plant parameters of interest are torque, thrust, power, fuel consumption, 

weight, and volume. We will briefly review these for the engines mentioned above. 

If we consider the case where the output power is extracted from a rotating shaft, then 

of particular interest is torque T, which is the amount of force applied tangentially to a 

circle, so that the load at a particular rpm is measured by the torque being applied by the 

vehicle driveshaft. Torque is routinely measured as part of characterizing a particular 

engine. The torque characteristics differ among the various types of engines typically 

used in transportation and influence the decision regarding what type of engine to use in a 

particular application. In order to illustrate the torque differences among engine 

technologies, Figure 5 compares the torque vs. rotation rate for several engine 

technologies applied to engines of similar size (in each case with the engine set for 

maximum power and the curve derived from a commercially available engine). For each 

engine technology, the torque has been normalized to a maximum value of one in order to 

cleanly display the various torque characteristics on a single chart. 

Figure 5. Normalized torque vs rotation speed

0

0.2

0.4

0.6

0.8

1

1.2

0 1000 2000 3000 4000 5000 6000 7000 8000

Rotation Speed (rpm)

Normalized Torque

Gas Turbine

Diesel

Electric

Gasoline

It is evident from figure 5 that the various engines have quite different torque 

characteristics. The electric motor has close to ideal torque characteristics in that its 

torque is independent of rotation rate until it reaches high rpm. This makes this engine, in 

principle, broadly applicable. However, as we shall see later, there are significant 

challenges in providing the power and energy needed to broadly apply this engine to 
11

many transportation applications. The gas turbine engine achieves maximum torque at 

low rpm with the torque declining as the rpm increases. High torque at low speed is 

needed for rapid acceleration and for moving large loads. However, for this engine, the 

maximum torque at low shaft rotation rate is only achievable with the compressor 

operating at maximum and the output shaft strongly braked. This results in significant 

fuel consumption at low speeds thereby limiting its application in the low rotation rate 

arena. In the case shown, the diesel engine provides maximum torque at about 1800 rpm. 

This torque peak occurs at substantially lower rpm than does the peak for a similar size 

gasoline engine. This is one of the reasons why diesel engines are used for hauling freight 

and gasoline engines are not. The gasoline engine curve is broad and provides maximum 

torque at about 4500 rpm for the case shown. This allows the application of high torque 

at high speed, which is desirable for passenger cars. 

Figure 6. Normalized Horsepower vs Rotation Speed

-0.2

0

0.2

0.4

0.6

0.8

1

1.2

0 1000 2000 3000 4000 5000 6000 7000 8000

Rotation Speed (rpm)

Normalized Horsepower

Gas Turbine

Diesel

Electric

Gasoline

While torque is the parameter that determines the force (and hence the acceleration) that a 

rotating shaft can apply, the power provided by the shaft determines the rate of fuel 

consumption needed to accelerate a vehicle and keep it in motion. The power P provided 

by a rotating shaft is related to the torque by the expression: P = T × 2 , where π × f f is 

the rotation rate of the shaft. Thus, the power is directly obtained from a measurement of 

the torque. Figure 6 provides the horsepower curves that result from the torque curves 

shown in figure 5. The power curves have been normalized such that the maximum 

horsepower for each engine is one. 
12

It can be seen from figure 6 that the horsepower curves for the gas turbine and for the 

diesel are similar, although the gas turbine develops its horsepower more rapidly at low 

rotation rates. The similarity occurs because the engines used as the basis for the curves 

were designed for similar applications, namely that of powering light trucks and buses. 

The curves for the electric engine and the gasoline engine are also similar, because the 

engines that formed the basis for these curves were designed to power passenger cars. 

Figures 5 and 6 make the obvious point that the mission of the vehicle strongly influences 

the selection and design of the propulsion power plant. 

Figure 7. Normalized BSFC vs Percent of Maximim Power for Three 

Engine Types

1

1.05

1.1

1.15

1.2

1.25

1.3

1.35

1.4

1.45

1.5

0 20 40 60 80 100 120

Percent of Maximum Power

BSFC

Gasoline

Diesel

Gas Turbine

A third factor that is important in characterizing an engine is its fuel consumption. The 

energy flow into an engine can be easily determined by measuring the rate at which fuel 

is consumed. If the fuel is liquid, then the rate of consumption might be measured in 

grams per second. If it is a gas, then the rate of fuel consumption might be measured in 

cubic meters per second. If the energy supply is electric, then the supply current and the 

supply voltage would be measured to give the energy input rate directly in Watts. In the 

case of internal combustion engines, the chemical energy content of the fuel is released 

upon combustion. For example, gasoline has a chemical energy content of about 43 

MJ/kg, while natural gas has energy content at normal temperature and pressure of about 

38 MJ/m3

. Thus, if one measures the consumption of gasoline in kg/s, or that of natural 

gas in m3

/s, then it is straightforward to obtain the energy consumption rate in MJ/s. The 

energy consumption is, of course, specific to the load that has been applied to the engine 

and the rate at which the engine is turning. These can be directly measured. The results of 
13

these measurements are usually expressed as the ratio of the rate of fuel consumption in 

grams per second to the power in Watts (Joules per second) being produced by the 

engine. This ratio is referred to as the brake specific fuel consumption (BSFC) and is 

often expressed in grams per kilowatt hour. Figure 7 plots the normalized BSFC versus 

the percent of maximum power for the three road vehicle internal combustion engines 

considered above. 

The BSFC in figure 7 is normalized to the minimum BSFC for each engine (with the 

engines set for maximum power). BSFC of unity, or the point where each curve touches 

the power axis, is the power at which minimum fuel consumption occurs. The gasoline 

and diesel engines show a BSFC minimum in the vicinity of 40% of maximum power. 

The gas turbine engine shows a minimum at 90% of maximum power. From a fuel 

consumption viewpoint, it is clear that these engines are best suited for different 

applications. The gas turbine shows high fuel consumption at low power and is best 

suited for applications where it will operate near maximum power most of the time or 

where high torque (or thrust) at low speed is a requirement that overrides high fuel 

consumption. The gasoline engine shows high fuel consumption when operated near 

maximum power and is best suited to applications where maximum power is required 

during only a small fraction of its operation. The diesel engine demonstrates relatively 

flat BSFC over much of its power range but the BSFC does increase rapidly as it nears 

maximum power. While it is possible to modify the BSFC curves by various engine 

modifications, the basic trends shown in figure 7 are intrinsic to the engine types. 

When two power plants can meet the mission torque, power, and fuel consumption 

requirements, then other factors, such as engine size and weight, will determine which 

engine is selected. This leads to the introduction of engine characteristics such as specific 

weight (lb/h.p.) and specific volume (cu.ft./h.p.). Table 3 provides a comparison of 

several engines including these additional characteristics. 

It is clear from table 3 that there is considerable variability among the various engines. 

For example, among the internal combustion engines, the marine diesel represents the 

heaviest technology and requires the largest installation volume. On the other hand, it has 

among the lowest specific fuel consumption and the highest energy efficiency. Hence, 

this technology finds its applications to missions where weight and volume are not a 

constraint, but fuel efficiency is of great concern. As a result, the marine diesel currently 

dominates in the area of commercial ship propulsion. At the other extreme is the gas 

turbine. This is the lightest technology and requires the least volume. However, it has 

rather high specific fuel consumption and modest energy efficiency. This technology 

finds applications where weight and volume are constrained and high power is desired 

but where fuel efficiency is not a major constraint, or where the engine is expected to 

operate at maximum power most of the time. This technology is used in military 

platforms such as tanks and ships and, of course, dominates the field of aircraft 

propulsion, where several variations of the technology (e.g., turbo shaft, low bypass turbo 

fans, turbo jets) are employed depending on the aircraft mission. 
14

 

Engine Specific Weight 

lb/h.p.

Specific Volume 

cu.ft./h.p.

Minimum 

Specific Fuel 

Consumption 

lb/h.p.hr.

Engine Energy 

Efficiency 

Low-rpm 

Marine Diesel 

109,000 h.p. 

42 0.35 0.26 0.54 

Diesel 

160 h.p. 

7 0.3 0.22 0.35 

Gasoline 

180 h.p. 

2.5 0.05 0.45 0.25 

Gas Turbine 

1500 h.p. 

1.7 0.03 0.45 0.4 

Gas Turbine 

57,330 h.p. 

0.3 0.03 0.33 0.42 

Electric 

288 h.p. 

.25 0.02 NA 0.9 

Table 3. Specific weight, specific volume, specific fuel consumption, and energy efficiency for 

several engines. 

The electric motor stands out among the several technologies listed in table 3. It is the 

lightest technology, requires the least volume and has the highest energy efficiency. All 

things being equal, this would seem to be the best technology for delivering shaft 

horsepower. However, it will become clear in the following section that the application of 

electric motors to transportation propulsion is quite challenging. If the challenges can be 

overcome, the electric motor could have a very large impact on the choice of alternative 

transportation fuels. 
15

4. Selecting the Power Plant 

Section 2 provided a brief overview of how mission requirements translate into 

dynamical and kinematical requirements. Section 3 provided a brief review of engine 

technologies that might be compatible with those requirements: diesel, gasoline, gas 

turbine, and electric. This section will provide a brief review of how to evaluate various 

power plants within the context of specified missions, and also includes an overview of 

the current status of batteries and fuel cells in the discussion of the electric motor engine. 

Engines must be supplied with fuel (energy) if they are to do anything. Figure 8 

provides a simple conceptual drawing of how power might flow in a propulsion power 

plant. 

The “engine power” circle represents the components that provide the power to 

generate the force that propels the vehicle. The engine power usually conveys via a 

rotating shaft that generates torque to drive wheels, treads, or propellers or through an 

exhaust fluid that provides thrust as in a jet engine. The “fuel energy” circle represents 

the component that provides the primary energy to power the engine. This could be a tank 

of fuel (e.g., gasoline, diesel, ethanol, and methanol), a pack of batteries, or a fuel cell 

and its fuel. The primary power supply may not be able to generate the peak power 

required by the vehicle’s mission even though it must be able to provide the average 

required power. In these cases it is necessary to incorporate a power source that can 

provide the required peak power. This power source is designated by the “pulse power” 

circle. The pulse power source may be a battery or may be composed of devices such as 

electrical capacitors. The intent of the pulse power unit is to provide high power for short 

times such as when acceleration is needed to climb a hill. The pulse power source will 

need to be charged or recharged from either the primary fuel or from output power of the 

engine as indicated by the dashed lines in figure 8. While the figure shows only one 

engine, it may involve several engines, such as occurs with the combination of internal 

combustion and electric engines in hybrid drive vehicles. The quantity PF is the primary 

power delivered by the fuel. For example, if the engine were an internal combustion 

engine then PF would be the energy content per kilogram of fuel times the number of 

kilograms per second of fuel being supplied to the engine. If the engine were an electric 

motor, then PF would be the voltage times the current being supplied by the batteries, 

electric generator, or fuel cells. The quantity PFP is the primary fuel power that is 

diverted to charge the (auxiliary) pulse power system. The quantity PIN is the input 

power to the engine, while POUT is the output power of the engine. These quantities are 

related by the efficiency of the engine. The quantity PEP represents engine output that is 

diverted to charge the pulse power system and PPP is the delivered pulse power. The 

quantity Pe is the power that is actually provided to propel the vehicle and is determined 

by mission requirements. The mass appropriate to the power plant is the sum of the 

engine mass Me and the fuel mass M f , where M f includes the fuel and the pulse power 

masses. 
16

Figure 8. Conceptual outline of power flow within a vehicle power plant. 

The energy Es that can be extracted from the various energy sources is mostly well 

understood. This energy is supplied to an engine that can turn it into useful work with an 

efficiency η. It is obvious that the energy Es is a function of the mission duration and the 

mission effective power requirements Pe . The fuel mass M f is often related to the source 

energy Es by the expression Es = M ef s , where s e is the specific energy of the fuel. For 

example, for gasoline 12 s e = Watt hours per gram (Wh/g) of gasoline. This allows the 

determination of the fuel mass needed to provide the mission energy Es . The fuel mass is 

taken to be the sum of the masses of all the components (i.e., fuel, batteries, fuel cell, 

generator, pulse power) that supply energy to the engine. The energy and power that can 

be extracted from fuels, batteries, fuel cells, pulse power systems, and generators are 

determined by detailed measurements that characterize particular fuels, batteries, fuel 

cells, pulse power systems and generators. These detailed measurements allow one to 

characterize various power plants in terms of their specific power and specific energy. 

For a given mission, the specific power SP of the total power plant is defined as 

e

f e

P SP

M M = +

. (1) 

Fuel 

Energy 

Engine 

Power 

Pulse 

Power 

PF

PF P

PIN POUT

PEP

Pe

PPP
17

Similarly, the specific energy SE of the total power plant is defined as 

s

f e

E SE

M M

η = +

. (2) 

These quantities are mission dependent. We saw in section 2 that Pe is determined by 

acceleration and/or speed requirements and by the total mass of the vehicle. For the 

purpose of discussion, we will assume that the mass of the vehicle is much greater than 

the sum of the fuel mass and the engine mass. In this case, Pe becomes independent of 

M f and Me . As a result, SP will decrease as M f increases (i.e., as the mission duration 

increases). The source energy Es is taken to be proportional to the fuel mass M f . Thus, 

for very long missions, when the fuel mass is much greater than the engine mass, the 

power plant specific energy will become constant and equal to the specific energy of the 

fuel source times the conversion efficiency of the engine. The conversion efficiency is a 

function of the power being supplied to the engine. At the other extreme, when M f is 

much less than Me , the power plant specific energy will scale as M f / Me . 

Power has units of energy divided by time. Thus, the ratio SE / SP defines a time t

where 

e

S

P

E

t η

= . (3) 

The time t provides an estimate of the time to deplete the fuel supply and, hence, of the 

time between refueling or recharging. 

Ordinarily, the mission requirements will determine Pe , M f + Me and t . Once these 

are specified, then SP and SE become determined for the mission. Since only M f + Me

is specified, there is a tradeoff between M f and Me . As an illustration of the outcome of 

such a specification/tradeoff, table 4 provides estimates of SP , SE for several 

commercial engines that have been chosen to respond to the specifications indicated. The 

specifications have been selected to cover the range from passenger cars to massive cargo 

ships. 

The specific powers shown in table 4 are calculated for maximum power. Hence, the 

discharge times shown are for maximum power. As the power level is decreased below 

maximum power the discharge time will increase accordingly. For example, the Honda 

J30 engine operating at 10% of maximum power would have a discharge time of about 8 

hours with the fuel mass indicated. 

The data shown in table 4 provide some insight into the various power plants. For 

example, the large, low-rpm diesel RTA96-C is clearly designed for specific energy 

rather than for specific power. Even if the fuel mass of this power plant were reduced to 

being much less than the engine mass, the maximum specific power would be only about 

40 W/kg. This power plant is designed to economically move large masses long 

distances. The power plants associated with the two gas turbines (LM6000 and AGT1500) represent a compromise to provide reasonably high specific power and specific 
18

energy as required by their military applications. The diesel plant 6D14-3A has been 

designed to provide moderate specific power and relatively high specific energy. The 

gasoline plant J30 has been designed to provide both high specific power and high 

specific energy. The battery electric power plant has opted for a relatively high specific 

power in order to compete for the passenger vehicle mission. The low specific energy of 

the power plant is a result of the low specific energy of the battery technology employed 

in the power plant and reflects the current state of battery technology. 

Engine 

selected 

Specified 

Max 

Horsepower 

Specified 

Engine 

Mass + 

Fuel 

Mass

Specified 

Depletion 

Time 

(hours) 

@Max 

HP

Resulting 

Engine 

Mass 

(kg) 

Resulting 

Fuel 

Mass 

(kg) 

Efficiency 

of 

Selected 

Engine

Specific 

Power 

(W/kg) 

@ Max 

HP 

Specific 

Energy 

(Wh/kg)

WartsilaSulzer 

RTA96-C 

Diesel 

(ship) 

109,000 1.2x107 735 2x106 107 .5 6.8 5,000 

General 

Electric 

LM6000 gas 

turbine 

(ship) 

57,330 106 113 7,818 106 .4 42.5 4,800 

Honeywell 

AGT-1500 

gas turbine 

(tank) 

1,500 2,800 7 1134 1666 .4 390 2,800 

Mitsubishi 

6D14-3A 

Diesel 

(bus/truck) 

160 620 4 500 120 .33 192 767 

Honda J30 

Gasoline 

(automobile) 

245 146 .8 110 36 .25 1,253 1,000 

Tesla 

battery 

(electric car) 

288 483 .2 33 450 .9 445 99 

Table 4. Specific power, specific energy, and depletion or discharge time for several engines with 

typical mission assignments indicated in parenthesis. 

Data of the type shown in table 4 provide a straightforward means for making rough 

comparisons among power plant technologies as they apply to particular missions. In 

section 3, it was shown that an electric motor has the most attractive torque, efficiency, 

and weight characteristics of the shaft horsepower systems considered. Let us now 

consider the application of electric engine technology to transportation power plants that 
19

must carry their own energy. Ragone introduced a chart that plots specific power against 

specific energy.4

 The chart is now widely used to compare power technologies. Figure 9 

provides a “Ragone chart” that summarizes the state of the art for several battery and fuel 

cell technologies. 

Sources: Scott,http://ntrs.nasa.gov/archive/nasa/casi.ntrs.nasa.gov/20070021785_ 

2007019841.pdf . Meeting the Energy Needs of Future Warriors, The National Academies Press, 

2004 available at http://www.nap.edu/openbook.php?isbn=0309092612&page=40. 

The diagonal lines in figure 9 represent depletion times ranging from 0.01 hours to 

1000 hours. The depletion times are indicated for each line. As discussed above, the 

mission of a vehicle would determine its mass, its required peak power, its average 

power, the depletion time at peak power, and the mass and volume that can be allocated 

to the power plant. The ratio of the required peak power to the available power plant 

mass determines the peak specific power. The intersection of the required peak specific 

power and the depletion time line determines the required specific energy. This 

information allows one to obtain a sense of what power plant technologies are available 

to meet the mission requirements. 

The discrete data points on the plot represent the data from table 4 and are evaluated at 

the mission maximum power requirement. For instance, the J30 Honda gasoline 

combustion engine can operate at full power for about 1 hour. The internal combustion 

plant discreet data points shown in figure 9 are representative of DOD requirements for 

light passenger vehicles, light trucks, land moving equipment, tanks, ships, and aircraft. It 
20

is noteworthy that all of these data points lie outside the regions that are directly 

accessible by currently available battery and fuel cell technologies. There are batteries 

that have the required specific power but not the required specific energy. The fuel cells 

may meet the specific energy requirements for average power for the J30 and 6D14-34 

power plants but not the specific power requirements at maximum power. It is necessary 

that both requirements are met because they are set by the mission. However, it is not 

always necessary that these two requirements be met simultaneously. For example, most 

of the time, the 6D14-3A diesel engine shown in figure 9 may operate at a point on the 

10-hour depletion that lies just inside the region covered by fuel cells. As long as the fuel 

cell can provide the additional energy needed to recharge the batteries (or capacitors) and 

also provide the energy needed to meet the average power needs, a hybrid solution that 

combines technology that can produce high power for a short time with technologies that 

can produce low power for long times might be possible. However, as the average power 

becomes closer to the peak power this becomes difficult to do. This is the situation for the 

data points represented by the AGT 1500, the LM6000, and RTA96-C power plants. It 

seems unlikely that any future battery and fuel cell arrangement will meet the 

requirements represented by those points. It is, of course, possible to provide an electric 

drive solution to those requirements by connecting (with appropriate reduction gears) the 

driveshafts of those internal combustion power plants to a properly sized electric 

generator, and then provide the generated electric power to an electric motor for electric 

drive. This would increase the mass and volume associated with the power plants and 

would slightly reduce the conversion efficiency, but should not greatly shift the location 

of the associated points in figure 9. For the large systems involved here, the efficiency 

loss could be compensated for by employing co-power generation, where the waste heat 

from the internal combustion process is captured to raise steam for the purpose of 

generating additional electric power. This, of course, further increases the mass and 

volume required for the total power plant. However, cogeneration is widely used and can 

achieve overall efficiencies of 60%. This approach can be quite attractive if the mass and 

volume allocation for the power plant can accommodate it. Such an electric power 

solution is actually an internal combustion solution rather than an all-electric solution. 

The major reason to consider such an approach would be the potential convenience and 

flexibility that a large electric power plant might provide (e.g., ship propulsion power and 

ship onboard power from a common power source). 

For shaft horsepower applications, the electric motor is the most attractive in terms of 

principal propulsion plant parameters, as we saw in section 3. However, the Ragone chart 

figure 9 shows that the electric motor is currently limited by the specific energy and 

specific power characteristics of available battery and fuel cell systems. There are 

ongoing battery developments that could improve the viability of electric motors for 

transportation. One example of this is the lithium air battery.5

 This battery chemistry is 

currently under study, and Ragone charts are not yet available. Based on the theoretical 

maximum energy density of the lithium air chemistry and the industrial experience that 

relates theoretical energy density to energy density that can be achieved in practice, 

expectations are that a primary lithium air cell could achieve an energy density of 1700 

Wh/kg. If this energy density could be achieved in a rechargeable lithium-air cell, and if 

the discharge characteristics allow a specific power in the 1000 W/kg range, then this 

hypothetical lithium-air cell would approach the range now occupied by internal 
21

combustion engines. In order to gain some insight regarding how this hypothetical battery 

would impact the matter of transportation fuels, it is interesting to compare the depletion 

times shown in table 4 with those that would be predicted when the sum of the engine 

mass and the fuel mass is that shown in table 4 but the power plant is composed of an 

electric motor and the hypothetical lithium air battery that has an energy density of 1700 

Wh/kg and is able to meet the specific power requirements shown in table 4. This 

comparison is done in table 5. 

Engine Measured Depletion Time 

(hrs) for Several Engines, 

from Table 4 

Hypothetical Depletion Time 

(hrs) Using Hypothetical LiAir Battery and Electric 

Motor 

Tesla (electric) 0.2 3.15 

J30A (gasoline) 0.8 0.95 

6D14-3A (diesel, land) 4 7 

AGT1500 (gas turbine, land) 7 3 

LM 6000 (gas turbine, ship) 113 21 

RTA96-C (diesel, ship) 735 211 

Table 5. Comparison of depletion times from table 4 with those predicted for a replacement of 

the power plant with a hypothetical Li-Air battery and an electric motor. 

In this table, the Tesla electric motor is used for both the replacement of the Tesla 

power plant and the J30A power plant. The 6D14-3A and AGT1500 engines are replaced 

by industrial quality electric motors that have specific weights of one pound per 

horsepower. The LM 6000 and RTA96-C engines are replaced by electric motors that 

have specific weights of 15 pounds per horsepower, which is representative of similar 

sized electric motors used to power the RMS Queen Elizabeth II.6

 

The hypothetical Li-Air battery considerably increases the depletion time for the Tesla 

power plant. The J30A replacement plant provides a slightly increased depletion time. 

Since both the Tesla and J30A power plants are expected to spend most of their operating 

time at about 10% of maximum power, it seems likely that a day’s driving (about 400 

miles) could be accomplished with the hypothetical Li-Air battery power plant. This 

would make overnight recharging of the batteries reasonable at about a 10 KW charging 

rate. The 6D14-3A power plant replacement provides about a 70% increase in the 

depletion time resulting in a 7-hour depletion time at maximum power. If one assumes 

that the application of this power plant will require that it operate on average at half its 

maximum power, then the time between recharging would be about 14 hours. A 10-hour 

recharge time would require a 100 KW charging system. This arrangement might be 

viable for commercial applications (bus, light truck, etc) where recharge periods could be 

scheduled. However, it is unlikely to be suitable for military applications where vehicles 

must be available on demand and recharge time requirements are measured in minutes. In 

the cases of the use of Li-Air batteries and electric motors to replace the AGT 1500, 
22

LM6000 and RTA96-C power plants, the replacement power plant depletion times do not 

meet the mission requirements. 

From the above discussion one can conclude that, if the hypothetical, rechargeable LiAir battery (SP = 1000 W/kg, SE = 1700 Wh/kg) were realized and found to be 

economical, durable and safe enough for manned vehicular use, it would enable the 

replacement of the internal combustion-powered passenger vehicle with an all electric 

vehicle that could travel 400–500 miles on a single charge. It is interesting to speculate 

on how such a development would impact the matter of transportation fuels. Table 1 lists 

the 2007 U.S. usage of petroleum and indicates that about 13.4 million barrels per day is 

used for transportation purposes. About 70% of this usage can be attributed to passenger 

vehicles, which appear to be amenable to being powered by the hypothetical Li-Air 

battery. Thus, if the hypothetical, rechargeable Li-Air battery were realized and found to 

be economical, durable, and safe, 70% of the need for conventional transportation fuel 

could be eliminated. This outcome would have a very large impact on alternative 

transportation fuels. The burden of fueling vehicles now powered by gasoline would pass 

to the nation’s electric grid. Since passenger vehicles travel about five billion miles per 

day, the burden on the grid would be about 1011 Watts corresponding to about 20% of 

current average electric power consumption of 5x1011 Watts. The total U.S. electric 

generating capacity is about 1012 Watts. Thus, it may be possible that this increase could 

be absorbed by the existing generating capacity, in which case there would be no power 

plant construction required to transition passenger vehicles to electric drive on a large 

scale. However, because peak electric power requirements can be about 80% of the 

maximum generating capacity, it would be prudent to plan on adding the additional 

capacity needed to accommodate a large-scale move to electric passenger vehicles. 

The technology options for provision of this additional electrical capacity are likely to 

be broader than those associated with the production of a hydrocarbon or alcohol 

replacement of gasoline. For example, the additional capacity could be provided by 

doubling the Nation’s current nuclear power electrical generating capacity or adding 

additional coal or natural gas electrical power plants.. There is a great deal of uncertainty 

regarding the capital cost associated with constructing new nuclear power plants. A unit 

cost of about $1500/KWe is at the lower end of estimates that are now appearing in the 

literature. This unit price is also representative of coal-fired power plants. At this unit 

price, the capital cost of adding 1011 W would be about 150 billion dollars. There would, 

of course, be additional capital investments needed to put in place the infrastructure that 

would produce and recycle the batteries and the infrastructure associated with recharging 

the electric vehicles. The total capital investment, however, is likely to be comparable or 

less than that associated with putting in place a synthetic fuel production infrastructure 

required to replace petroleum-derived gasoline. In light of this, it would seem that a 

resolution of the viability to transportation systems of Li-Air-like battery chemistries will 

be important to determining the future direction for alternative transportation fuel 

initiatives. 

Central questions are: can Li-Air battery technology provide needed acceleration, and, 

is it viable for heavy vehicles? At this time it is not clear that the Li-Air chemistries will 

be viable for transportation systems. For example, the high specific energies that have 

been reported for Li-Air batteries involve low discharge currents, where the discharge 
23

times are measured in hundreds of hours. While the published data is limited, it is clear 

that the energy that can be extracted from the batteries decreases rapidly with increasing 

discharge currents, which would be necessary for rapid vehicular acceleration. This is the 

same phenomenon that is evident for batteries and fuel cells in the Ragone chart given in 

figure 9. It is possible and even likely that the Li-Air battery will prove to be a high 

specific energy device but a low-to-moderate specific power device. Furthermore, even if 

the chemistries do enable large-scale use for passenger vehicles, it is unlikely that they 

will enable battery-powered heavy trucks, jet aircraft, armored vehicles, tanks, and large 

ships. 

Missions drive the need for heavy trucks and armored vehicles, and the consequent 

need for combustion engines—and hence the need for liquid fuels that have the attractive 

features of petroleum-based fuel products. It is, therefore, prudent to continue to 

investigate alternative means to the equivalent of conventional fuels, especially those that 

are not likely to be supplanted by all-electric propulsion. The following sections will 

provide an overview of several approaches in this regard. We start with hydrogen, 

followed by coal to liquid, natural gas and gas hydrate-derived fuels, bio-derived fuels, 

CO2-derived fuels and, finally, oil shale. 
24

5. The Role of Hydrogen 

This section will provide a brief discussion of the role of hydrogen in alternative 

transportation fuels. Hydrogen is broadly important to the subject of alternative 

transportation fuels, so is considered first in this review. It may be a constituent of the 

fuel (e.g., hydrocarbons or alcohols), it may play a role in battery chemistry or fuel cell 

chemistry, or it may be the fuel itself (e.g., a hydrogen-fueled internal combustion 

engine). The prospects for hydrogen as a fuel for DOD were discussed by Coffey et al.7

This section will summarize the relevant findings from that paper. 

To begin that discussion it is helpful to put hydrogen into perspective relative to 

several other fuels. It is clear from eq. (A1) that the fuel mass that a vehicle must carry 

directly impacts on the vehicle dynamics. Also, the volume constraints on transportation 

vehicles place significant limits on the amount of fuel that a vehicle can carry. Thus, as 

discussed earlier, energy per unit mass and energy per unit volume are important metrics 

for judging the viability of various transportation fuels. Since the most familiar 

transportation fuel is gasoline, it is helpful to have an understanding of energy content of 

various alternative energy sources of interest relative to the energy content of gasoline. 

This is provided in table 6 for several energy sources. If one wishes to estimate real 

energy densities rather than relative energy densities, one can take the specific energy of 

gasoline to be about 12,000 Wh/kg, or about 9 Wh/cc. Multiplication of columns two and 

three of table 6 by the appropriate specific energy of gasoline will provide estimates of 

the specific energies of the various energy sources listed. 

It should be clear from table 6 why the liquid hydrocarbon fuels (particularly gasoline 

and diesel) have been dominant for the past 100 years. With the exception of hydrogen, 

they provide the highest energy content by either measure and are easily stored at room 

temperature and pressure. Were it not for growing concerns regarding their continued 

easy availability and their potential adverse environmental impact, hydrocarbon fuels 

would remain the obvious transportation fuels of choice. The liquid alcohol fuels ethanol 

and methanol have the next highest energy content by either measure (again, except for 

hydrogen). The hydrocarbon gas methane, when pressurized to 10,000 psi, approaches its 

liquid energy densities and approaches 50% of the volumetric energy density of gasoline. 

The listed batteries have the lowest energy content by either measure (except for 

hydrogen @ 3000 psi) of any of the fuels listed. 

Regarding hydrogen, it can be seen from table 6 that hydrogen has the highest energy 

content per unit mass of any of the listed fuels. However, for transportation fuels, energy 

content per unit volume is often the more important parameter because of volume 

constraints. By this metric (with the exception of batteries), hydrogen has the lowest 

energy content of the listed fuels. Furthermore, to obtain hydrogen’s highest volumetric 

energy content it must be cooled to – 253 Co or pressurized to over 10,000 PSI. These 

properties of hydrogen make it problematic as a fuel, especially for most highperformance DOD platforms. 
25

Energy Source Energy per 

unit mass

Energy per 

unit volume

Temperature o C Chemical 

Formula 

Liquid Gasoline 1.0 1.0 25 <C8 H18 > 

Liquid Diesel .97 1.1 25 <C12 H23 > 

Liquid propane (@ 

90psi) 

1.0 .86 25 C3 H8 

Liquid Methane 1.3 .75 -162 CH4 

Liquid Ethanol .61 .69 25 C2 H5 OH 

Liquid Methanol .44 .51 25 CH3 OH 

Liquid hydrogen 2.6 .27 - 253 H2 

Methane Gas (@ 

3000 psi) 

1.3 .37 25 CH4 

Methane Gas (@ 

10,000 psi) 

1.3 .5 25 CH4

Hydrogen Gas (@ 

3000 psi) 

2.6 .06 25 H2

Hydrogen Gas (@ 

10,000 psi) 

2.6 .2 25 H2

Lead Acid Battery .003 .006 25 NA 

Li Ion Battery .013 .026 25 NA 

Li Polymer Battery .01 .029 25 NA 

Hypothetical LiAir battery .14 .1 25 NA 

NiMH Battery .004 .02 25 NA 

Table 6. Energy content and chemical composition of several energy sources referenced to 

gasoline. The bracket < > indicates the average chemical formula. (Source: modified from Coffey 

et al.7

) 

Hydrogen is the simplest element and can be considered to exist in unlimited supply on 

earth. When combined with oxygen in a fuel cell it produces electricity (and water) that 

can be used to power vehicles. The range of specific energy and specific power of typical 

fuel cells is summarized in figure 9. If pure hydrogen is stored on the vehicle, a fuel cell 

can convert it to electricity with about 80% efficiency. This is conceptually a 

straightforward approach and eliminates CO2 production on the vehicle, but it requires 
26

that hydrogen adequate to the vehicle’s mission be stored on the vehicle at high pressure 

or at cryogenic temperatures. It is also possible to produce hydrogen onboard the vehicle 

by using reforming techniques to remove the hydrogen from fuels such as methanol, 

ethanol, gasoline, and diesel. This conversion can be done with about 30–40% efficiency 

and requires that fuel adequate to the vehicle mission be stored onboard the vehicle. This 

approach eliminates the complexity of the hydrogen storage system but replaces it with 

the complexity of a reformer and a hydrogen purification system and produces CO2 as a 

by product of the reforming process. It seems likely, based on the considerations of the 

previous section, that a hydrogen fuel cell combined with an appropriate pulse power 

system could, in principle, meet the specific power and specific energy requirements for 

passenger vehicles. It is unlikely, however, that such an arrangement could meet the 

requirements for most high-performance DOD or industrial platforms. 

Hydrogen has the property that, when combusted with oxygen, it produces only water 

thereby eliminating the CO2 associated with combusting hydrocarbon or alcohol fuels on 

vehicles. When combusted with air, it does produce nitrous oxides, but properly designed 

engines can solve this problem at the cost of producing engines that are somewhat larger 

than gasoline engines of the same power. The design of hydrogen-based internal 

combustion engines goes back to the early 1800s and can be considered to be a solved 

problem. Hydrogen internal combustion engines can most certainly be designed to meet 

civilian and military transportation requirements. The hydrogen could be supplied from a 

cryogenic or high-pressure tank or from reformed fuels. This approach is limited by the 

thermodynamic efficiencies of internal combustion and has the same fuel 

storage/conversion problems associated with the fuel cells mentioned above. It is not 

clear that hydrogen as a combustion fuel will prove to be satisfactory or competitive with 

other alternatives. The cryogenic and high-pressure requirements will be a great 

impediment to its adoption. This is especially true for DOD applications. 

There are, of course, special applications where hydrogen will be the preferred fuel. 

These include situations where the high gas velocities available from hydrogen are 

needed (e.g., hypersonic aircraft) or where fuel mass is more important than fuel volume 

(certain space applications). In general, however, it seems unlikely that hydrogen will 

prevail as a preferred general purpose or military fuel. This matter has been the subject of 

extensive debate and will be ultimately resolved by the marketplace. 

Regardless of how the debate works out, hydrogen will play an important role in the 

larger effort to develop economically viable and environmentally acceptable alternative 

fuels. This is simply because hydrogen is a very important ingredient for these fuels. 

However, in order to use hydrogen one must obtain it. In general, even though hydrogen 

is plentiful, it does not exist as a free entity but rather as part of chemical compounds 

(e.g., as a component of water, natural gas, and biomass). If one envisions using 

hydrogen as a fuel or in the manufacture of alternative fuels, it is important to gain some 

insight regarding the costs associated with producing hydrogen on a scale relevant to the 

U.S. transportation fuels problem. In this regard, it is helpful to examine the capital costs 

associated with producing an amount of hydrogen equivalent in energy content to that 

actually needed to power the U.S. transportation system (i.e., 2.4x106 BPD of oil 

equivalent, assuming 100% energy conversion efficiency). Hydrogen has an energy 

content of about 142 MJ/kg, while a barrel of oil has an energy content of about 6.1x103 
27

MJ. Thus, the hydrogen production corresponding to the actual energy needed to power 

the U.S. transportation is about 105 tons per day (TPD). The actual hydrogen needed 

would depend on the true energy conversion efficiency. For example, if hydrogen were 

used directly as a fuel and combusted in internal combustion engines with a net 

conversion efficiency of 18%, then 5.5x105 TPD of hydrogen would be required. If the 

hydrogen were used as a fuel to power PEM fuel cells with 80% conversion efficiencies 

coupled to electric motors with 90% efficiencies, then about 1.4x105 TPD would be 

needed. If hydrogen were employed in a process to synthesize some alternative fuel, then 

the amount needed would depend on that process. However, the amount needed would 

likely be appropriately measured in units of 105 TPD. We will, therefore, use that as the 

appropriate metric for the discussion regarding the production of hydrogen. 

There are several well-known methods for producing hydrogen that involve the 

commercially proven technologies of reforming gases, gasification, and electrolysis. A 

discussion of these technologies in the context of hydrogen production has been 

published by Simbeck and Chang.8

 Other promising approaches have been studied but 

have not been proved commercially viable. An example is the use of thermochemical 

cycles for splitting water to produce hydrogen.9

 

In order to gain some insight into the costs associated with the various schemes, table 7 

provides rough order of magnitude estimates (ROM) of the capital costs associated with 

the construction of hydrogen production capability using several of these technologies. 

The estimates are based on published data. 

The first three technologies (SM, BG, CG) are well understood, and the cost estimates 

are based on equipment that has been used commercially for many years. The SI-MHR, 

or Sulfur-Iodine (SI) cycle that uses heat from a modular helium reactor (MHR) for the 

necessary thermal energy, is a proposed system that has been well studied but for which 

the major components are under development. The electrolysis technology for the CE-NR 

system is well understood, but the unit cost used for the nuclear reactor is at the low end 

of estimates appearing in the current literature. Thus, the SI-MHR and CE-NR estimates 

are likely to be optimistic. It is clear from table 7 that by far the lowest capital costs for 

producing hydrogen are associated with steam reforming of methane (SMR). As a result, 

the SMR process produces most (95%) of the hydrogen used in the United States today. 

The production of CO2 is significant for several of the schemes shown in table 7. For 

example, hydrogen production by current industrial SMR processes produces about 9.5 

tons of CO2 for each ton of hydrogen. Hence, SMR production of 100,000 TPD hydrogen 

will result in about 950,000 TPD of CO2. Conventional coal gasification schemes 

produce about 20 tons of CO2 for each ton of hydrogen produced, resulting in 2x106 TPD 

of CO2 per 100,000 TPD of hydrogen. Biomass gasification is somewhat more 

complicated regarding CO2 production, because the carbon that is gasified to produce 

hydrogen originated in the atmosphere. In that sense, the process is CO2 neutral. There 

may, however, have been CO2 produced in the process of growing the biomass that would 

need to be taken into account regarding the CO2 balance. The SI-MHR and CE-NR 

schemes would produce no CO2. 
28

Hydrogen production 

technology 

ROM of capital costs for 

100,000 TPD capability of 

hydrogen production 

(billions of dollars) 

Basis of 

capital cost 

estimates 

Process 

Energy 

efficiency 

Steam reforming of 

methane (SMR) 

31 Mintz et al.10 70% 

Biomass gasification 

(BG) 

92 Spath et al.11 46% 

Coal gasification (CG) 94 Buchanan et 

al.12 

44% 

Sulfur Iodide Cycle 

powered by high 

temperature nuclear 

reactor (SI-MHR) 

194 Schultz et al.9 50% 

Conventional 

electrolysis of water 

powered by a nuclear 

reactor (CE-NR) 

360 Ivy for CE,13

$1500/KWe for 

NR 

25% 

Table 7. ROM of Capital Costs Associated With Producing Hydrogen Equivalent of the Energy 

Actually Needed to Power the U.S. Transportation System. 

If the matter of what to do with the CO2 produced by the above processes can be 

satisfactorily resolved, then the SMR process would likely remain the preferred means 

for producing hydrogen on a large scale, as long as methane gas is readily and 

economically available. The recent advances in the use of hydraulic fracture for the 

production of natural gas from shale may help in the near term. In the long term, 

exploitation of gas hydrates could become important to ensure the continuing supply of 

methane needed for SMR. If the CO2 disposal problem cannot be resolved, and large 

amounts of hydrogen are needed then biomass gasification, thermochemical cycles, 

electrolysis, or some other method of production will need to be considered. There will 

be feedstock issues (e.g., availability of required biomass, uranium, and water) that may 

limit the applicability of each of these approaches. Some of these issues will become 

apparent in the following sections. 

According to table 7, the capital costs for producing a quantity of hydrogen gas with 

the energy equivalent of 2.4 million barrels of oil per day are estimated to range from 

about 31 billion dollars (the SMR process) to about 360 billion dollars (the conventional 

electrolysis process using nuclear electric power). These costs do not include capital costs 

associated with feedstock acquisition and delivery, hydrogen liquefaction (if used), 

storage and distribution of the hydrogen or if necessary the disposition of the CO2

produced. 

The capital costs provide a sense of the scale of the undertaking and the funds that need 

to be invested or borrowed in order to proceed. They do not, however, translate directly 

into the cost of the produced product. The cost of the product produced depends on 
29

factors such as operating costs, feedstock prices, interest rates, payback time for the 

borrowed money, and tax rates. These factors can be quite variable and are difficult to 

project into the future with any degree of certainty. This paper will, therefore, not attempt 

to estimate product prices for fuels produced by different approaches. 

We now turn to discussion of several methods of producing alternative liquid 

transportation fuels. For most of the alternative fuels considered in sections 6–10, the 

production of hydrogen is a dominant cost. Moreover, in many cases the hydrogen 

production schemes discussed in this section are integral to alternative fuel synthesis. 
30

6. Liquid Transportation Fuels from 

Reforming and Gasification 

Today, the primary feedstock for transportation fuels is a natural resource, petroleum. 

One of the reasons for looking beyond petroleum is the growing concern regarding its 

future availability. It is widely believed that petroleum and other fossil fuels were created 

over millions of years from the oils (lipids) of plants and animals. This process was 

highly inefficient. For example, Dukes14 estimates that, at current consumption rates, one 

year’s worth of energy derived from fossil fuel required 1026 Joules of solar energy to 

produce the plant and animal life needed to make the fossil fuel. That corresponds to an 

energy efficiency of about 3x10-6. The practical consequence of this is that, today, 

petroleum is being extracted at a much faster rate than it is being created. As a result, 

petroleum will ultimately be depleted to the point where it is no longer a viable feedstock 

for fuels. There is general agreement that this will happen, but considerable disagreement 

as to when it will happen. Perhaps the most referenced work in this area is that of M. K. 

Hubbert, who in 1956 predicted that U.S. oil production would peak in 1970,15 and in 

1969 predicted that world oil production would peak in 2000. Hubbert’s prediction that 

U.S. oil production would peak in 1970 turned out to be correct. His prediction that world 

oil production would peak in 2000 does not appear to have been correct, and there 

remains considerable speculation as to when world oil production will peak. There is, 

however, a growing consensus that it would be prudent to look beyond conventional 

petroleum. 

Carbon-based transportation fuels (e.g., hydrocarbons and alcohols) have many 

attractive features. They also have the property that, when combusted with air or 

reformed, they produce CO2 as a byproduct. In most cases, the synthesis of carbon-based 

fuels will also produce CO2. In spite of this latter property, it is necessary to have an 

understanding of how one can synthesize hydrocarbon and alcohol fuels, because they are 

likely to remain the dominant transportation fuel. 

The hydrocarbons are just combinations of carbon and hydrogen, and the alcohols are 

combinations of carbon, hydrogen, and oxygen. The synthesis of carbon-based fuels is a 

mater of carbon chemistry about which a great deal is known. In order to undertake such 

chemistry one must have sufficient feedstocks of carbon, hydrogen, and oxygen. 

Hydrogen and oxygen are, of course, constituents of water and can be considered, in a 

global sense, to be in unlimited supply. 

Where do we get the carbon we need? Obvious sources of carbon are the earth’s 

hydrocarbon resources and the earth’s biomass resources. Some insights into the 

available hydrocarbon resources can be gained from figure 10. 
31

295 2343

420

837

18759

6246

conventional oil

unconventional oil

conventional natural gas

unconnventional natural gas

gas hydrates

coal

Source: H.H. Rogner “An Assessment of World Hydrocarbon Resources”, Annu. Rev. Energy Environ. 1997 22: 217-262

Figure 10. Assessment of World Hydrocarbon Resources (Gtoe). 

This figure summarizes the findings from a recent assessment of world hydrocarbon 

resources in units of Gtoe (109 tons of oil equivalent). It is clear that the current principle 

feedstock, conventional petroleum, represents a very small fraction of the earth’s 

potentially available hydrocarbon resources. If it were possible to access all the 

hydrocarbon resources indicated by figure 10, then, from a purely energy perspective, the 

energy needs of the earth could be met for thousands of years. There would, of course, be 

profound environmental considerations associated with such an undertaking. In reality, 

most of the hydrocarbon resources indicated by figure 10 will not be economically or 

technologically accessible. Nevertheless, if only a fraction of them can be harvested in a 

cost-effective and environmentally acceptable fashion, then the long-term prospects for 

satisfying the world’s transportation energy needs are quite promising. 

The unconventional oil indicated in figure 10 includes oil shale and tar sands. 

Unconventional natural gas includes coal bed methane, gas from fractured shale, and 

tight-formation gas. In this regard, it has been estimated that recent advances in the use of 

hydraulic fracture techniques for the extraction of gas from shale may increase the 

potentially available U.S. natural gas supply by about one-third.16 This results in a U.S. 

natural gas supply of about 100 years at current usage rates. Gas hydrates actually fall 

under the category of unconventional natural gas but have been separated out because of 

the unique chemical configuration in which they occur and the estimated size of the vast 

store of gas contained in this configuration. If one could economically and safely access 

the gas hydrates indicated in figure 10, then the methane derived would have the potential 

to provide natural gas for thousands of years. This could have a direct impact on 
32

transportation fuels, because natural gas can be straightforwardly employed to synthesize 

alcohol and hydrocarbon fuels. We will discuss this next. 

Liquid fuels via steam reforming of methane 

All of the hydrocarbon resources shown in figure 10 have the potential for being 

converted into transportation fuels (liquid or gaseous). Perhaps the simplest case for 

purposes of illustration to consider is the indirect conversion of natural gas into methanol. 

As background with regards to practicalities for this sub-section discussion: methanol 

has an effective octane of 119 compared to 87–93 for gasoline. This results in a higher 

auto ignition temperature for methanol. As a result, methanol internal combustion 

engines can operate with higher compression ratios than can gasoline engines. As noted 

earlier, the thermal efficiency of internal combustion engines increases as the 

compression ratio increases. In this regard, Brusstar et al.17 have operated a methanolpowered internal combustion engine with a compression ratio of 19.5:1 and demonstrated 

a thermal efficiency of greater than 40%. This exceeds the efficiencies of gasoline and 

diesel engines and also that of methanol-powered fuel cell engines. As compared with 

gasoline and diesel power, methanol internal combustion, depending on the achieved 

engine energy efficiency, would require more fuel due to its specific energy being about 

half that of gasoline. Gallon for gallon, methanol combustion produces about half the 

carbon dioxide of gasoline combustion. Hence, at equal engine energy efficiencies, it 

would produce about the same amount of carbon dioxide, because about twice as much 

methanol would need to be combusted. If the methanol engine energy efficiency were 

double that of the gasoline engine that it replaced, it would produce about half the carbon 

dioxide of gasoline combustion. On the basis of this, one could argue that methanol 

combusted in a high compression ratio engine could be a viable transportation fuel. 

We here describe the most common way to make methanol. The process begins with 

steam reforming of methane (SMR), where methane (CH4) is the principal constituent of 

natural gas. SMR is shown in table 7 to be the cheapest way to make hydrogen on a large 

scale. In an elementary sense, SMR proceeds according to the reaction 

4 2 2 CH + H O ⇔ CO + 3H . (4) 

This reaction requires a catalyst (usually nickel), and the steam is usually in the 800–

900 o

C range. 

If one desires to maximize the production of hydrogen, the water gas shift (WGS) 

reaction 

CO + H2O ⇔ CO2 + H2 (5) 

is also employed to yield the overall SMR reaction for the production of hydrogen 

4 2 2 2 CH + 2H O → CO + 4H . (6) 

At this point it is helpful to remember that mass is conserved in a chemical reaction. 

Thus, knowing the mass numbers of each element in a reaction allows a simple 

determination of the quantity of feedstock needed to produce a particular product. The 

mass number of hydrogen is 1, carbon is 12, and oxygen is 16. If one expresses mass in 

tons, then the SMR reaction says that 16 tons of methane combined with 36 tons of water 
33

(steam) produces 44 tons of carbon dioxide and 8 tons of hydrogen. Said another way, 

each ton of hydrogen desired will require 2 tons of methane and 4.5 tons of water and 

will produce 5.5 tons of carbon dioxide. So far we have neglected the fact that the steam 

must be heated to about C

0 800 in order for the reaction to proceed. The energy to do this 

is taken from the methane supply and consumes about 1.5 tons of methane and produces 

an additional 4 tons of carbon dioxide per ton of hydrogen. Thus, for each ton of 

hydrogen produced, the net methane consumption is about 3.5 tons, and the net carbon 

dioxide production is about 9.5 tons. This simple arithmetic allows one to estimate the 

SMR feedstock (methane and water) required and the carbon dioxide produced for a 

given amount of hydrogen. 

For simplicity, we introduce a simple “product” energy efficiency ηp where 

p

p

FS S

E

E E η =

+

 . (7) 

In this equation, Ep is the calorific content of the product produced, EFS is the 

calorific content of the feedstock consumed and ES is the calorific value of any 

supplemental energy that was supplied to the process. This efficiency measures only the 

energy of the fuel product produced relative to the energy that was required to produce it. 

It does not give credit to the value of byproducts of the process, such as cogeneration of 

electricity from waste heat or the calorific or sales value of chemical byproducts. While 

the energy and market value of the byproducts are important, the interest in this paper is 

the transportation fuel product of a synthesis process. We will use this simple product 

energy efficiency as a metric for comparing the various process considered. 

Hydrogen has a chemical energy content of about 142 MJ/kg, and methane has a 

chemical energy of about 55.5 MJ/kg. Since it takes 3.5 kg of methane to produce 1 kg of 

hydrogen, it follows that .73 η =p when SMR is used to produce hydrogen. In practice, 

the energy efficiency for SMR for hydrogen production is found to be between .6 and .7. 

Instead of producing hydrogen from SMR, one can produce methanol by sending the 

products of eq. (4) to a methanol synthesis reactor, which typically operates at a 

temperature of about 250 o

C and pressures of 50–100 atmospheres and employs a catalyst 

to favor the reaction 

CO + 2H2 → CH3OH . (8) 

The actual chemistries of SMR and methanol synthesis are somewhat more 

complicated than that shown above. However, for the purpose of this discussion, the 

simplified chemistry is adequate. In practice, the energy efficiency from methane to 

methanol is found to be about 60%. 

The capital cost for a methanol plant that implements the above chemistry is dominated 

by the capital costs for the methane reforming and syngas conditioning steps. These 

account for about 80% of the plant costs.18 One can, therefore, obtain a rough estimate of 

the capital cost for a methanol capability by estimating the capital cost for producing the 

needed hydrogen using SMR technology and increasing that estimate by 20%. For 
34

example, to do an in-kind replacement of the 13.4x106 BPD of petroleum used for 

transportation would require about 250 billion dollars of capital investment for a 

methanol output with an energy equivalent to the petroleum used by today’s U.S. 

transportation system. If one used a hydrogen production method other than SMR, the 

capital costs would depend on the scheme chosen. 

Various attempts have been made to eliminate the expensive reforming step in 

methanol production by developing processes that convert methane directly into 

methanol. However, after decades of work, direct methane conversion is not yet 

competitive with conventional processes. This is largely due to the fact that methane is a 

fairly chemically inert compound. Further, as with all carbon sources for fuels, the 

chemical properties of methanol need to be considered in evaluating its suitability as a 

fuel. For example: its low volatility can cause starting problems at cold temperatures, it 

can dissolve certain materials typically used as engine seals, it is corrosive to some 

metals, it is toxic and it is hydrophilic. These properties would need to be considered in 

assessing methanol as viable transportation fuel. Details of methanol’s physical and 

chemical properties and material safety data sheets can be accessed via 

http://cetiner.tripod.com/Properties.htm.

The SMR process can also be employed to make liquid transportation fuels other than 

methanol. One such approach utilizes the methanol process discussed above. There are 

well-established techniques for converting methanol to gasoline. In particular, in the 

1970s a process now called MTG (methanol to gasoline) was developed by Mobil Oil. 

Some insights into that process can be found in Meisel et al19. The details of the process 

are too complex to cover here. However, it is efficient at converting methanol to gasoline. 

The overall energy efficiency (including recycled heat) of the MTG process is about 

90%. Thus, the energy efficiency of the SMR through MTG process is about 54%. One of 

the problems that has been identified with this approach is that the gasoline product 

contains about 40% aromatic hydrocarbons (e.g., tolulene, xylenes, and 

trimethylbenzene), putting it in conflict with current environmental laws. It is 

problematic whether this process should be pursued as an alternative to petroleumderived gasoline. 

Liquid fuels from coal 

It was shown above in illustrative detail that methanol or gasoline can be made by 

using methane as a feedstock. In that case, the approach employed was to cause the 

methane to react with hot steam so as to produce a new gas consisting of carbon 

monoxide and hydrogen. This gas is referred to as “syngas.” The syngas was sent to a 

reactor that was designed to cause the carbon monoxide and hydrogen to react so as to 

produce methanol. Adding the MTG process step provides a pathway to gasoline. There 

are many other feedstocks that can be employed for liquid fuel synthesis. This section 

will discuss the use of coal as a feedstock for the production of liquid transportation fuels. 

The total recoverable coal in the United States is estimated to be 280 billion tons (EIA 

2003). At the present rate of consumption, this resource will last about 280 years. In light 

of the size of these reserves, it is reasonable to consider what would be required to utilize 

this resource as a feedstock for liquid transportation fuels. There are well-known 

processes that accomplish this. One approach that has been considered is to pyrolyze (i.e., 
35

heat in an inert atmosphere) the coal in order to drive off the volatile matter (tar, light 

oils, hydrogen, etc.) that might be amenable to distillation techniques for the production 

of liquid fuels. This process has been studied for years. It has been found that, because 

the volatile matter in coal is typically 20–40 percent, pyrolysis results in a large fraction 

of solid char, which is principally carbon. As a result, pyrolysis, while it has many uses, 

has not been heavily utilized for fuel synthesis, because fuel synthesis wishes to 

maximize the conversion of carbon into a hydrocarbon or alcohol fuel. 

A second scheme attempts direct liquefaction through hydrogenation of coal. In some 

sense this scheme can be viewed as replacing the inert atmosphere in pyrolysis with a 

hydrogen atmosphere that can react with carbon in coal to produce more distillable 

liquids and less char. Friedrich Bergius and his colleagues studied this approach during 

the period from about 1912 through WWI and found that they could obtain reaction 

products that were mostly distillable liquids. The process, however, was slow and 

required gas pressures up to 700 atmospheres to obtain a large fraction of distillable 

liquids. In 1931, Bergius received the Nobel Prize in chemistry for his work on chemical 

reactions under high pressure (this recognition included his work on direct coal 

liquefaction). The Bergius process for coal liquefaction was scaled to commercial 

production levels and contributed to the German war effort during WWII. This highpressure, direct liquefaction process probably has the highest carbon conversion 

efficiency of the various coal liquefaction schemes. However, the very high pressure 

needed to obtain large fractions of distillable liquids has discouraged widespread 

industrial application of this approach. 

A third scheme also developed in Germany in the 1920s by Franz Fischer and Hans 

Tropsch has become the method generally used to synthesize liquid fuels from coal. This 

method is called indirect liquefaction and is similar to SMR, in that it involves gasifying 

the coal to create a gas (called syngas) that is predominantly CO and H2. This gas is 

essentially the basis for producing hydrogen by coal gasification mentioned earlier. In the 

present case, a different synthesis route from that described above for SMR is followed. 

The syngas is purified and then used as the feedstock for a process known as FischerTropsch or FT synthesis. The FT process involves a complex catalyzed chemistry that 

produces a variety of products, including paraffins, olefins, alcohols, and carbon dioxide. 

While coal is primarily carbon, it is not a pure chemical compound but rather is a mix of 

substances, usually including carbon, hydrogen, oxygen, sulfur, and nitrogen. For 

example, for bituminous coal the average formula is CH.8O.1N.02S.02. A proper analysis of 

the FT process applied to coal would deal with all of its constituents. For simplicity, we 

will assume that coal is just carbon. The basic FT synthesis process proceeds according to 

the reactions 

nCO + 2nH2 → CnH2n + nH 2O , (9) 

nCO + (2n +1)H2 → Cn H2n+2 + nH2O . (10) 

The first reaction produces olefins, or alkenes, (CnH2n ), while the second reaction 

produces paraffins, or alkanes, (CnH2n+2 ). As an example, when n = 8, the reader will 

recognize the paraffin product as octane. The FT process always produces a mix of 

olefins and paraffins. However, the details of the mix depend on the reactor conditions 
36

and the catalyst used. The FT reactors are generally operated in a low temperature range 

of 200–240 C

o or a high temperature range of 300–350 Co . Low-temperature operation 

favors high molecular weight waxes, while high-temperature operation favors low 

molecular weight olefins. The route to diesel fuel is through the low-temperature process 

while the route to gasoline is the high-temperature process. In both cases, product 

upgrading is required. 

Since the FT process requires an input gas consisting of carbon monoxide and 

hydrogen, any process that provides such a gas is a potential candidate for creating the 

input gas. However, it can be seen from the governing chemical equations that maximum 

use of carbon in FT synthesis occurs when the input gas contains about two hydrogen 

molecules for each carbon monoxide molecule. Thus, a process like SMR, which creates 

a mixture of three hydrogen molecules for each carbon monoxide, is not, by itself, a good 

candidate for preparing the input gas for FT synthesis. Some modification of the SMR 

process, such as adding pure oxygen (autothermal reforming), would be desirable in order 

to use methane as the feedstock for FT synthesis. Such approaches have been 

considered.20 These methane conversion schemes can be expected to have thermal 

efficiencies similar to the 60% efficiency that is characteristic of SMR. 

 Other methods of syngas preparation for FT synthesis are well developed. One such 

approach is the gasification of coal. Because of their general importance in the field of 

synthetic fuels, we have included a brief discussion of coal gasification coupled to the FT 

synthesis process in appendix B. A more detailed discussion can be found in Probstein 

and Hicks.2

 The simple analysis presented in appendix B suggests that one ton of coal 

will produce two barrels of oil equivalent product. This is similar to the industrial 

experience. From this one can estimate the process energy efficiency. The calorific 

energy content of one ton of coal is about 2.8x1010 Joules, while the energy content of a 

barrel of oil is about 6.1x109 Joules. Since most of the energy for this process comes from 

the coal feedstock, one finds that the process energy efficiency of coal gasification 

coupled to FT synthesis will be about 44% for the liquid fuel product. There are, of 

course, other energy credits that can be given For example, FT is a very exothermic 

process, and perhaps a 7% energy credit is available from cogeneration of electrical 

power. Other products, such as heavy waxes, have potential value. However, our interest 

here is the process energy efficiency to the desired transportation fuel. That efficiency is 

about 44%. 

The combination of coal gasification and FT to produce liquid fuel is generally referred 

to as “coal to liquid” (CTL) conversion. The CTL process is well understood and could, 

in principle, be employed to provide for all U.S. transportation fuels. Such an undertaking 

would involve significant feedstock requirements and would also present significant 

carbon dioxide management issues. 

The feedstock issue is easily quantified. The current rate of coal production in the 

United States is about 109 tons per year. Most of this is used to provide the United States 

electrical generating capacity. Since U.S. electrical consumption is unlikely to decline, 

any effort to provide transportation fuel from coal will require coal in addition to that 

which is currently mined. The United States consumes about 5x109 barrels of oil per year 

for transportation purposes. At a conversion rate of two barrels of oil per ton of coal, total 

oil independence at today’s transportation fuel consumption would require that an 
37

additional 2.5x109 tons of coal be mined each year, resulting in annual coal consumption 

of 3.5x109 tons. Hence, if we were to provide for our current uses of coal and fill our 

current transportation-related petroleum needs by a conventional CTL process then the 

current coal reserves of 280 years would be reduced to about 80 years. A 1.4% annual 

growth in consumption would reduce that to about 50 years and a 5% growth would 

reduce it to about 30 years. While these estimates are only approximate, it is clear that the 

use of the conventional CTL process to resolve any significant fraction of the nation’s 

transportation fuel problem would have a profound effect on the nation’s coal resources 

in a relatively short time. Nevertheless, it is clear that CTL could, in principle, provide 

for U.S. transportation fuel needs for an extended period. This would roughly double the

CO2 production associated with transportation, because the CTL process itself produces 

about as much CO2 as does the combustion of the FT-produced liquid fuel. Since the CTL 

process is centralized, most of the CO2 produced by it could be captured. The captured 

CO2 could be converted to additional fuel by processes that will be discussed later. This 

would be expensive but would reduce the amount of coal that needed to be gasified. . 

Also, if permitted, the captured CO2 could be sequestered. In this regard, one should keep 

in mind that after about 80 years one would have sequestered about half the carbon in the 

U.S. coal supply in the form of gaseous CO2. 

It is logical to inquire whether modifications to the conventional CTL process could 

reduce its coal consumption. A significant amount of the coal consumption calculated 

above is driven by an inadequate supply of hydrogen in the feedstock for the FT process; 

see appendix B (the Gasification and Fischer-Tropsch Process). This situation could, in 

principle, be improved by injecting into the output of the coal gasifier an appropriate 

amount of supplemental hydrogen. The precise amount of hydrogen required depends on 

the detailed kinetics of the gasifier. The example discussed in appendix B indicates that 

the hydrogen available from gasification designed to optimize the production of hydrogen 

and carbon monoxide (the feedstocks for the FT process) is about 50% of what is needed 

for the optimum syngas for the FT process. As discussed in appendix B, some 

improvement in hydrogen production is obtained by using the gas water shift (WGS) 

reaction. This, however, is wasteful of carbon and has already been included in the 

analysis that leads to the estimate of two barrels of oil per ton of coal. If one eliminated 

the WGS step and instead injected a supplemental amount of hydrogen into the syngas 

that was equal to that being produced by the gasifier, then the resulting syngas would be 

ideal for the FT synthesizer. This step would reduce the coal requirement by about 33% 

for the same FT product, resulting in about three barrels of oil equivalent per ton of coal 

gasified. This rate of coal conversion leads to a CTL coal requirement of about 1.7x109 

tons per year and a total coal requirement of about 2.7x109 tons per year. At this rate, the 

lifespan of the current U.S. coal supply would be reduced to about 105 years, assuming 

no additional growth in use. This is 25 years longer than CTL without supplemental 

hydrogen. The price one pays for this coal supply lifetime extension is the need to 

provide about 5x105 TPD of supplemental hydrogen. This is about the amount of 

hydrogen that would be needed to provide for a hydrogen internal combustion engine 

solution to the entire transportation fuel problem. The supplemental hydrogen 

infrastructure would itself be a massive complex. 

It is straightforward to estimate the capital cost of the combined CTL and supplemental 

hydrogen infrastructure. Using National Mining Association estimates, one finds that a 
38

13.4x106 barrel per day conventional CTL capacity would cost about 900 billion dollars 

to construct.21 The provision of supplemental hydrogen should reduce the capital cost of 

the coal gasification component of that capability by about 300 billion dollars. The cost 

of hydrogen production for several different technologies is given in table 7. If one scales 

these hydrogen production capital costs to those associated with a 500,000 TPD 

capability, one can estimate the capital cost associated with CTL involving supplemental 

hydrogen. These estimates are given in table 8. 

Hydrogen production 

technology 

ROM of capital costs for 

500,000 TPD hydrogen 

production capability (billion 

dollars) 

ROM of capital cost of 

13.4x106 barrel per day CTL 

capability with supplemental 

hydrogen (billion dollars) 

Steam Reforming of Methane 

(SMR) 

157 757 

Biomass gasification (BG) 450 1050 

Coal Gasification (CG) 467 1067 

Nuclear reactor Sulfur –

Iodide Cycle (SI-MHR) 

967 1567 

Conventional Electrolysis 

Powered by Nuclear Reactor 

(CE-NR) 

1800 2400 

Table 8. Estimates of capital costs associated with providing supplemental hydrogen to a CTL 

capability and the capital costs of the resulting CTL capability when the CTL capacity is 13.4x106 

barrels per day. 

The third column in table 8 should be compared with the conventional CTL capital cost 

estimate of 900 billion dollars. Of the supplemental hydrogen production schemes 

considered, only the SMR scheme indicates a net reduction in CTL capital cost. The 

SMR supplemental hydrogen production would increase CO2 production by about 5x106 

TPD and methane consumption by about 1.3x106 TPD. This would roughly double the 

CO2 produced by the transportation sector and double the rate of consumption of natural 

gas. The use of coal gasification to produce the supplemental hydrogen makes no sense, 

because it would consume coal faster than CTL without supplemental hydrogen. The two 

nuclear schemes considered would increase the lifetime of the coal supply by perhaps 

25%, but would require a much larger capital investment than using an SMR approach to 

supplemental hydrogen or just using a conventional CTL approach without supplemental 

hydrogen. The gasification of biomass to produce the supplemental hydrogen would 

extend the lifetime of the coal supply by perhaps 25%, but would have higher capital 

costs than using SMR or just conventional CTL. It would also introduce the complexity 

of having to run two separate large gasification infrastructures. 

From the above discussion it would seem that the injection of supplemental hydrogen 

into the CTL process, while possible, would not be practical or cost effective. Another 
39

option to consider would be to perform the entire liquid fuel production using carbon 

neutral biomass gasification. We will consider that option next. 

Liquid Fuel via Biomass Gasification 

In the above two sub-sections we have considered methane and coal as sources of the 

syngas used for liquid fuel synthesis. These approaches were shown to be capable of 

providing for the full U.S. transportation fuel needs for significant periods of time. Such 

use would greatly increase the consumption of coal and natural gas, thereby reducing the 

lifetimes of those reserves. They would also have the side effect of producing large 

amounts of additional carbon dioxide. 

The synthesis of liquid fuels using the FT process requires a feedstock consisting of 

carbon monoxide and hydrogen. The preferred ratio of hydrogen molecules to carbon 

monoxide molecules in the feedstock is 2:1. The FT reactor does not care how the syngas 

is produced as long as it has been prepared so as to be free of impurities that might poison 

the FT catalysts and enters the reactor with the proper temperature, pressure and mixture. 

Therefore, biomass (e.g., hardwoods, softwoods, grasses, crop residues, etc.) gasification 

provides another potential option for the source of the FT feedstock. The use of biomass 

feedstocks, if done in a sustainable fashion, avoids much of the carbon dioxide 

management issue, because the carbon dioxide that is released during the production and 

use of these fuels comes from the atmosphere. Because of this, the biomass feedstock 

approach is said to be carbon neutral. This statement is true to the extent that fossil fuels 

are not used to grow and harvest the biomass. In this sub-section we will discuss the 

extent to which biomass gasification can address the transportation fuels problem. The 

combination of biomass gasification with FT synthesis is referred to as BTL. 

The chemical makeup of biomass has been well studied and catalogued (see for 

example http://www1.eere.energy.gov/biomass/feedstock_databases.html) Dry biomass is 

composed of cellulose, hemicellulose, lignin, protein, and ash. The fractions of these 

compounds vary with the type of biomass. However, on average, the composition is as 

follows: 

Compound Weight Percent 

Cellulose (45% carbon) 44 

Hemicellulose (48% carbon) 27 

Lignin (40% carbon) 20 

Other 9 

Total 100 

Table 9. Average chemical composition of dry biomass (hardwoods, softwoods, grasses, crop 

residue, etc.). 
40

From this table we see that, on average, carbon accounts for about 41% by mass of 

biomass. We can use the previous analysis of the CTL process to gain some 

understanding of the ability of biomass gasification to contribute to a solution of the 

transportation fuels problem. The most plentiful form of coal in the United States is 

bituminous coal, which has an average carbon content of about 70%. Thus, one can 

expect that the production of FT liquids from the gasification of biomass will require 

about 1.7 times the mass of coal needed for the equivalent liquid product production from 

the CTL approach. This results in a dry biomass requirement of about 4x109 tons per year 

to produce a FT product with energy content approximating that currently consumed in 

U.S. transportation fuel. A recent study by the Department of Energy and the Department 

of Agriculture concluded that about 1.4x109 tons per year of biomass could be recovered 

from U.S. forest resources and agricultural resources in a sustainable fashion without 

adversely impacting the forest and agriculture industries.22 This would be a significant 

undertaking and involve a “more than seven-fold increase in production from the amount 

of biomass currently consumed for bioenergy and biobased products.” One can conclude 

from this that an aggressive biomass gasification program could produce at most about 

one-third of the current U.S. transportation fuel requirement. While this is a crude 

estimate, it suggests that it will be difficult for biomass gasification alone to provide, on a 

sustainable basis, the liquid fuel equivalent of the 13.4x106 BPD of oil now used for the 

current U.S. transportation system. 

It should be noted that biomass gasification chemistry is somewhat different from coal 

gasification chemistry. This is because cellulose is the basic building block of biomass, 

resulting in a chemical structure based on the C6H10O5 complex. This is quite different 

from the average chemical formula for bituminous coal, CH.8O.1 . As a result, the output 

from the biomass gasifier includes significant water, methane, and tar. It is, therefore, 

necessary to include a reforming step that converts the methane and tar into carbon 

monoxide and hydrogen prior to entering the gas cleanup apparatus and the FT reactor. 

An example of how to perform this gasification and reforming has been reported by 

Spath et al.11 and is the basis for the capital costs quoted in table 6 for hydrogen 

production by biomass gasification. In that case, the gas that leaves the tar reformer has a 

hydrogen to carbon monoxide ratio of 2.03:1, which is about what is required for 

complete consumption of carbon monoxide in an FT reactor. Unlike CTL, where there is 

substantial experience regarding capital costs, there are no large commercial BTL plants 

from which one can scale BTL capital costs. However, it is known that about 70–75% of 

the capital costs in the production of syngas from gasification are associated with the 

syngas production, gas conditioning, and power generation, while 10–20% are associated 

with FT synthesis and product upgrading. If one assumes that a similar breakout of costs 

will occur for BTL systems, then one can utilize the analysis reported by Spath et al.11 to 

provide a rough estimate for the capital cost for a BTL facility that produces 13.4x106 

barrel per day of FT liquid product. We saw above that this will require about 4x109 TPY 

of dry biomass, or 1.1x107 TPD. The Spath et al.11 estimates for hydrogen production 

were based on a 2000 TPD biomass input to the gasifier. If we simply scale the Spath et 

al.11 capital cost estimate of 154 million dollars to the required biomass input, we obtain 

893 billion dollars, which is quite similar to the CTL estimate of 900billion dollarsfor the 

same quantity of FT liquid product. In reality, a BTL capital investment would likely be 
41

limited to about 300 billion dollars because of the limit on the availability of biomass that 

was mentioned above. As noted earlier, this capability would provide for about one-third 

of the needed fuel. 

It is straightforward to make a rough estimate of the BTL process energy efficiency. It 

takes about 1.7 tons of biomass to produce two barrels of oil equivalent liquid by the 

BTL process. A ton of dry biomass has a typical calorific value of about 1.5x1010 Joules, 

while a barrel of oil has a calorific value of about 6.1x109 Joules. These numbers suggest 

that the BTL process has an energy efficiency of about 47%. As expected, this is 

comparable to the process efficiency of 44% found for the CTL process. 

There are several other methods for producing transportation fuels from biomass. A 

method employing fermentation technology will be discussed in section 7. 
42

7. Enzymatic Approach to Producing 

Fuels from Biomass 

It was pointed out previously that the carbon in biomass is contained principally in 

carbohydrates and in lignin. The carbohydrates (cellulose, hemicellulose, and starch) are 

composed of sugars or polymers of sugars. Lignin is not a carbohydrate and is not 

amenable to the processes describe below. It has been known for millennia that certain 

sugars can be fermented (anaerobically decomposed into alcohols and carbon dioxide) in 

the presence of enzymes (complex proteins that are produced by cells and act as catalysts 

in specific biochemical reactions). The reduction of carbohydrates to these sugars is a key 

step in the production of alcohol fuels. Perhaps the best known example of such a fuel is 

ethanol synthesized from cornstarch. The basic process here involves the hydrolysis 

(decomposition by reaction with water) of cornstarch ( − − CH O 6 10 5 ) and the fermentation 

of the resulting Maltose (CHO 12 22 11 ) to produce ethanol 2 5 ( ) C H OH . The overall reaction 

can be written as 

6 10 5 2 2 5 2 2( ) 2 4 4 − −+ → + C H O H O C H OH CO . (11) 

It follows from eq. (11) that 57% of the corn starch is converted into ethanol. Since 

about 57% (by weight) of a bushel of corn kernels is starch, it follows that about 33% can 

be converted into ethanol. A typical bushel of corn kernels weighs about 56 lbs. Thus, a 

bushel of corn yields about 18.5 lbs, or 2.8 gal. of ethanol. The corn to ethanol process 

requires about 64% of the energy contained in the ethanol product.2

 This energy is 

typically provided by burning natural gas. The energy content of bone-dry corn is about 

14 MJ/kg. The energy content of methanol is about 30 MJ/kg. Thus, the simple energy 

efficiency of the corn to ethanol process is about 46%. The capital cost for a large corn 

ethanol plant is estimated to be about $1 per gallon per year. 

The ethanol equivalent of U.S. oil consumption for transportation is about 3x1011 

gallons per year. If corn-based ethanol were to provide this, it would require about 1011 

bushels of corn. The typical productivity of an acre of corn is about 130 bushels. Thus, 

the process described above would require about 109 acres of corn production to yield the 

ethanol energy equivalent of today's transportation fuel needs. This represents about forty 

percent of the landmass of the United States and exceeds the estimated arable land (4x108 

acres) available in the United States. Current annual corn production in the United States 

is about 1010 bushels. Most of that is used to feed livestock, poultry, fish, and people. 

These results indicate that enzymatic production of ethanol using only corn starch as a 

feedstock is not viable as an approach to provide for U.S. transportation fuel needs. If 

ethanol were to be the fuel of choice, then other feedstocks must be considered. 

Corn starch is a small fraction of U.S. biomass. It can be seen from table 8 that about 

71% by weight of biomass (plants, crops, trees, etc.) resides in cellulose and 

hemicellulose, both of which are polymers of sugars. If these polymers can be 

decomposed into sugars that are fermentable, then the basic process discussed above for 

the production of ethanol can be utilized. This opens up a broad array of crops beyond 
43

corn. Obvious candidates are grain crops, whose seeds, like corn, are high in starch and 

are easily hydrolyzed to fermentable sugars. Another obvious candidate is sugar crops, 

because the sucrose from these crops is easily hydrolyzed to fermentable sugars. After the 

seeds and sucrose have been removed from grain crops and sugar crops, considerable 

carbon remains in crop residue in the form of cellulose, hemicellulose, and lignin. There 

are also the lignocellulosic crops, such as grasses, shrubs, and trees. The lignocellulosic 

residues from crops and lignocellulosic crops have proved to be difficult as feedstocks for 

fermentation. However, recent developments in the areas of cellulases and xylases show 

promise for hydrolyzing the cellulose and hemicellulose found in biomass. Considerable 

work remains to be done to show that the required cellulases can be produced 

economically on a scale required for synthetic fuel production. However, if one assumes 

that the ongoing work will be successful, then the application to lignocellulosic biomass 

will follow a total reaction path similar to that shown in equation (11), but acting on the 

polysaccharides that make up cellulose and hemicellulose. As a result, 1 g of cellulose or 

one gram of hemicellulose will yield about 0.57 g of ethanol. Since cellulose plus 

hemicellulose constitute about 71% of the biomass, it follows that a ton of biomass could, 

in principle, produce about 0 .4 tons of ethanol. 

The process of cellulosic ethanol production is much more energy intensive than that 

for corn ethanol production, and the production plants will be much more expensive to 

build than are the corn ethanol plants. A plant design study was performed recently to 

compare the costs of building a lignocellulosic ethanol plant to for the costs of building a 

corn ethanol plant.23 The lignocellulose plant utilized a fluidized bed combustor fed by 

the lignocellulose feedstock to provide for the process energy requirements. The corn 

ethanol plant employed the much less expensive natural gas boiler to provide the process 

energy. A 50 million gallon per year lignocellulose plant was estimated to cost about 194 

million dollars. The same capacity corn ethanol plant was estimated to cost 48 million 

dollars. As noted earlier, the corn ethanol approach, while much less expensive, is not 

viable as a total solution, because there is insufficient landmass to grow the necessary 

corn. The lignocellulose plant was predicted to produce 79 gallons of ethanol per dry ton 

of lignocellulose feedstock. If one takes the biomass feedstock as having an energy 

content of 17 MJ/kg and ethanol as having an energy value of 80 MJ/gal one obtains a 

simple energy efficiency of about 41% for the lignocellulose plant. This is comparable to 

the simple energy efficiency calculated above for a typical corn ethanol plant. 

The information given above allows one to estimate the number of biomass acres 

needed to provide from lignocellulose the ethanol energy equivalent of today’s U.S. 

transportation fuel as a function of the lignocellulose biomass yield per acre. This 

estimate is plotted in figure 11. 
44

Figure 11. Biomass acres needed to provide the ethanol energy equivalent of 

today’s US transportation fuel from ligno-cellulose vs the ligno-cellulose biomass 

yield per acre.

0

0.5

1

1.5

2

2.5

3

0 10 20 30 40 50 60 70

Biomass yield (tons per acre per year)

Billions of acres needed

Total US land 

Total US forested 

land

Total US arable land

Mature forest new 

Sugar cane bagasse

Corn kernels plus 

stover plus cob 

Sw itch 

Miscanthus

The horizontal dashed lines in figure 11 indicate the total U.S. landmass, the total U.S. 

forested landmass, and total U.S. arable landmass. The vertical dashed lines indicate the 

annual new wood growth per acre added to a mature forest, the sugarcane bagasse yield 

per acre, the corn kernel plus stover (leaves and stalks) plus cob yield per acre, the switch 

grass yield per acre, and the miscanthus yield per acre. The intersection between these 

vertical lines and the solid curve provides an estimate of the number of acres needed for a 

particular feedstock. One can see from figure 11 that there is not enough new growth in 

mature forested lands to provide the wood to obtain sufficient ethanol from the U.S. 

forests. The acreage required for sugar cane bagasse or for corn, including kernels, 

stover, and cob, exceeds the total U.S. arable landmass. The perennial grasses, switch 

grass, and miscanthus require approximately the total arable landmass. These perennial 

grasses can grow on land that today would be considered marginal, thereby reducing the 

impact on food production. However, the biomass yield will likely decline on marginal 

land. It seems clear that a single crop to ethanol solution will have great difficulty in 

solving the full transportation fuel problem while at the same time providing for the 

critical traditional products from agricultural and forested lands. 

It was noted earlier that a DOE/USDA study concluded that, with some effort, about 

1.4 billion tons of biomass per year could be obtained from the forest and agriculture 

industries without adversely impacting the ability of those industries to meet their 
45

traditional and essential responsibilities.22 If cellulosic ethanol becomes a reality, then 1.4 

billion tons of biomass could produce about 360 million tons, or about 1011 gallons, per 

year of ethanol. This is about one-third of the ethanol required for a full solution to the 

transportation fuels problem. It is estimated that the capital cost of a large cellulosic 

ethanol plant would be about 4 dollars per gallon per year.23 This leads to a capital cost 

for converting 1.4 billion tons of biomass into cellulosic ethanol of about 400 billion 

dollars. This cost should be compared to the estimated capital cost of 300 billion dollars

for gasifying the same biomass and producing FT liquids with roughly the same energy 

content. Thus, within these rough estimates, the biomass to ethanol approach appears 

have capital costs that are about 30% higher than the BTL approach. The FT product 

from the BTL approach would likely be more compatible with the current gasoline and 

diesel infrastructures and with the FT fuels that would need to be produced from other 

feedstocks that would be needed to make up the two-thirds of the fuel that biomass could 

not produce in a sustainable fashion. 

A factor that we have not discussed involves the non-solar energy that must be invested 

to grow the biomass. If that energy must come from the biomass-produced fuel, then the 

energy content of the biomass fuel must be many multiples of the biomass-produced 

energy invested to grow the biomass in the first place, if the process is to be self 

sustaining. Also, if the non-solar energy needed to grow, prepare, and distribute the 

biomass comes from fossil fuels, then the overall process is not carbon neutral. These 

topics are beyond the scope of this paper but have been matters of some controversy in 

the bio-energy field for some time. 

A DOD-only solution using biomass requires only one 50th of the acreages shown in 

figure 11. In principle, a DOD solution could be accommodated with any of the biomass 

sources indicated in figure 11. However, the required landmasses are still large. For 

example, a corn kernel solution for DOD would require about 30 million acres. The entire 

U.S. corn production involves about 90 million acres, of which only about 4 million acres 

are currently dedicated to ethanol production. Even a DOD-only solution would have a 

large impact on the U.S. forestry and agriculture industries. 
46

8. Fuels from Biomass Oils 

In the above discussion we have discussed the topic of synthesizing fuels from 

biomass. There are also natural oils that occur in biomass (seeds, animal fats, etc.) that 

provide another potential approach to alternative transportation fuels. Fuels made from 

natural oils are generally referred to as biodiesel fuels. About 95% of biomass oils are 

triglycerides (three fatty acids plus glycerol). There exists a mature biorefinery industry 

that produces a large number of products (soaps, detergents, lubricants, solvents, etc.). 

The basic technology employed here is well developed. The process consists of a 

crushing step where the bio oil is separated from the feedstock (e.g., soy beans) and an oil 

conversion step that converts the triglycerides in the bio oil into biodiesel (methyl ester) 

and glycerine. In the oil conversion process, 1 kg of bio oil produces about .97 kg of 

biodiesel and .2 kg of glycerine and consumes about .1 gram of methanol. The 

predominant bio oil feedstock used in the United States is soybean. We will use soy 

beans as an illustrative example. 

Bio oil constitutes about 19% by weight of the soybean. Thus, a 1 kg bio oil input 

requires about 5.3 kg of soybean. The calorific energy content of soybean is about 18.7 

MJ/kg. The calorific energy of biodiesel is about 37 MJ/kg, and the calorific energy 

content of methanol is about 19.7 MJ/kg. A detailed study of the life cycle of biodiesel 

produced from soybean found that about 17% of the biodiesel product energy was 

required to be added in the crushing and conversion steps of the process.24 From these 

numbers one finds that the simple process-energy efficiency of the biodiesel process from 

soybean feedstock to biodiesel product is about 35%. 

The biodiesel lifecycle report mentioned above provides some data regarding the 

capital cost of constructing biodiesel plants. While there is considerable variability in the 

data, a capital cost of about $1 per gallon per year of biodiesel product is representative 

of the cited capital costs. Thus, if one were able to provide the bio oil feedstock needed to 

produce the 2x1011 gallons per year needed for a biodiesel solution to the national 

transportation fuels problem, the capital cost involved would be in the vicinity of $2x1011 

This is comparable to the capital cost estimated earlier for methanol solution using SMR. 

There are other plant and vegetable oils that can be used for feedstock for biodiesel 

production. Among these are corn oil, sunflower seed oil, peanut oil and palm oil. The 

biodiesel yields for these crops are well known and are listed in table 10. 

Oil Crop Biodiesel yield in gals/acre Annual MJ/acre 

Corn 14 1,746 

Soybean 40 4,988 

Peanut 90 11,223 

Avocado 225 28,0575 

Palm 500 62,350 

Table 10. Biodiesel yield from several bio oil crops. 
47

One could use table 10 to estimate the number of acres that would be needed by each 

of the various oil crops in order to satisfy the transportation fuel requirements. It is 

simpler to just compare the oil crop yields with the lignocellulose crop ethanol yields 

discussed above. These yields are summarized in table 11 for several lignocellulose 

crops. 

Lignocellulose Crop Ethanol yield in gals/acre Annual MJ/acre 

sugar cane bagasse 475 37,968 

lignocellulose corn 634 50,625 

switch grass 792 62,280 

miscanthus 1,426 114,000 

Table 11. Ethanol yield for several lignocellulose crops. 

The lignocellulose energy yields are seen to be comparable to or greater than the 

biodiesel crop yields. Therefore, from the point of view of solving the national 

transportation fuels problem, biodiesel approaches will face even more serious 

difficulties than those faced by ethanol approaches. This is further complicated by the 

fact that the high-yield biodiesel crops such as avocado and palm are very limited 

regarding where they can be grown. The NREL biomass oil analysis study mentioned 

above concluded that the ultimate supply potential for bio oil fuel is about 10 billion 

gallons per year. This represents about 5% of the U.S. transportation fuel need. The 

addition of biofuel from animal fats does not significantly change this result. Thus, while 

bio oils and biodiesel fuel may have important niche applications, they are not a solution 

to the national transportation fuel problem. 

There is one potential, although unlikely, exception to the bio oil conclusion. It has 

been conjectured that certain algae may produce bio oil yields greater than 10,000 gallons 

per acre. This projected yield derives from results obtained in the Department of Energy 

Aquatics Species Program (ASP), where algae strains were found having natural oil 

content as high as 60%.25 The ASP was initially motivated by the idea of using algae 

ponds as a way to sequester CO2 emissions from smokestacks. It was envisioned that CO2

would be separated from the stack gases and bubbled through a flowing algae pond, 

where it would be taken up by the algae. The experimental data indicated that certain 

algae strains were very good, under the proper circumstances, at converting CO2 and 

sunlight into oil. As a result, the ASP changed its thrust from that of CO2 sequestration to 

biodiesel production. If the projected yield were actually realizable on a large, 

sustainable, and economically viable scale, it would have a significant impact on the 

viability of biomass-derived fuels as a solution to the national transportation fuels 

problem. If successful, the landmass required to meet the national transportation fuel 

need would be about one percent of the U.S. landmass. 

The ASP project found that the conditions that promote high productivity and rapid 

algae growth and the conditions that induce high oil accumulation seem to be mutually 

exclusive. Therefore, the conjectured high yields were never achieved in the ASP. There 

is, however, some hope that genetic manipulation of promising algae strains might 
48

produce strains that are simultaneously capable of both high growth and high lipid (oil) 

synthesis. The new strains would also have to be able to maintain these properties in the 

demanding operational environments in which they would ultimately function. Research 

to achieve these goals is high risk, but, if it were successful, it could have a very large 

impact. The data needed to assess the efficiency and expected capital cost associated with 

this approach remains to be obtained. 
49

9. Synthetic Fuel from Atmospheric 

Carbon Dioxide 

Among the factors motivating interest in alternative transportation fuels is concern over 

the buildup of CO2 in the atmosphere. In this regard, an obvious approach to consider is 

the possibility of removing the CO2 from the atmosphere at the rate that transportation 

fuels are adding CO2 to the atmosphere and converting that CO2 into transportation fuel. 

This is similar to the biomass approach discussed in the previous sections, except that, in 

this case, the removal scheme for CO2 involves artificial filtration rather than photosynthesis. The extracted CO2 could be converted into a transportation fuel which, when 

consumed, would return the CO2 to the atmosphere. The cycle would, therefore, be CO2 

neutral, provided that the energy source needed to extract the CO2 and to make the 

synthetic fuel was not itself a CO2 producer. One approach for doing this was proposed 

by Stucki et al.26 This approach involves an absorption/desorption process in which a

K CO 2 3 (potassium carbonate) solution formed through CO2 absorption by KOH

(potassium hydroxide) is fed to an electrolyzer where CO2 and KOH are regenerated by 

the overall reaction 

2 23 2 2 2 42 2 4 2 H O K CO H O KOH CO + = ++ + . (12) 

The regenerated KOH is returned to absorb more CO2 , and the regenerated CO2 is 

converted into methanol through the mildly exothermic reaction 

22 3 2 CO H CH OH H O += + 3 . (13) 

Using experimental results, Stucki et al. designed a one-square-meter module 

consisting of an array of hollow fibers (240 mm inner diameter) through which a 0.5 

molar KOH solution would flow at 2 cm per second. The array of fibers provided an 

absorption membrane area of 18 square meters with a total fiber length of 23,000 m. The 

air was assumed to flow through the array at 3 m per second. The experimental data 

indicated that this array would remove 3.7 kg of CO2 per hour from an atmosphere 

containing 350 ppm of CO2. The air was predicted to undergo a 50% CO2 depletion as it 

passed through the array. An electrolysis cell would be used to regenerate the KOH and

CO2 according to reaction (12), and in the process would also generate one-third of the 

hydrogen needed for the methanol synthesis reaction (13). Additional hydrogen will be 

needed because, for maximum carbon consumption, reaction (13) requires three hydrogen 

molecules per CO2 molecule, while equation (12) generates only one hydrogen molecule 

per CO2 molecule. The electrolyzer that would regenerate the, CO2, KOH and also 

supply the needed hydrogen would require about 30 kilowatts of electrical power for the 

case studied by Stucki et al. 

A variation on this approach has recently been studied by Los Alamos National 

Laboratory (LANL). The LANL scheme, designated as “Green Freedom,” employs a 

K CO 2 3 solution to absorb CO2 to form potassium bicarbonate ( KHCO3 ) .27 Absorption of 

greater than 95% is claimed. The bicarbonate solution is then sent to an electrolyzer, 
50

where CO2 is regenerated along with one molecule of H2 for each molecule of CO2. The 

CO2 is then reacted with hydrogen to synthesize methanol according to equation (13). As 

with the Stucki scheme, supplemental hydrogen must be added to achieve the 

stoichiometric coefficient required by eq. (13). The methanol produced is then converted 

to gasoline by the Mobil MTG process mentioned earlier.19 

Since the Green Freedom results are recent, we will use them to estimate the energy 

efficiency of the synthesis of transportation fuel from atmospheric CO2. The Green 

Freedom program proposes to employ conventional electrolysis powered by nuclear 

reactors. Since the individual processes involved in Green Freedom are well understood, 

it is possible to make reasonably accurate estimates of the process efficiency and of the 

capital costs involved in building the production plants. The CO2 feedstock has no 

calorific value. However, it is found that the nuclear fuel must provide about 5.7 Joules of 

thermal energy for each Joule’s worth of gasoline produced. This leads to a simple 

process-energy efficiency of about 18%. This efficiency could be raised to perhaps 25% 

if more energy-efficient methods (e.g., SI thermal cycle or high-temperature electrolysis) 

for producing the supplemental hydrogen proved to be viable. The Green Freedom 

program estimated the nuclear reactor capital costs based on using the expected costs of 

the Westinghouse AP1000 third generation pressurized water reactor as the processenergy source. The other components are commercially available, and their capital costs 

are known. The total system capital cost was found to be about 290,000 dollars per barrel 

per day of oil equivalent product. This leads to an estimated capital cost of about 4 

trillion dollars for a capability equivalent to the 13.4x106 BPD currently used for 

transportation. About 58% of the capital cost is due to the nuclear reactor costs. The 

scheme would require about 1600 three-gigawatt thermal nuclear reactors. For reference, 

there are about 444 nuclear power reactors in operation around the world. 

Other proposals for converting CO2 into transportation fuels have been considered. For 

example, the CO2emitted from fossil-fired smokestacks has much higher density than 

atmospheric CO2, thereby simplifying CO2 extraction. While such an approach is not CO2

neutral, it could substantially reduce the net CO2 introduced into the atmosphere. Another 

approach that has been suggested is to extract carbon from the oceans, where the carbon 

content is much higher than in the atmosphere. This has been suggested as a potential 

approach for fuel synthesis at sea to support deployed naval forces. A brief discussion of 

this will be found in Coffey et al.7

 For these various approaches, as with the Stucki et al. 

and Green Freedom approaches discussed above, the regeneration of the CO2 upon 

extraction and the provision of the needed supplemental hydrogen for fuel synthesis will 

be energy intensive and have capital costs similar to those given above, because the same 

amount of CO2 must be regenerated, and the same amount of supplemental hydrogen 

must be provided. 
51

10. Exploitation of Oil Shale 

Production of liquids from oil shale appears on most lists of potential alternative 

transportation fuels. This is because there is a lot of oil shale. The most promising U.S. 

deposits are found in Wyoming, Utah, and Colorado. The most recent extensive 

assessment of the prospects for shale oil was published by the Office of Technology 

Assessment in 1980.28 This assessment is still quite relevant. 

While oil shale’s organic content is relatively low (about 20% that of coal), the World 

Energy Council (WEC) puts U.S. proved recoverable and estimated recoverable oil from 

shale to be about 6.5x1011 barrels.29 If this oil were recovered and used to meet the 

current annual U.S. petroleum requirement for transportation fuels, then the supply would 

last about 140 years. A 1.4% annual growth in demand would reduce that number to 

about 90 years, and a 5% annual growth in demand would reduce the time to depletion to 

about 50 years. These numbers indicate that oil shale is a significant potential source of 

transportation fuel. 

The approach to fuels from oil shale is qualitatively different from the approaches 

discussed in the previous sections. Most of the organic content of oil shale is found in a 

substance called kerogen. Kerogen is not a member of the petroleum family and is not 

soluble in conventional petroleum solvents. As a result, it is not recoverable by solvent 

extraction. The standard practice for recovering oil from oil shale is to mine the shale, 

move it to a retort, and pyrolyze it. This practice is referred to as “surface retorting.” The 

oil yield from this process has substantial variability, ranging from 10 gallons per ton to 

60 (or more) gallons per ton of mined shale. Yields greater than 25 gallons per ton are 

believed to be required for economically viable production of shale oil.25 If one assumes 

a yield of 30 gallons per ton, then it would be necessary to mine about 2.3x109 tons of oil 

shale per year to meet current U.S. petroleum needs. This is about the same as the 

estimate given earlier regarding the amount of coal that would need to be mined to meet 

U.S. petroleum needs through the CTL process. 

Since oil shale is predominantly inorganic, most of the mined material would have to 

be disposed of. The large volumes of shale needed to be mined and the need to dispose of 

a large waste stream have been major impediments to commercial exploitation of oil 

shale. This has led to several efforts to examine in situ retorting of the shale, where the 

shale would be pyrolyzed in place, thereby reducing the mining and waste disposal 

requirements. The basic idea is to drive out and condense the volatile components of the 

kerogen and extract the oils and gases by conventional petroleum retrieval schemes. One 

approach to this is to fracture the shale and combust the upper layer of the kerogencontaining shale, thereby forming a retorting and vaporization zone below the 

combustion zone. The vapor produced is condensed, and the resultant oil, water, and 

gases are pumped out. This process is more energy intensive than the surface retorting 

process but has the advantage of greatly reducing the waste disposal problem. It also 

raises considerable concerns regarding contamination of ground water. A variant of this 

scheme has been studied by Shell Oil corporation through its Mahogany Research 

Project.30 In this scheme, electric heaters are inserted into the shale and gradually heat a 

volume of shale to about 700 o

F. In order to keep the oil produced within a fixed volume, 
52

the ground surrounding this volume is frozen. Tests were recently completed (2004) by 

applying this scheme to a small volume (about 1200 square feet of surface area). About 

1700 barrels of light oils were recovered along with associated gases. Approximately 

one-third of the energy released was in the gases produced and two-thirds in the oil 

produced. This approach appears attractive, because it would seem to have a much lower 

environmental impact than the conventional techniques for recovering shale oil. Shell 

asserts that the process is less expensive than the conventional approaches for extracting 

shale oil. 

It is informative to estimate the capital investment that would need to be made to 

recover the shale oil. In 1980 it was estimated (OTA) that a 50,000 barrel per day oil 

shale facility using underground mining and surface retorting would involve a capital cost 

of about 1.7 billion dollars (1980 dollars). If one simply scales that cost by inflation, one 

arrives at an estimate of about one trillion dollars (2005 dollars) for a 13.4 million barrel 

per day capability from surface retorting. This compares with an estimate of 900 billion 

dollar for producing the same quantity of oil equivalent liquid using the CTL or BTL 

approaches. 

To the author’s knowledge, there is no estimate available for the in situ approaches. 

However, one can gain some insight into the capital costs associated with the Shell 

approach. If the Shell approach to in situ retorting utilizes electric heating, then 

substantial capital costs will be associated with meeting the electric power demands. One 

can gain some insight into those capital costs by examining the power demands. Shell 

asserts that the energy return on energy invested (EROEI) for their process is about three. 

Most of the energy invested (EI) is associated with the electrical power needed to heat the 

shale. The energy returned (ER) represents the energy in the extracted oil and gas. A 

barrel of oil contains about 6x109 Joules, and the United States consumes about 13.4x106 

barrels of oil per day for transportation purposes. If ER = 3EI, then these numbers imply 

that, in steady state, the energy invested per second would be about 3.4x1011 Watts. This 

is comparable to the average U.S. electric power consumption of about 5x1011 Watts. 

Considering the large amount of power needed and the remote locations of oil shale 

reserves, the Shell approach would likely require the construction of new generating 

capacity. If we assume that the power is supplied by power plants at a capital cost of 

$1,500/KWe, then the capital cost for providing the electrical generating capacity needed 

to heat the oil shale at the rate required to supply the current U.S. transportation demand 

would be about 500 billion dollars. This capital cost does not include the drilling and 

refrigeration capital costs. Thus, the 500 billion dollar cost estimate represents a lower 

bound on the actual capital cost. The further additional capital costs associated with oil 

and gas extraction should be similar to those that occur in traditional oil and gas 

extraction in the petroleum industry. 

The prospects for generating the power required by the Shell in situ approach present 

some interesting challenges. For example, coal currently provides about half of the U.S. 

electricity supply. Thus, if coal were used to generate the electricity for the Shell process 

it would require tripling the current rate of coal production in the United States. The 

impact on the U.S. coal supply would be comparable to that of the CTL approach 

discussed earlier. Also, the capital costs associated with the substantial increase in coal 
53

mining would need to be included in a proper capital cost estimate for an oil shale 

industry based on this approach. 

As another alternative, one could consider a nuclear reactor approach to generating the 

electricity. This would involve building about 300 one gigawatt electric power nuclear 

reactors. 

Another approach would be to make use of the gas that is generated by the in situ

process itself. Approximately one-third of the energy returned is contained in that gas. 

Thus, its energy content would be produced at a rate of about 3.4x1011 Watts. If that 

power could be converted into electricity with 50% efficiency, it could provide about half 

the required electricity. Since the capital cost to construct a natural gas power plant is 

about half that required to construct a coal fired plant, the partial production of electricity 

from the in situ-produced gas would result in about a 25% capital cost saving for the 

electricity generation. 

 It is interesting to note that the in situ-produced gas contains about the same energy as 

that required by the in situ process. If gas burners could be inserted into the shale and the 

retrieved in situ-produced gas could be pumped into those burners and combusted, it 

could, in principle, provide the energy needed to power the in situ process thereby 

eliminating the capital costs associated with electricity generation. However, this 

approach, while energetically attractive, would likely greatly complicate the Shell 

concept. It would also eliminate a potentially valuable/marketable product of the in situ

process. 

Shell states that the energy returned (ER) by its process (oil and gas) divided by the 

energy invested (EI) to obtain the energy returned is 3. This should not be confused with 

the process efficiency calculated for the other processes considered. That efficiency 

would be the energy in the oil obtained divided by the sum of the calorific value of the 

kerogen that was pyrolyzed (35 MJ/kg times the number of kg pyrolyzed) plus the energy 

invested to accomplish that pyrolysis. We do not know from the Shell number how much 

of the energy in the kerogen was captured. However, we can put an upper limit on the 

process efficiency by assuming that ER represents all of the energy in the kerogen. Since 

Shell states that one-third of ER was in the gas product, we will assume that two-thirds of 

ER is in the oil product. In that case, it is a simple matter to show that the process 

efficiency would be 50%. This represents an upper limit on the process efficiency, 

because it is unlikely that all of the original kerogen will be captured. For example, if half 

of the kerogen is captured then the process efficiency would be about 25%. More data is 

needed to assess the efficiency of the Shell process. 
54

11. Conclusion 

A review is undertaken of several approaches to producing alternative transportation 

fuels using feedstocks that are under the control of the United States. The objective of the 

review is to provide the non-specialist reader with a general understanding of the several 

approaches, how they compare regarding process energy efficiency, their individual 

abilities to provide for national transportation fuel needs, and their associated capital 

costs. 

 It was found that, for all the propulsion plants considered, the specific energy of the 

plant decreases as the specific power of the plant increases. Batteries and fuel cells were 

shown to have a rapid decline in specific energy as specific power increased. As a result, 

there has been a very limited overlap between battery and fuel cell power and energy 

characteristics and transportation vehicle mission requirements. In some cases, where the 

mission requires high power for only a small fraction of a vehicle’s mission, the 

introduction of an auxiliary pulse power system becomes viable. As a result, it is possible 

that battery and fuel cell technology combined with electric motors may progress to the 

point where this approach is viable for passenger vehicles where high power is typically 

required for less than 10% of a vehicle’s mission. This could be an important 

development, because passenger vehicles account for about half of U.S. oil consumption. 

However, for high-energy, high-power missions, batteries and fuel cells are 

disadvantaged relative to the internal combustion engines considered. It seems unlikely 

that the disadvantage can be overcome for high-performance DOD, commercial, and 

industrial missions involving transportation fuels. As a result, internal combustion 

propulsion plants will likely remain the plants of choice for these missions. 

The U.S. transportation sector consumes about 13.4 million barrels per day (BPD) of 

oil equivalent product. Consequently, this is the goal that was established for each 

alternative fuel process considered. The alternative fuel approaches considered include: 

hydrogen production, creation of synthesis gases from various feedstocks followed by a 

fuel synthesis process, enzymatic production of ethanol, the use of bio oils for biodiesel 

production, fuel synthesis using atmospheric carbon dioxide as a feedstock, and the 

exploitation of oil shale. 

A quick summary of the findings for the various approaches considered is found in 

table 12. This table provides rough estimates of the process efficiencies and capital costs 

associated with production of hydrogen and the liquid fuels considered at a scale needed 

to produce 13.4x106 BPD oil equivalent product. The table is ordered by increasing 

capital costs, except for oil shale, which is qualitatively different from the other entries. 
55

Process Process energy 

efficiency 

ROM of capital cost 

(billions of dollars) 

Comment 

SMR to hydrogen 70% 173 Commercial 

process,* doubles 

NG consumption 

Biodiesel 35% 200 Commercial 

process*** 

SMR to methanol 60% 250 Commercial 

process* 

SMR to gasoline via 

methanol 

54% 280 Commercial 

process* 

Corn ethanol 46% 370 Commercial 

process*** 

Hydrogen by 

biomass gasification 

46% 515 Commercial 

process** 

Hydrogen by coal 

gasification 

44% 525 Commercial 

process*, doubles 

coal consumption 

Coal to liquid 44% 900 Commercial 

process*, quadruples 

coal consumption 

Biomass to liquid 47% 900 commercial 

processes** 

Hydrogen by 

thermochemical 

50% 1,080 Process under 

development* 

Lignocellulose 

ethanol 

41% 1,467 Process under 

development** 

Hydrogen by 

conventional 

electrolysis 

25% 2,000 Commercial 

electrolyzer, 3’rd gen 

nuclear reactor* 

Atmospheric CO2 18% 4,000 Commercial 

processes + 3’rd gen 

nuclear reactor* 

Oil shale surface 

retort 

? 1,000 Involves massive 

mining and disposal 

Shell oil shale in situ

retort approach 

Less than 50% Greater than 500 electric power plant 

only* 

Table 12. Summary estimates of the process efficiencies and capital costs associated with 

production of hydrogen and several liquid fuels at a scale to produce 13.4x106 BPD oil equivalent 

product. 

Key: *not renewable but can, in principle, meet the BPD goal, **renewable but available 

feedstock cannot sustainably meet BPD goal, ***renewable but available feedstock cannot meet 

BPD goal ). 
56

Several of the processes shown in table 12 can be eliminated. For example, corn-based 

ethanol and biodiesel have been included simply to show where they fall in the 

hierarchies of efficiency and cost. In reality, while both fuels may have important niche 

roles to play, neither of them is a serious candidate for solving the national transportation 

fuels problem. The necessary feedstocks are simply not available. It is also suggested to 

set hydrogen aside, even though it has the lowest capital costs when produced by SMR 

techniques. It could be used as a fuel if it were absolutely necessary and could be 

produced in adequate quantity to meet national transportation fuel needs. If produced by 

nuclear or solar-powered thermochemical means or electrolysis it would produce no CO2. 

However, the logistical problems associated with the cryogenic systems or high-pressure 

systems required to employ hydrogen as a general purpose transportation fuel make its 

use as a general purpose transportation fuel or as a fuel for most DOD vehicles 

problematic. 

Among the remaining processes, the steam reforming of methane (SMR) processes are 

found to be the most energy efficient and to have the lowest capital costs. They can also 

produce a variety of different fuels, including hydrogen, alcohols, and hydrocarbons. 

Their use would double the consumption of natural gas and add substantially to CO2

production. With regard to the increased consumption of natural gas, recent advances in 

the extraction of gas from shale using hydraulic fracture and the vast reserves of gas 

hydrates may play a role. The advances in extraction by hydraulic fracture have been 

estimated to increases the potentially available natural gas reserves by one-third, resulting 

in a U.S. natural gas supply of about 100 years at current usage rates. If gas hydrates 

could be safely and economically obtained, they would potentially provide a large supply 

of methane, thereby allowing the manufacture of transportation fuels for generations. It 

was found that, while SMR processes could supply the needed transportation fuels for an 

extended period, a number of issues must be resolved before the SMR approach to 

alternative fuel production can be properly assessed. 

The next processes found to be most efficient and least capital intensive were the 

conversion of coal to liquid fuels (CTL) and the conversion of biomass to liquid (BTL) 

These process are considerably more costly than the SMR processes. Nevertheless, they 

can produce a variety of fuels, including hydrogen, alcohols, and hydrocarbons. Their use 

would have significant impact on the coal and biomass resources of the United States. 

The CTL process could supply the needed transportation fuels for an extended period. 

The BTL process could produce about 30% of the needed transportation fuel in a 

sustainable fashion. The BTL process would be carbon neutral provided that no fossil 

fuel was used in growing and harvesting the biomass or in the BTL process itself. A 

number of issues must be resolved before either the CTL or BTL approach to alternative 

fuel production can be properly assessed. 

The next process to appear in the efficiency and capital cost sorting is lignocellulosic 

ethanol production. This process attempts to break down the cellulose and hemicellulose 

in biomass into fermentable sugars. The process is still under development and is much 

more difficult and energy intensive than the well-developed corn ethanol process. 

However, if successful, it has the advantage that it can access a much larger feedstock 

than can the corn ethanol process. In order to function in a sustainable fashion, it would 

target the same 1.4 billion tons of biomass as does the BTL process. This amount of 
57

biomass used as feedstock for the lignocellulosic ethanol process would yield about 30% 

of the ethanol required for a full solution. The capital investment required is estimated to 

be about 500 billion dollars. The situation regarding carbon neutrality is the same as for 

the BTL approach. The process has yet to be demonstrated at a scale where its 

contribution to alternative fuels can be properly assessed. 

It was found that the fuel synthesis schemes with the lowest energy efficiency and the 

highest capital cost involve the use of atmospheric CO2 as a feedstock. In principle, the 

process should be capable of producing the quantities of fuel needed to solve the 

transportation fuel problem. For the case considered herein, this would require about 

1600 nuclear reactors, each providing a thermal power of about three gigawatts. The 

associated uranium consumption would be substantial and would deplete the reserves of 

high-grade uranium ore in a few decades. The long-term viability of such a process 

would likely involve the introduction of advanced reactors including breeder reactors. 

Similar approaches could be applied to converting smokestack CO2 to fuel, where the 

higher CO2 density would make the collection of CO2 easier. However, for the same 

amount of fuel the plant capital costs would be similar to that given above for fuel 

production from atmospheric CO2. There are clearly many issues that need to be resolved 

regarding this approach to alternative transportation fuels. 

The final topic considered was oil shale. It is estimated that U.S. oil shale formations 

could supply current U.S. fuel needs for more than 100 years. Studies done in the 1980s, 

when scaled to 2005 dollars, suggest that the capital costs associated with producing 

13.4x106 BPD of oil shale crude by surface retorting would be about one trillion dollars. 

Shell Oil has been studying an in situ retorting approach in which the heat needed to 

drive out the oil shale crude is provided by electric heaters placed within the shale 

deposits. It was shown that the electrical power system needed to provide the heat 

necessary to produce 13.4x106 BPD of oil shale crude would itself have a capital cost in 

excess of 500 billion dollars. There are many environmental concerns (e.g., ground water 

contamination) associated with producing oil shale crude. 

The above results suggest these conclusions about alternative fuels: 

• If necessary, the United States can manufacture the transportation fuels it 

needs. 

• The capital investments needed to manufacture fuels beyond petroleum will 

be substantial, regardless of the particular alternative fuel selected. In this 

regard, the SMR processes, because of their higher efficiencies and 

substantially lower capital costs, would seem to warrant special attention. Of 

course, the associated fuels are not carbon free or carbon neutral. 

• The capital investments associated with the manufacture of carbon free or 

carbon neutral fuels will be especially large. Associated with the latter point is 

the reality that serious investment in alternative fuels will be difficult to obtain 

as long as low-cost petroleum is available. 

• On the basis of national security needs, the DOD could argue to use 

appropriated funds to pay for the development of an alternative fuel to supply 

its 2% of national transportation fuel usage. Such an undertaking should be 
58

approached with great caution. If DOD selects a scheme that is not viable for 

the larger transportation system, then DOD will be left with a costly 

proprietary system, will be unable to benefit from competitive forces in the 

larger marketplace, and could find itself short of fuel in a time of national 

emergency. 

It is certainly not clear at this time which is the best alternative fuel approach 

for DOD and for the nation. It will likely take decades to sort this out. DOD 

should be a participant in a national effort to clarify the choices from a 

perspective of mission requirements, to ensure that these will be met, because it 

could be impacted substantially by the outcome. 
59

Appendix A 

A Simple Model for Vehicle Kinematics 

Figure A1 provides a simple illustration of how the energy flows through a typical land 

vehicle to provide the force needed to drive the vehicle. 

Figure A1. A Simplified Accounting of Energy Flow in a Typical Vehicle Powered by an 

Internal Combustion Engine. (Source: http ://www.fueleconomy.gov/feg/atv.shtml) 

It is obvious from figure A1 that the energy actually needed to accomplish the 

vehicle’s mission is a small fraction of the energy consumed by the vehicle. The power 

plant and its management are the principal reasons for this. If one could accomplish a 

significant improvement on the net energy conversion efficiency of the power plant it 

would have a great impact on the alternative fuels problem and the fuels problem in 

general. Furthermore, the ultimate energy and power needs are determined by a vehicle’s 

mission rather than the fuel or the power plant. Therefore, it is helpful to be able to make 

simple estimates regarding how mission requirements relate to fuel requirements. An 

examination of figure A1 suggests that the motion of the vehicle along a straight line can 

be described by the following simple differential equation:

FP FR FD FG dS

dV MV

dt

dV M = = − − − . (A1) 

Here M is the vehicle mass in kg, V is the vehicle speed in meters per second, t is the 

time in seconds, S is distance traveled in meters, FP is the propulsion force in Newton, 

FR is the rolling force, F D is the drag force, and FG is the component of the gravity 

force in the direction of motion. The rolling force can be expressed approximately as, 
60

FR = CRW , where CR is the rolling coefficient and W is the vehicle weight. The drag 

force can be written as 2/ 2 FD = CD ρAV , where CD is the drag coefficient, ρ is the 

fluid density, A is the appropriate area of the vehicle (frontal area for land vehicles, 

surface area for aircraft, wetted area for ships and submarines), and V is the velocity of 

the vehicle. The quantitiesCR , W , CD , and A are properties of the vehicle. For air 

vehicles, the drag force 2/ 2 FD = CD ρAV applies only at velocities where the parasitic 

drag dominates the induced drag. If we assume that the propulsion force is constant and 

the motion is along a straight line, then it is straightforward to show that the following 

simple relationship between the vehicle velocity and the distance traveled applies: 

⎥

⎦

⎤ ⎢

⎣

⎡ = − − − − Sc

S

MV (FP F G CRW )Sc 1 Ke

2

1 2 . (A2) 

Here, K is a constant that is determined by the initial conditions placed on V and S . 

The characteristic length Sc = M /CD ρA depends on the vehicle properties and the 

density of the fluid in which it moves. We will call the expression in square brackets the 

kinetic energy scaling factor. For simplicity, we will assume that K =1 (i.e., the velocity 

is zero when S = 0 ). For this case, the kinetic energy factor is plotted in figure A2. 

Kinetic Energy Scaling Factor

0

0.2

0.4

0.6

0.8

1

1.2

0123456

S/Sc

Scaling Factor

Figure A2. Kinetic energy scaling factor when K =1. 

Several things are evident from eq. (A1) and figure A2. First, for there to be any 

forward motion, the propulsion force must exceed the sum of the gravitational force and 

the rolling force. Second, for a fixed propulsion force, there is a maximum velocity that 
61

can be achieved. This maximum velocity is achieved when S is much greater than Sc . 

This region generally establishes the power required for constant velocity travel by land 

or by sea vehicles. A similar result holds for aircraft, but the calculation is more 

complicated due to the presence of induced drag. Finally, when S is much less than Sc , 

the kinetic energy is proportional to S . This is a region of constant acceleration. For land 

vehicles, this region usually establishes the size of the propulsion plant. 

In order to make use of eq. (A1), it is necessary to specify the various parameters on 

which the equation depends. For land vehicles, table A1 provides some approximate 

values for the parameters of several vehicles. The vehicles have been selected to cover 

the range from passenger vehicles to heavy armored vehicles. 

Vehicle Weight 

(lbs) 

Mass 

(kg) 

Available 

Horsepower 

CR

(asphalt 

surface) 

CD A (m/s) Sc

(m) 

FR (N)

Tesla 

Roadster 

2723 1237 288 .03 .35 2 1473 364 

Honda 

Accord 

3300 1500 270 .03 .35 2 1786 441 

Jeep 

Grand 

Cherokee 

4470 2032 195 .03 .45 2.8 1334 598 

Hummer 6600 3000 300 .03 .6 4 1041 883 

MRAP 38,000 17,000 400 .02 .8 12 1500 3,300 

Abrams 

Tank 

140,000 63,000 1500 .04 .8 12.4 5292 25,000 

Table A1. Approximate Values of Parameters Characterizing Several Land Vehicles. 

From table A1 and eq. A1, one can estimate the velocities at which the drag force 

becomes significant relative to the rolling force. Figure A3 provides the ratio of the drag 

force to the rolling force as a function of speed. 
62

It is clear from figure A3 that the rolling force dominates up to speeds of about 40 mph 

for all the vehicles considered. One must exceed 60 mph for the drag force to become 

dominant. For the Abrams tank, the rolling force dominates over all speeds of interest 

(the Abrams has a maximum governed speed of 42 mph). The rolling force results 

primarily from energy lost in deforming the materials in tires, treads, and the surface on 

which a vehicle travels. The results presented in figure A3 are for travel over an asphalt 

surface. The MRAP and the Abrams have about the same drag force, but the Abrams has 

a much larger rolling force. This is partly due to the larger weight of the Abrams, but it is 

also due to the lower value of CR for the rubber-wheeled MRAP as opposed to the 

tracked Abrams. Fuel consumption is related to the speed multiplied by the sum of the 

drag and rolling forces. One can conclude from figure A3 and table A1 that, for travel on 

hard surfaces, wheeled vehicles will consume less fuel per pound than will tracked 

vehicles. However, for travel on soft surfaces, such as sand, the value of CR increases 

much more rapidly for wheeled vehicles than for tracked vehicles, and fuel consumption 

should be lower for tracked vehicles. This points to the obvious reality that judging fuels 

and fuel consumption is very dependent on mission and whether one is engaging in 

peacetime operations or wartime operations. 

Table A1 indicates that the characteristic length Sc is measured in kilometers for the 

vehicles considered. In general, one wants to reach the upper speed range of a vehicle in 

distances less than Sc . The power that must be provided at velocity V is just VFP . When 

S << Sc , the kinetic energy factor is just S / Sc . The power that must be provided at 

velocity V is just VFP . It follows from eq. (A2) that, when S << Sc , the effective 

horsepower HPe needed to reach a velocity V in a time t is 
63

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = × + − F V

t

MV HPe R

2

3 1.34 10 . (A3) 

The factor in front of the square brackets is the conversion factor from Watts to 

horsepower. The effective energy Ee required to accomplish the acceleration is just 

[ ] ( ) Ee = MV + S FR + FG

2

2

1 , (A4) 

where S = Vt / 2 is the distance traveled during acceleration. The energy Ee is 

expressed in Joules. Equations (A3) and (A4) can be used to calculate HPe and Ee if V

and t are specified or to calculate t and Ee if V and HPe are specified. These 

calculations may be done with a hand calculator. 

It should be noted from eq. (A4) that the energy expended to overcome the rolling 

force is proportional tot . Hence, a shorter acceleration time results in less energy loss. 

However, the power given by eq. (A3) contains a term that is proportional to −1 t leading 

to the result that faster acceleration requires more power and hence a larger power plant 

in the vehicle. The tradeoff between these competing effects becomes significant for 

heavy military vehicles. 

If one applies eq. (A3) to the vehicles listed in table A1 and calculates the horsepower 

needed to accelerate these vehicles to 60 mph in 6 seconds and the time to accelerate to 

60 mph with the horsepower available to each vehicle, one obtains table A2. 

Vehicle Horsepower needed to go from 0 

to 60 mph in 6 seconds 

Time (s) to go from 0 to 60 mph 

with available horsepower 

Tesla 215 4.4 

Honda Accord 252 5.76 

Jeep GC 363 11.5 

Hummer 520 12.5 

MRAP 2,887 67 

Abrams 11,661 103 

Table A2. Horsepower needed to go from 0 to 60 mph in 6 seconds and time to reach 60 mph 

with available horsepower for acceleration over level ground. 

Only the Tesla Roadster and the Honda Accord have the horsepower required to travel 

from 0 to 60 mph in 6 seconds. The other vehicles are underpowered to meet this 

objective. The third column in table A2 provides an estimate of the time it would take to 

reach 60 mph with the horsepower available to the various vehicles “as-built.” As 

mentioned above, the Abrams tank, while it has the horsepower to reach 60 mph, is not 

permitted to travel faster than 42 mph. 
64

When S / Sc >> 1, It is evident from fig A2 that the kinetic energy, and hence the 

velocity, reaches a constant value independent of distance. This region determines the 

horsepower needed to maintain a constant speed. In this case the horsepower can be 

written as 

⎥

⎦

⎤ ⎢

⎣

⎡ = × + + − F C W V

S

MV HP G R

c

e ( ) 2

1 1.34 10

3

3 . (A5) 

Fig A4 plots the fraction of the available horsepower needed to maintain speed versus 

the speed for the several vehicles listed in table A1. 

Figure A4. Fraction of Available Horsepower Needed to Maintain Speed vs Speed (mph) 

for Several Vehicles

0

0.2

0.4

0.6

0.8

1

1.2

0 20 40 60 80 100 120

Speed (mph)

Fraction 

Tesla

Honda Accord

Jeep GC

Hummer

MRAP

Abrams

It is clear from figure A4 that, with the exception of the MRAP, the horsepower 

available to each vehicle is larger than that needed to maintain a particular speed. Since 

the MRAP has a maximum speed requirement of about 70 mph, the full horsepower is 

required to maintain that speed. For most vehicles, the engines are oversized for the 

cruising requirement. For example, the average speed traveled by private automobiles is 

about 45 mph. At that cruising speed, the Honda Accord uses about 6% of its available 

horsepower. The power plants for these vehicles are set by the acceleration requirements 

expressed through eq. (A3) and not by the cruising speed requirements. 

Equation A1 can shed some light on the energy and power requirements associated 

with seagoing vehicles. To illustrate, we will consider surface vessels with displacement 

hulls. In this case, the rolling force is zero and, for our purposes, the gravity force can be 

taken as zero. The density that enters the characteristic length is 1000 ρ = , and the area 

A is the wetted area of the vessel. For analytical simplicity we will use a formula for A

developed by David Taylor: 

2

1

A = 2.6(ΔL) . (A6) 
65

Here Δis the ship displacement in tons and L is the ship waterline length in meters. 

The length L will be taken as 85% of the ship length. The Taylor formula is limited in 

accuracy but will suffice for the estimates desired here. It would be helpful to have a 

simple analytical relationship between ship length l and its displacement Δ. In this 

regard, an examination of the displacement and length data for a variety of cargo ships 

and fast ships finds that the data is well encompassed by two curves of the form 

3 Δ = αl . (A7) 

The choice α = .0098 is representative of the larger cargo ships. The choiceα = .002

is representative of the fast ships, such as combatants and fast cruise ships. We will refer 

to these as fast ships. If we use this relationship between Δand l , then the Taylor 

formula becomes 

2 2 1

A = 2.4α l . (A8) 

.The drag force becomes 

6

1

3

2

FD = 12000CD Δ /α . (A9) 

For cargo ships we will set 3 4 10− CD = × . This value is taken from Lin et al.3

 The 

effective horsepower needed to maintain a ship at speed V is just the product of Fd and 

V . Using this data, figure 4 provides estimates for the required effective horsepower vs. 

desired maximum speed for cargo ships in the length range 150–400 meters 

As a point of comparison, the VLCC tanker Frank A Shrontz with a length of about 

330 meters and a cruising speed of 16 knots has a power plant of about 34,000 

horsepower. This is in reasonable agreement with the predicted value obtained from 

figure 4 and suggests that the power plants chosen for cargo ships are selected to be close 

to the power needed to maintain a desired cruising speed. Similar calculations can be 

done for fast ships when the appropriate values of the drag coefficient and wetted surface 

areas are known. 
66

Appendix B 

The Gasification and Fischer-Tropsch Processes 

For the purpose of illustration, this appendix considers a specific example of a FischerTropsch reactor fed by a coal gasifier. The basic FT synthesis process proceeds according 

to the reactions 

nCO + 2nH2 → CnH2n + nH 2O (B1) 

nCO + (2n +1)H2 → Cn H2n+2 + nH2O (B2) 

The first reaction produces olefins, or alkenes, (CnH2n ) while the second reaction 

produces paraffins, or alkanes, (CnH2n+2 ). As an example, when n = 8, the reader will 

recognize the paraffin product as octane. The FT process always produces a mix of 

olefins and paraffins. However, the details of the mix depend on the reactor conditions 

and the catalyst used. The FT reactors are generally operated in a low temperature range 

of 200–240 C

o or a high temperature range of 300–350 Co . Low-temperature operation 

favors high molecular weight waxes, while high-temperature operation favors low 

molecular weight olefins. The route to diesel fuel is through the low-temperature process, 

while the route to gasoline is the high-temperature process. In both cases, product 

upgrading is required. 

A typical source of the carbon monoxide (CO) and hydrogen needed by the FT reactor 

is a gasifier. Because of the central roles that gasification and Fischer-Tropsch chemistry 

play in the study of alternative fuels, this topic is discussed here in somewhat more detail 

than others in this paper. The discussion will still be elementary. A more thorough 

discussion of gasification can be found in Probstein and Hicks.2 

For this example, consider a gasifier that can produce a syngas with a H2/CO ratio of 

2:1, which it achieves by converting a substantial fraction of the available CO to CO2. 

Although the ratio of 2:1 is necessary for the olefins FT process, this greatly reduces the 

total quantity of CO in the feedstock. There is, therefore, a tradeoff between achieving 

the desired ratio and the absolute amount of CO available for the FT process. To the 

extent that the H2/CO ratio is less than 2:1 it will be necessary either to burn additional 

coal or to provide supplemental hydrogen in order to produce the needed quantity of 

desired product. 

The actual amount of CO and hydrogen available is determined by the chemical 

kinetics that occur in the gasifier. For the application considered here, a gasifier works by 

combusting a fraction of the available carbon and using the released energy to raise and 

heat steam and carbon to a temperature where the production of CO and H2 is optimized. 

In this regard, a temperature of 1000 o

K is appropriate. In figure B1 we provide an 

oversimplified illustration based on equilibrium chemistry for the case where one mole 

(12 grams) of carbon is gasified using .25 mole (8 grams) of oxygen and 1 mole (18 

grams) of water. 
67

Figure B1. Mass flowchart (units in moles) from the gasifier through the water-gas 

shifter. 

For the moment, we will consider only streams 1, 2 and 3 of figure B1. The 

combustion of .25 mole of carbon with .25 mole of oxygen produces 98.6 KJ of heat 

energy. This is adequate to raise and heat the 1 mole of steam and the remaining .75 mole 

of carbon to 1000 o

K. In this particular example, the gasification reactions that lead to 

stream 3 will not greatly alter the energy balance. In general, if the gasification reactions 

lead to an energy deficit regarding maintaining the desired temperature, then additional 

energy would have to be added. Similarly, if the gasification reactions produced energy 

excess to maintaining the desired temperature, then energy would have to be removed. 

Excess energy could, in principle, be reused, for example, to raise steam or to generate 

electricity. 

The gasifier outlet stream 3 contains only half the hydrogen needed to satisfy equations 

(B1) and (B2). This means that only one half of the carbon in stream 3 can be converted 

via the FT process. This is very wasteful in the use of carbon (e.g. coal). Some 

improvement can be made by introducing an additional step that employs the water-gas 

shift reaction 

CO + H2 O = CO2 + H2 (-41.2 kJ/mol) (B3). 

Figure B1 illustrates the use of the shift reaction by separating stream 3 into stream 4 

and stream 5. Stream 4 contains all of the hydrogen from the gasifier and half the carbon 

monoxide. The remaining carbon monoxide and sufficient steam is separated into stream 

5 such that the output of the shift reactor (stream 6) will contain the proper ratio of 

hydrogen to carbon monoxide. The catalyst in the shift reactor works best at 623 o

K. This 

requires that heat (15.5 KJ) be removed from stream 5. Since the shift reaction is 

exothermic, heat (9.6 KJ) must also be removed from the shift reactor in order to 

maintain its temperature. The excess heat from stream 5 and from the shift reactor can, in 

principle, be reused. 

gasifier

H20 = 1

02 =. 25

298o K

2

298o K

1

C = 1.0 mole

3

CO = .7

 H2 = .7

CO2 = .3

 H2

0 = .3

1000o K

CO = .35

 H2 = .7

CO2 = .3

 H20 = .07

1000o K

4

shift

5

CO = .35

 H2

0 = .233

1000o K

Remove Heat

15.52 KJ

623o K

CO = .117

 CO2

 = .233

H2 = .233

623o K

6

Remove Heat

9.6 KJ
68

If one separates out and combines the carbon monoxide and hydrogen in streams 4 and 

6, one is left with a combined stream containing .933 mole of hydrogen and .467 mole of 

carbon monoxide. This approximately satisfies equation 2. Therefore, the gasifier-shifter 

arrangement shown in figure B1 would provide 47% of the carbon that entered the 

gasifier to the FT synthesis unit. Figure B2 provides an oversimplified mass flow chart 

beginning with the combined stream (stream 7) through the FT reactor. 

Figure B2. Mass flow chart (flow units in moles) from the water-gas shifter through the FT 

reactor. 

The FT reactor prefers to operate at a temperature of 648 oK. This requires that 3.86 kJ 

of heat be removed from stream 7. Furthermore, the FT reaction is exothermic. In order 

to maintain the FT reactor temperature at 648 o

K it is necessary to remove 77 kJ of heat 

from the reactor. The FT reactor is the largest source of excess heat in the example 

considered here. 

The FT reactor generally produces a mixture of compounds. The liquid fuel fraction 

has a maximum selectivity of about 50%. At this selectivity, about 25% of the carbon that 

entered the gasifier would exit the FT synthesis unit as gasoline or diesel. This implies 

that one ton of carbon (coal) produces about .29 tons, or 2 barrels, of oil equivalent 

liquid. This is in agreement with industrial experience with the coal to liquid (CTL) 

process Therefore, about 2.2x10 9 tons/year of coal would be needed to provide the liquid 

fuel to replace conventional petroleum using the CTL process. From an energy efficiency 

perspective, it should be noted that one ton of coal has a calorific value of about 28 GJ 

while two barrels of gasoline have a calorific value of about 12.2 GJ. This results in a net 

calorific efficiency of about 44% for the CTL process. There is the potential to improve 

this efficiency by utilizing some of the waste heat that is evident in figures B1 and B2. 

The excess heat identified in these figures is about 130 kJ. If 50% of this energy could be 

Remove Heat

3.9 KJ

T = 906o K

T = 648o K FT Products

H20 = .467

T = 648o K

Remove

Heat

77 KJ

Cool and Condense

Steam

23.6 KJ

9

7

CO = .467

 H2 = .933

Fischer-Tropsch Reactor

T = 648o K

8 10
69

recovered and used to generate electricity, then the net calorific efficiency would rise to 

about 57%. 

One can gain some understanding of the total power flow that would be involved in a 

CTL solution of the national transportation fuels problem by scaling from the 12 grams of 

carbon used in the example above to the needed 2.2x109 tons/year (6.3x107 gm/sec). In 

this case, the thermal power associated with carbon combustion is 5.2x1011 Watts. This 

corresponds to 170 3GWth coal gasifiers. The thermal power associated with the waste 

heat identified in this simple example would be about 7x1011 Watts. Since the average 

U.S. electrical power usage is about 5x1011 Watts, there would be a high priority placed 

on making use of the waste heat from CTL plants associated with a solution to the 

national transportation fuels problem. 
70

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1980, available at: http://www.gwpc.org/e-library/documents/general/ 

An%20Assessment%20of%20Oil%20Shale%20Technologies.pdf. 

29. “Survey of Energy Resources: Oil Shale,” World Energy Council, December 2000, 

available at: http://www.energybulletin.net/print/5600. 

30. Shell Oil Technology In situ Conversion Process, information available at: 

http://www.shell.us/home/content/usa/aboutshell/projects_locations/mahogany/ 

technology/