In This Issue
Engineering Challenges
September 1, 1999 Volume 29 Issue 3

Alternative Pathways to a Carbon-Emission-Free Energy System

Wednesday, December 3, 2008

Author: Henry R. Linden

There has developed a broad consensus that energy systems will move towards electricity for all stationary energy uses, and to hydrogen (compressed, adsorbed, or liquefied) for transportation fuel.

Over the past several decades there have been drastic changes in the perception of the forces driving the evolution of the global energy system. Technological advances and increased efficiency have calmed fears of large price increases and early exhaustion of the most desirable fossil fuels--oil and natural gas. In fact, during 1998, oil prices in deflated terms dropped to a 50-year low. Natural gas, although not nearly as fungible as oil, has become a widely traded commodity because of the growing importance of liquefied natural gas and the use of transnational pipelines to provide clean and competitively priced energy in areas without indigenous gas resources. In the United States, composite spot wellhead prices of natural gas have generally remained below $2/million Btu ($11.60/barrel crude oil equivalent) since 1987, and are expected to rise to only $2.61/million Btu in constant 1997 dollars by 2020 (Energy Information Administration, 1998). The prophets of doom, who predict early peaking of global crude oil and natural gas capacity on the basis of outdated theories, will again prove to be wrong, as they often have in the past (Laherrere, 1999; Linden, 1998). Coal, because of its much greater abundance than oil and natural gas, is not subject to fears of long-term supply problems. However, in a world increasingly concerned with environmental quality, coal is under growing market pressure, and this has further driven down its current and projected costs relative to other primary energy sources.

It has long been expected that the global energy system will continue to evolve in historical cycles, as it has from a primary reliance on wood, then on coal, and now on oil, to some time during the twenty-first century on natural gas, followed by a yet uncertain mix of renewable energy sources and nuclear power. The growing global abundance of natural gas, its desirable environmental qualities, and the relative ease and efficiency of its conversion to electricity have made it the logical transition fuel to a sustainable energy system, and bode well for its capturing the largest share of the primary energy market during the next 50 years or so. However, in recent years, a new consideration has become dominant in shaping the future of the global energy mix. It is the realization that it is probably unwise to liberate a major share of the roughly 5,000 billion metric tons (gigatonnes) of carbon in the technically recoverable fossil fuels in the form of carbon dioxide (CO2) because of the potential impact on climate. Thus, there is now a great impetus to move as quickly as possible to a global energy system that is free of carbon emissions.

As noted before, it has been anticipated that technological advances would make fossil fuels obsolete by the end of the twenty-first century, just as coal made fuel wood in the middle of the nineteenth century. In fact, even during the late 1960s and early 1970s, the Institute of Gas Technology developed the concept of a "hydrogen economy" in which nonfossil sources of hydrogen would eventually replace natural gas (Linden, 1971). Now, hydrogen is again considered to be the key to a sustainable energy future. The major U.S. automobile manufacturers have already made a commitment to its use in propulsion systems with triple the efficiency of conventional internal-combustion engines.

Over the longer term, hydrogen is considered the ideal energy storage medium for intermittent renewable energy sources such as photovoltaic and wind power, and could possibly be an alternative to electricity as an energy carrier. However, earlier enthusiasm for hydrogen as a direct source for stationary energy applications has now diminished because of its high cost of transmission and distribution, and potential technical and safety problems in its utilization as a substitute for natural gas. Instead, there has developed a broad consensus that energy systems will move towards electricity for all stationary energy uses, and to hydrogen (compressed, adsorbed, or liquefied) for transportation fuel. In recent years, the debate over the likely endpoint of this evolution has been mostly about the relative roles of nuclear power and the various renewable sources of power (solar, wind, hydropower, biomass, etc.). Also, among the renewables, there has been debate over the relative roles of biomass and energy crops in general, with specific concerns about excessive land requirements and environmental impacts.

A Change in Thinking
Now, another drastic change in thinking has occurred among some of today’s most prominent advocates of the hydrogen economy. The new thinking accepts the use of electricity and hydrogen but plans to obtain the hydrogen from fossil fuel reforming or gasification and then separate and sequester the CO2 formed in these processes (Hileman, 1997). In these well-known processes, fossil fuels are converted with oxygen and/or steam into mixtures of hydrogen, carbon monoxide (CO) and CO2, and the CO is then further converted with steam into more hydrogen and CO2. In carbon sequestration, the resulting CO2 is captured and stored in geological formations or the deep ocean. These techniques raise many new issues regarding the most cost-effective and socially least disruptive pathway to sustainability. For example, what should determine the relative amounts of research, development, and demonstration (RD&D) investments in the various renewable power sources, in the emerging resources of natural gas, and in fossil fuel reforming/gasification with carbon sequestration?

As noted before, the die is already cast in respect to surface transport shifting to more efficient electromotive propulsion. It appears that most vehicles will eventually be powered with hydrogen stored on board and converted to electricity with air in proton exchange membrane (PEM) fuel cells, used in tandem with advanced batteries for startup, peak power, and the capture of braking energy. Only inadequate global supplies of platinum, used as a catalyst in PEM fuel cells, are likely to constrain this option (Appleby, 1999). Hydrogen produced on board by reforming of gasoline or methanol is unlikely to prove practical because of operational and economic disadvantages (Thomas, 1998). This option was always based on a misperception of the cost of creating a hydrogen refueling infrastructure. Hydrogen "filling stations" do not depend on a transmission and distribution network similar to that for natural gas, but can be dispersed systems, initially using natural gas steam reformers for hydrogen production, but soon using PEM water electrolyzers to split water into hydrogen and oxygen. Eventually, electrolyzers will be powered with solar (photovoltaic) energy, but in the interim could be powered by cheap off-peak power.

PEM electrolyzers produce chemically pure hydrogen, thereby avoiding fuel cell anode poisoning problems. They also reduce compression costs because they are capable of delivering hydrogen at pressures as high as 2,000 pounds per square inch. Admittedly, in areas where most of the off-peak power is generated from coal or other fossil fuels in steam-electric plants, the power required to produce hydrogen for surface transportation fuel would increase greenhouse gas emissions compared to other propulsion options (Thomas, 1997). However, hydrogen produced by natural gas reforming does not have this disadvantage. In any event, this will be a temporary problem. Over the next 20-30 years, highly efficient combined-cycle turbine systems, fired by natural gas, will replace current fossil fuel systems. They emit only one-third as much CO2, and cost only one-third as much, as today’s coal-fired steam-electric plants. Also, by then, photovoltaic power modules integrated with PEM electrolyzers or reversible PEM fuel cells/electrolyzers might be competitive for both hydrogen production and energy storage.

Issues Raised by the Carbon Sequestration Option for Continued Reliance on Fossil Fuels
Clearly, the abundance of fossil fuels, especially coal, in combination with cost-effective processes for gasification and carbon sequestration, offers an alternative to using natural gas as a transition fuel on the path to zero-carbon-emission technologies. In the most vigorously advocated embodiment of the carbon sequestration option, hydrogen from large coal-gasification plants would be used to generate power on-site and as a regional transportation fuel (Williams, 1999b). This raises the following questions:

  • In the absence of proof of technical feasibility, how reliable are the projected economics of hydrogen production from coal and carbon sequestration using such new technologies as ceramic membranes for hydrogen separation (Williams, 1999b)?
  • Who will make the huge investments in coal-based hydrogen production, carbon sequestration, centralized hydrogen power generation facilities, and the associated electric and hydrogen transmission systems? It seems unlikely that it will be the restructured utilities in the United States, which are rapidly becoming "wires only" businesses. If private investors cannot be enticed to take the risk of competing with currently cheaper sources of power and hydrogen, is this a prescription for massive public power projects?
  • Are there not major environmental impacts, including the release of greenhouse gases such as methane, caused by mining and transporting coal, as well as unavoidable health and safety problems?
  • Is it really preferable to use hydrogen near its point of production to generate electricity? Or would it be better to use a hydrogen distribution and transmission infrastructure equivalent to that which now exists for natural gas?
  • In the absence of such an infrastructure, how would the hydrogen produced in central coal-gasification facilities be made widely available for surface and air transport? Might it be practical to distribute hydrogen in compressed or liquefied form via trucks or railroad tank cars?
  • Would it be advantageous to develop a relatively costly infrastructure for delivering hydrogen to refueling stations, especially since such a system could also serve distributed power generation needs? Should there be a renewed effort to explore the feasibility of gradually converting the existing natural gas infrastructure to hydrogen?
  • As an alternative, would the best solution be to have only a power transmission and distribution infrastructure, accept the costs and energy losses of electrolysis, and make the hydrogen for surface and air transport needs in dispersed installations from centrally generated electricity?
  • Will it really be feasible to sequester carbon from coal gasification in relatively nearby depleted oil and gas reservoirs, deep coal seams, or aquifers, or will, in many instances, more costly long-distance pipeline transport of CO2 to sequestering sites have to be considered?
  • And, most fundamental of all, are there convincing economic, environmental, political, and institutional arguments to pursue this technologically risky alternative? And if so, can these arguments justify slowing or even halting rapid progress towards an inherently zero-carbon-emission, renewable, or essentially inexhaustible energy system, and also downgrading the valuable role of natural gas as a transition fuel?

Earlier studies of hydrogen versus natural gas transmission have indicated that the cost for hydrogen would range from 60 percent higher to as much as 2 to 3 times as much per unit of delivered energy, based on the higher heating value (HHV), but that there may be a slight cost advantage of hydrogen versus high-voltage power transmission (Gregory et al., 1972; Rosenberg and Gregory, 1972). Unfortunately, direct conversion of the existing high-pressure natural gas transmission grid to pure hydrogen is not feasible because of hydrogen embrittlement problems and because of hydrogen’s much larger compression power requirements. However, solutions to the embrittlement problem may be found, such as the addition of a small percentage of oxygen (100 parts per million to 1 percent by volume) (Williams, 1996).

A Novel Approach to a Cost-Effective, Coal-Based, Carbon-Emission-Free Energy System
Robert H. Williams of Princeton University has made a strong case for the option of central coal gasification with carbon sequestration. He claims that by 2020 hydrogen could be produced at roughly the same cost per unit of HHV as that projected for natural gas delivered to power plants (Williams, 1999b). This would be achieved through the use of still unproved ceramic membrane devices for hydrogen separation and associated increases in process efficiency. Coal would first be gasified at high pressure and temperature with oxygen from an air separation plant to produce primarily CO. Steam would then be added to convert the CO to CO2 and hydrogen at a relatively high temperature compared to the conventional catalytic process for performing this water gas shift reaction (CO + H2O ? H2 + CO2). The novel hydrogen separation device would allow progress of the water gas shift reaction to near completion in the absence of a catalyst at this relatively high temperature because the hydrogen, as it is produced, is removed continuously by diffusion through the tubular ceramic membranes. As projected by Williams, the use of the hot, high-pressure waste gas from the ceramic membrane device would produce about twice as much power than on-site requirements. Credits for this export power, in combination with other novel features, would reduce hydrogen production costs to roughly one-half those of conventional coal gasification, water gas shift, and CO2 removal processes.

In coal-gasification plants based on this scheme and large enough to fuel two 400-megawatt (MW) GE Frame 7-H combined-cycle gas-turbine/steam-turbine plants, Williams claims that without carbon sequestration, hydrogen could be produced in 2020 at about $3/million Btu (HHV and 1997 dollars). With carbon sequestration in onshore and offshore disposal sites 250-500 kilometers from the plant, the cost would be $4 to $4.25/million Btu. This is based on a projected cost of coal delivered to power plants in 2020 of $0.93/million Btu, again in 1997 dollars (Energy Information Administration, 1998).

Williams estimates that power costs for this essentially carbon-emission-free method of generation will be $0.043 to $0.048 per kilowatt-hour (kWh), depending on the type of combined-cycle turbine system employed (i.e., GE Frame 7-F or 7-H). However, this is a substantial premium over power produced with natural gas in combined-cycle turbine units at the projected cost of natural gas delivered to power plants in 2020 of $3.24/million Btu in 1997 dollars (Energy Information Administration, 1998). Williams calculates this power cost to be $0.031 to $0.034/kWh even though the fuel costs 3.5 times as much as coal. He does not really justify the premium of $0.012 to $0.014/kWh because he makes his case primarily by pointing to the large value of reducing pollutants and CO2 emissions via the use of coal-derived hydrogen instead of various coal-fired power generation technologies, including so-called "clean coal" technologies.

Comparing Costs
For example, even compared to the most advanced commercial coal-fired power generation technology -- integrated coal-gasification combined-cycle (IGCC) plants -- with their relatively high efficiency and low emissions of particulate matter, pollutants, and CO2, the higher costs of power generated with coal-based hydrogen can apparently be justified by the health benefits. Moreover, the cost of avoiding CO2 emissions is only $44/metric ton of carbon (tC), which is within the CO2 disposal cost range of $35 to $45/tC cited by Williams (1999b). But this reasoning does not apply to comparisons with modern natural gas technologies. For example, using Williams’s data, natural-gas-fueled combined-cycle plants emit only 37-49 percent as much CO2 as modern clean coal-fired power generation plants. Natural-gas-fired combined-cycle plants also have negligible emissions of particulates and other conventional pollutants. In this context, one may question Williams’s comparison of power costs of $0.036 to $0.037/kWh with coal-based hydrogen in which the CO2 is vented, with natural-gas-fueled power costs of $0.031 to $0.034/kWh, because it fails to account for the much higher CO2 emissions.

In his latest study, Williams acknowledges that many technological and institutional uncertainties face his approach. Most important are the unanswered questions about the ceramic membrane hydrogen separation device itself -- such as mechanical stability at the high pressure drop across the membrane; the possible need for catalysis to achieve adequate conversion of CO to hydrogen in a feed gas that contains high concentrations of hydrogen sulfide which poisons conventional water gas shift catalysts; and possible fouling of the membrane with particles that escape an unproved ceramic filter proposed for cleaning the hot synthesis gas that leaves the oxygen-blown coal gasifier. In terms of institutional problems, the greatest is the ability and willingness of the large and rapidly increasing coal users in the developing world, such as China and India, to adopt this radical new technology in view of their limited financial resources. In addition, there are many unanswered geological and environmental questions about the various options for carbon sequestration. Nevertheless, the proposed pathway to zero carbon emissions proposed by Williams merits serious consideration and substantial RD&D investments.

Coal-Based Hydrogen for Transportation
In contrast with an earlier study by Williams made available as a private communication (Williams, 1999a), Williams’s latest study does not elaborate on the means and costs of distributing hydrogen production in excess of that required for central power generation as a transportation fuel. He merely states that 12 percent of excess hydrogen production by each coal-gasification plant that fuels 800 MW of combined-cycle capacity at an 80 percent load factor would support 340,000 fuel cell vehicles traveling 18,000 kilometers per year at a fuel efficiency equivalent to 106 miles per gallon of gasoline. Williams also notes that, if in 1996 all U.S. coal-fired power plants had been converted to combined-cycle plants fueled with coal-based hydrogen and the carbon sequestered, and the 12 percent extra hydrogen produced had been used for fuel-cell-powered transport, one-half of the U.S. light-duty vehicle fleet could have been supported. Together, this would have reduced U.S. CO2 emissions by 40 percent and oil use by 20 percent, and would have increased U.S. coal use by 7.5 percent.

Presumably, as in the earlier study, the extra hydrogen would be made available to end users through regional transmission grids and refueling stations at a retail cost of about $13/million Btu (HHV and 1997 dollars). At the much higher efficiency of fuel cell vehicles, this would still be competitive with gasoline. In checking this thought experiment against the 305 gigawatts of 1996 U.S. coal-fired capacity, it would yield an excessive number of 130 million vehicles without correcting for the actual 65 percent load factor for U.S. coal-fired generation capacity in 1996, versus the 80 percent assumed by Williams for the hydrogen-fueled combined-cycle plants.

An Alternative Proposal for a Least-Cost Pathway to a Sustainable U.S. and Global Energy System
I favor an alternative pathway to a sustainable energy system (Linden, 1995, 1996, 1999) based on my confidence in the availability of natural gas as a transition fuel, and in the tremendous promise of high-tech renewable technologies that are inherently inexhaustible, free of pollutants and carbon emissions, and adaptable to distributed generation of electricity and hydrogen. This pathway calls for:

1. Increasing RD&D investments by industry, government, and industry/government consortia in high-tech renewable options such as photovoltaic, solar-thermal, and wind power, and the use of chemically pure electrolytic hydrogen for transportation uses and as an energy storage medium for reconversion to electricity by means of PEM fuel cells or the new reversible PEM fuel cell/electrolyzer systems.

2. Deploying solar and wind power as rapidly as is justified by their fully internalized economics (i.e., giving credit to such positive externalities as elimination of conventional pollutant and carbon emissions and to any benefits derived from the generally distributed nature of these power sources, and debiting the costs of overcoming the problem of the intermittency of these sources).

3. Providing appropriate incentives to industry and consumers for the accelerated conversion of surface transport to electromotive drive. After a possible transitional period in which conventional transportation fuels would be used more efficiently in hybrid systems, the ultimate goal would be to have all surface transport powered by hydrogen stored on board through the use of PEM fuel cells operating in tandem with advanced batteries.

4. To facilitate this conversion of surface transportation, creating a practical, dispersed hydrogen refueling system for light-duty vehicles that delivers compressed, high-purity hydrogen at competitive costs with gasoline or diesel fuel, taking into consideration the higher efficiency and lower maintenance costs of hydrogen-fueled vehicles, offset by the amortization of whatever cost premium such vehicles may require.

5. Over the three to five decades needed to achieve sufficient global market penetration of these zero-carbon-emission technologies, keeping annual global carbon emissions within a range that ensures that total anthropogenic emissions between 1991 and 2100 will not exceed 1,000 gigatonnes and will be in steep decline after 2050. This will be facilitated by such measures as the phaseout of power generation in coal-fired steam-electric plants and a shift to electromotive surface transport. According to the current best estimate of the Intergovernmental Panel on Climate Change, a global carbon budget of no more than 1,000 gigatonnes would limit atmospheric CO2 concentrations to 550 parts per million by volume at equilibrium, and additional global surface temperature increases to 1?C by 2100 and 1.6?C at equilibrium (Houghton et al., 1996; Linden, 1999).

6. Consistent with this pathway to sustainability, not following the Kyoto Protocol for premature carbon emission reductions by just the industrial (Annex I) nations that will be responsible for only a minor share of projected emissions increases, but instead capping peak global anthropogenic carbon emissions at about 11 gigatonnes per year in the 2030-2050 time frame (Linden, 1999).

7. Using natural gas as the transition fuel to a sustainable energy system because of its inherently low conventional pollutant and carbon emissions, growing global availability, and relatively low cost.

This strategy seems less risky because it makes no a priori assumptions of the final zero-carbon-emission technology mix and logistics of hydrogen supply, and, therefore, does not depend on the extremely favorable economics of converting coal to hydrogen by unproved processes, and the unsubstantiated economics and environmental impacts of carbon sequestration. Investments based on this strategy also appear to be less risky because they are on a much less massive scale than that required for coal supply, hydrogen production, and carbon sequestration complexes supporting 800 MW of central power generation, and because they offer a permanent solution for meeting U.S. and global energy needs without detrimental environmental impacts.

Reducing Reliance on Coal
A major element of this strategy is to rapidly reduce U.S. and, especially, the developing nations’ reliance on coal. This can be accomplished by substituting abundant natural gas resources for coal in power production in modular, highly efficient, and low-cost combined-cycle turbine systems which emit negligible conventional pollutants and only one-third as much CO2 as conventional coal-fired steam-electric plants. During the 30-50 years it would take for zero-carbon-emission renewable or essentially inexhaustible power sources to capture a major share of the global energy market, natural gas would also be a convenient and widely available energy source for efficient combined heat and power (cogeneration) systems using fuel cells, microturbines, reciprocating engines, and combustion turbines with capacities from 5 kW to 50 MW. In addition, natural gas reforming by well-proved, widely practiced, efficient, and low-cost processes would be used as an interim source of hydrogen for transportation fuel needs, in combination with hydrogen produced by off-peak power from whatever source is cheapest. Also, as a fall-back strategy, the development and demonstration of inherently safe and proliferation-proof nuclear breeder reactor technologies would be resumed in the United States to ensure the long-term availability of nonpolluting baseload power in case this option proves to be more cost effective.

In parallel with this proposed pathway to a sustainable global energy system, it seems prudent to pursue the fossil fuel reforming/gasification option with carbon sequestration. Intensive R&D to validate the coal-based approach advocated by Williams and to demonstrate its critical elements appears to be well justified. Such issues as the suitability of large, open horizontal aquifers for secure sequestration of CO2 and the feasibility of deep-ocean disposal are, of course, generic to all fossil fuel decarbonization options and clearly require major RD&D investments. However, early consideration of natural gas conversion to hydrogen near the point of gas production, with sequestration of the CO2 in depleted gas and oil fields, seems to be indicated. This promises to be the most cost-effective approach to avoiding the release of up to 290 gigatonnes of carbon -- the carbon content of the estimated 20,000 trillion cubic feet (Tcf) of remaining technically recoverable global natural gas resources (Linden, 1999). The commercial feasibility has already been confirmed in locations where the CO2 can be used for enhanced oil recovery and where substantial carbon taxes have been imposed.

The 20,000 Tcf of remaining natural gas resources (compared to 5,145 Tcf of year-end 1998 proved reserves) would have satisfied 1996 global fossil fuel consumption for only 64 years and would meet projected 2020 requirements for only 38 years. The portion of this resource base that will eventually be economically recoverable is not known, but should be at least on the order of 10,000 Tcf. This excludes the potentially larger unconventional natural gas resources, such as the enormous deposits of natural gas hydrates. In addition, there are as much as 3,000 billion barrels of conventional crude oil and natural gas liquids reserves and technically recoverable resources (i.e., excluding unconventional sources of hydrocarbon liquids such as tar sands and oil shale) which contain roughly another 340 gigatonnes of carbon (Linden, 1999).

In combination with the use of large natural gas reserves and resources, the optimal exploitation of liquid fuels in environmentally acceptable ways--such as for hybrid electromotive transport--should provide the necessary lead time for a shift to a zero-carbon-emission energy system. After all, with an allowable carbon emission budget of up to 1,000 gigatonnes, this strategy should leave ample margin for slower than anticipated progress towards the zero-carbon-emission goal. It should also be noted that, in terms of energy content, global proved reserves and recoverable resources of coal and lignite are six to seven times as large as the corresponding natural gas reserves and resources. However, even this amount of energy would provide only on the order of 150 years of projected global demand via the hydrogen production/carbon sequestration route and is, therefore, by definition, not a sustainable option.


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About the Author:Henry R. Linden, a member of the National Academy of Engineering, is the Max McGraw Professor of Energy and Power Engineering and Management, Illinois Institute of Technology.