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1. Obviously, the service "commuting to work" also requires a road infrastructure. Such infrastructures, however, although representing embodied technology, know-how, materials, and energy services, are only indirectly considered part of the energy system.
2. Exergy defines the maximum amount of work theoretically obtainable from a system as it interacts to equilibrium with the environment. While the energy of 11 litres of water at 80°C and 1 kWh of electricity is approximately the same, it should be obvious that 1 kWh of electricity enables the production of more useful work than the 11 litres of hot water. Exergy, therefore, is a quality measure for different types and forms of energy. Moreover, unlike energy, exergy is not conserved and the initial exergy potential is destroyed by the irreversibility's present in any conversion process. Contrary to energy efficiencies, the use of exergy efficiency relates actual efficiencies to the ideal maximum. Although this maximum can never be reached, exergy efficiencies provide a means to identify those areas with the largest improvement potentials or applications where there is a mismatch between the energy service and the energy supplied to provide that service.
3. Useful exergy is defined as the exergy supplied by the service conversion technology (e.g. the mechanical energy at the wheel of an automobile engine, the heat supply to a room by a radiator, or the luminosity of a light bulb), while the corresponding services could be measured in person kilometres travelled, the desired temperature in a room, or adequate illumination for reading.
4. Generating efficiencies are based on the current OECD production mix, which is dominated by thermal power plants.
5. The overall efficiency from crude oil production to the supply of gasoline to an internal combustion engine of a vehicle is, on average, 80 per cent. The overall efficiency of hydrogen produced for the same vehicle, while depending on the primary energy source and subsequent conversion steps, is certainly lower. For example, one possible source-to-currency onboard pathway commences with nuclear-generated electricity, which is used to split water electrolytically into hydrogen and oxygen. The hydrogen then is liquefied (using nuclear electricity) and distributed to the filling station, stored, and dispensed to the cryogenic tank of the vehicle. Based on future technologies, the overall efficiency is expected to range between 20 and 25 per cent. If photovoltaic technology replaces nuclear electricity in this chain at an assumed conversion efficiency of 15 per cent, the overall efficiency of this pathway ranges between 6 and 9 per cent. If the solar radiation is considered free, then the pathway efficiency becomes some 50 per cent. Another pathway could utilize biomass for methanol production. Distribution and dispensing could use the present oil product infrastructures. Onboard the vehicle, the methanol would be re-formed on demand to generate hydrogen. The estimated efficiency is 45-55 per cent.
6. The technologies for effective leakage control exist but are often too capital intensive to be considered economical under present market conditions.
7. There are four routes for a substantial expansion of the role of natural gas in transportation. Two routes use natural gas directly as onboard fuels, i.e. CNG or LNG (liquefied natural gas). The other two routes, methanol and hydrogen, use natural gas indirectly. Although methanol has been promoted as a clean substitute for gasoline, it is unlikely that it will have a major impact on the transportation fuel market. Methanol appears attractive because, unlike the other natural gas options, it is a liquid at ambient conditions and thus can use the existing gasoline distribution and storage infrastructure. Still, the production and use of methanol generates considerable CO2 emissions. Used in internal combustion engines, the greenhouse gas emissions from methanol are comparable to those from oil products, whereas a significant reduction could be achieved after re-formation and use in fuel cells. Large-scale use of fossil-derived methanol is neither compatible with nor in support of objectives such as eco-restructuring, de-materialization, or carbon free energy service production. Fossil-sourced methanol is, therefore, at best an incremental transition solution. However, the outlook for methanol would change markedly if it were biomass sourced.
8. Storage in depleted natural gas and oil fields is another option; the storage capacities, however, are considerably smaller than ocean disposal and are unlikely to offer permanent solutions to CO2 emissions from the long-term use of fossil energy sources.
9. An alternative to growing forests for carbon fixation from fossil fuels, however, is to grow biomass sustainably as an energy substitute for fossil fuels.
10. The United Nations Framework Convention on Climate Change (UNFCCC) addresses the issue of technology and capital transfer from the North to the South under the label Activities Implemented Jointly (AIJ). At the First Conference of the Parties held in Berlin in the spring of 1995, it was decided that a pilot phase should be established for AIJ projects. However, no credits to ANNEX I will occur as a result of GHG emissions reduced or sequestered from activities implemented jointly (UNFCCC 1995).
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Nakicenovic, N., A. Grübber, A. Inaba, S. Messner, S. Nilson, Y. Nishimura, H. -H. Rogner, A. Schafer, L. Schrattenholzer, M. Strubegger, J. Swisher, D. Victor, and D. Wilson (1993) Long-term strategies for mitigating global warming. Energy 18(5), Special Issue.
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6. Fuel decarbonization for fuel cell applications and sequestration of the separated CO2
The challenge of stabilizing the atmosphere
Flue gas decarbonization vs. fuel gas decarbonization
Lifecycle CO2 emissions - without and with CO2 sequestration
Options for sequestering CO2
Framing the cost analysis for CO2 sequestration
Major findings of the sequestration cost analysis
Appendix A: The importance of the water-gas shift reaction in fuel decarbonization
Appendix B: Biomass CO2 emission offset potential in a world where some coal-rich regions cannot or will not reduce emissions
Appendix C: Pipeline transport of hydrogen
Robert H. Williams
The challenge of stabilizing the atmosphere
Since the pre-industrial era, the concentration of CO2 in the atmosphere has increased from 280 parts per million (ppm) to 350 ppm, mainly as a result of the burning of fossil fuels. The consequences of the ongoing build-up are troubling though uncertain (IPCC 1990; Manabe and Stouffer 1993, 1994). Stabilizing the atmosphere at less than a doubling of the atmospheric concentration of CO2 would require radical change in global energy technology. According to the Intergovernmental Panel on Climate Change (IPCC), stabilizing the atmospheric concentration of CO2 at 450 ppm would require that cumulative emissions over the period 1990-2100 be no more than 630-650 GtC, corresponding to an average emission rate of 5.7-5.9 GtC/year (IPCC 1996). For comparison the mean estimate of actual emissions in 1990 is 7.4 GtC (of which 6.0 GtC was due to fossil fuel burning). Moreover, IS92a, the reference scenario for global energy generated by the IPCC, involves emissions increasing to 20 GtC/year by 2100, with cumulative emissions amounting to 1,500 GtC over 1990-2100 (IPCC 1994).
Recent advances relating to the prospects for renewable electric power-generating technologies - especially wind, photovoltaic, solar thermal electric, and biomass power technologies - have led various groups to be optimistic about the prospects for curbing emissions from the electric power sector over a period of many decades (Johansson et al. 1993; WEC 1994; Anderson and Ahmed 1995).
Although this new outlook for renewable electric technologies is auspicious, successful development of a wide range of renewable electric technologies by itself would not make it possible to stabilize the atmosphere at near current levels, because most CO2 emissions are from non-electric sources. In 1990, the electricity sector accounted for 36 per cent of global primary commercial energy use but only 29 per cent of global CO2 emissions from fossil fuels; in the IS92a scenario, it is projected that the electricity sector in 2100 will account for 44 per cent of primary energy use but just 25 per cent of total CO2 emissions from fossil fuel use (despite a 6.3 fold increase in electricity demand over the period 1990-2100, compared with a more modest 4.2-fold increase in total primary energy use in this period), because of projected growing contributions to power generation from renewable and nuclear power sources (IPCC 1992).1
The major greenhouse challenge will be to avoid enormous increases in CO2 emissions arising from the production of synthetic fuels from coal.2 In the IS92a scenario, synthetic fluids account for 75 per cent of all liquid and gaseous fuels used in 2100, and the amount of coal used for synthetic liquid and gaseous fuels production then is 4.2 times the total amount of coal use in 1990.
Synthetic fuels can be produced from non-fossil fuel sources. The prospect that low-cost photovoltaic (PV) power systems could become available (circa 2010-2020) with amorphous silicon and/or other thin-film PV technologies led in the late 1980s to a detailed technical/economic analysis painting a picture of a world energy economy in which PV technology would be widely used not only to provide electricity that is used directly but also to provide hydrogen derived electrolytically from this electricity, for transport and various stationary markets (Ogden and Williams 1989). Although the outlook for low-cost PV technology based on thin-film devices is as good today as it was at the time of the Ogden and Williams study (Carlson and Wagner 1993; Zweibel and Barnett 1993), it is now known that the production of hydrogen from biomass via thermochemical gasification would be a much less costly route for producing hydrogen from a renewable energy source than hydrogen derived electrolytically from any source3 other than off-peak power4 - even if cost goals for thin-film PV technology are fully realized; moreover, the prospects are good that this biomass-derived hydrogen would be no more costly than hydrogen derived from coal via thermochemical gasification in many instances (Williams et al. 1995 a,b).
The growing of biomass for use with modern energy conversion technologies, either in large plantations or on many small energy farms (Larson et al. 1994), has been identified as an attractive climate friendly energy strategy that simultaneously could provide an energy base for rural industrialization and employment generation in the developing world and make it possible to phase out agricultural subsidies in the industrialized world (Williams 1994a). Although it is inherently easier to grow biomass for energy in environmentally acceptable ways than is the case for food production (Larson et al. 1995), various groups are sceptical that biomass can be produced for energy at large scales in environmentally acceptable ways (WEC 1994; Flavin and Lenssen 1994).
This paper explores a strategy for decarbonizing fuels (both fossil and biomass) that would make it possible to achieve deep reductions in CO2 emissions, prospectively at a relatively low incremental cost for energy services, while reducing the amount of land resources needed for making energy from biomass and avoiding the large cost penalties associated with a possible premature commitment to solar electrolytic hydrogen in the quest for an energy future compatible with sustainable development goals.
Flue gas decarbonization vs. fuel gas decarbonization
A technically feasible but costly option for achieving deep reductions in greenhouse gas emissions is to extract the CO2 from flue gases of large fossil fuel combustors (e.g. at fossil fuel power plants) and to isolate the CO2 so recovered from the atmosphere (Blok et al. 1989). This "flue gas decarbonization" strategy is costly largely because of the expenses associated with separation of the CO2 from flue gases (in which the concentration of CO2 is only 8-15 per cent); once the CO2 is separated out, the incremental cost of isolating the recovered CO2 from the atmosphere can often be relatively modest (van Engelenburg and Blok 1993; Hendriks 1994).
A much more promising approach involves fuel decarbonization: the production of hydrogen or a hydrogen-rich fuel from a carbon rich fuel, in the process of which a stream of essentially pure CO2 is separated as a byproduct at low incremental cost - a process that might more appropriately be labelled "fuel gas decarbonization" (see Appendix A). Pioneering work on fuel gas decarbonization has been carried out at the University of Utrecht (Blok et al. 1989; Hendriks 1994) and at Shell in the Hague (van der Burgt et al. 1992) in conjunction with the production of electricity from coal via integrated gasification/combined cycle power plants. Although the cost penalty for fuel decarbonization and sequestration of the separated CO2 with this approach is far less than that for various flue gas decarbonization schemes, the electricity produced this way would nevertheless be about 30 per cent more costly than with a conventional coal integrated gasifier/combined cycle power plant (Hendriks 1994), simply because there are no direct economic benefits (only environmental benefits) arising from fuel gas decarbonization.
Because the production of hydrogen is inherently costly, it is desirable to use it in conversion equipment where it is worth more than conventional fluid fuels- especially because there is little prospect that the prices of conventional hydrocarbon fuels will rise high enough in the foreseeable future to the point where hydrogen will be able to compete on a $-per-GJ-equivalent basis. The true value of hydrogen should be determined not by a comparison of fuel costs but by a comparison of the costs of providing an energy service such as the cost per vehicle km of travel.
The use of hydrogen in low-temperature fuel cells for transport and distributed combined heat and power applications could provide the needed high value. Fuel cells offer high thermodynamic efficiency and zero or near zero local pollutant emissions without the need for pollution control equipment. Moreover, for combined heat and power applications, the absence of scale economies for production units, the lack of need for operating personnel, low maintenance requirements, and low noise levels make it possible to site low-temperature fuel cells near users where the produced energy is more valuable than at centralized facilities.
Until recently it has not been practical to take advantage of these attributes. The only commercial fuel cell is the phosphoric acid fuel cell. Its power density is too low for it to be considered for automotive applications, and its prospective costs in mass production are not especially low. However, recent advances relating to the proton exchange-membrane (PEM) fuel cell indicate a hopeful future for this technology for both distributed combined heat and power (Little 1995; Dunnison and Wilson 1994) and transport (Williams 1993, 1994b; Mark et al. 1994) applications.5 When mass produced for transport applications, its costs could be low, approaching the costs of internal combustion engines.6
Low-temperature PEM fuel cells can very efficiently utilize hydrogen or methanol that is re-formed with steam to produce a gaseous H2/CO2 mixture onsite or, in transport applications, onboard the vehicle.7 Such fuels have good prospects for becoming major energy carriers in the "post-combustion" era, when electrochemically based fuel cells will have become well established in the energy economy. The least costly ways of producing these energy carriers are from chemical fuel feed stock's - initially natural gas and later coal and biomass (Williams et al. 1995 a,b).
Whereas the alchemists failed in their attempts to transmute base metals into gold, the technology for making hydrogen from carbon is well established. Specifically, a carbon-rich fuel feedstock can be processed to produce hydrogen or methanol (a hydrogen carrier) by first converting the feedstock into "syugas" (a mixture of CO and H2) via steam re-forming (in the case of natural gas) or via thermochemical gasification (in the case of coal or biomass) and then shifting the energy contained in the CO to H2 by reacting the CO with steam - a process requiring very little net energy input (see Appendix A). In the final stages of the manufacturing process, CO2 is separated from the fuel product (e.g. using pressure swing adsorption [PSA] in the case of hydrogen production or Selexol in the case of methanol production) in a virtually pure stream that is available as a by-product at low incremental cost (see table 6.1).8
If there were no greenhouse problem, this stream of pure CO2 would be vented to the atmosphere. In a greenhouse-constrained world, consideration might be given to isolating this CO2 from the atmosphere because of the large potential and relatively low costs involved. If this stream of separated CO2 could be stored in isolation from the atmosphere, CO2 emissions would be sharply reduced.
Lifecycle CO2 emissions - without and with CO2 sequestration
Without sequestration of the separated CO2 there would be no significant reduction in lifecycle CO2 emissions per GJ of fuel provided, in shifting from reformulated gasoline to methanol or hydrogen derived from natural gas; moreover, lifecycle emissions would roughly double in shifting from reformulated gasoline to methanol or hydrogen derived from coal (see table 6.1). The only options based on the thermochemical conversion of fuels that offer significant greenhouse benefits without sequestration of the separated CO2 are methanol and hydrogen derived from biomass that is grown on a sustainable basis; in these instances lifecycle emissions are just 5 and 10 per cent of those for reformulated gasoline (see table 6.1).9
With sequestering, the balances are sharply changed. Lifecycle emissions for methanol produced from coal would be no more than for gasoline or for methanol produced from natural gas, while life cycle emissions for hydrogen produced from either natural gas or coal with sequestering would be only about half of the emissions from gasoline (see table 6.1).
In the case of biomass grown on a sustainable basis, net lifecycle emissions with sequestering would be strongly negative (because the carbon in the plant matter was originally extracted from the atmosphere in photosynthesis) and, absolutely, more than twice as large for hydrogen production10 as for methanol production (see table 6.1). This characteristic of systems that involve the production of hydrogen-rich fuels from biomass with sequestering of the separated CO2 makes it possible to achieve deep net reductions in global greenhouse gas emissions even if some countries are unable to achieve deep reductions or choose to ignore the greenhouse problem (see, for example, Appendix B).
If the end-use technology is taken into account, the emissions reduction potential with sequestration can be even more dramatic. Consider lifecycle emissions, measured in gr C per km of vehicular travel, for fuels used in fuel cell vehicles (FCVs) compared with emissions for gasoline internal combustion engine vehicles (ICEVs). Operated on gasoline, methanol, and compressed hydrogen, FCVs are expected to be, respectively, 1.8, 2.4, and 2.8 times as energy efficient as comparable gasoline ICEVs (see table 6.2). As a result, lifecycle emissions per km of travel for FCVs operated on methanol derived from coal with CO2 sequestering are only two-fifths as large as for gasoline ICEVs. For FCVs operated on hydrogen derived from natural gas or coal with CO2 sequestering, emissions per km are less than one-fifth of those for gasoline ICEVs and one-third of those for gasoline FCVs (see table 6.2).
Table 6.1 CO2 emissions characteristics of alternative transport fuel options (kg C/GJ of transport fuel produced)
Lifecycle CO2 generation ratea
Potential CO2 sequestration ratec
|Net lifecycle emissions with photosynthetic offset and/or CO2 sequestration|
|MeOH from natural gas||23.0||-||_d||23.0|
|H2 from natural gas w/o CO2 sequestering||21.8||-||- 10.7||21.8|
|H2 from natural gas w/CO2 sequestering||21.8||-||- 10.7||11.1|
|MeOH from coal w/o CO2 sequestering||40.8||-||-18.6||40.8|
|MeOH from coal w/CO2 sequestering||40.8||-||-18.6||22.3|
|H2 from coal w/o CO2 sequestering||41.2||-||- 29.8||41.2|
|H2 from coal w/CO2 sequestering||41.2||-||- 29.8||11.4|
|MeOH from biomass w/o CO2 sequestering||42.8||-40.5||-11.1||2.3|
|MeOH from biomass w/CO2 sequestering||42.8||-40.5||-11.1||-8.8|
|H2 from biomass w/o CO2 sequestering||38.9||-33.5||-23.8||5.4|
|H2 from biomass w/CO2 sequestering||38.9||-33.5||-23.8||-18.4|
a. Williams et al. (1995 a,b) provide estimates of emissions
of CO2 that occur throughout the entire cycle of fuel
production, fuel transport, additional processing (if any), and
final use for the primary energy source/energy carrier
combinations shown here, in gr C per km, for internal combustion
engine vehicle and fuel cell vehicle applications. Lifecycle
emissions per km of travel are converted here to emissions per GJ
of energy carrier consumed by taking into account the fuel
economy of the vehicle (see note b to table 6.2).
b. This is the CO2 extracted from the atmosphere in growing biomass. It is not quite as large as the lifecycle emissions associated with the production of H2 or MeOH from biomass, because of the various fossil fuel inputs involved in biomass production - e.g. for cultivation, harvesting, and hauling equipment, and for fertilizers and herbicides.
c. This is the C in the pure CO2 stream produced at the fuel production facility as a "free" by-product of the production of H2 or MeOH (from Katofsky 1993).
d. There is no CO2 recovery at plants producing methanol from natural gas, because fuel processing does not involve the water-gas shift reaction (see Appendix A); the H/C ratio needed for methanol is the same as that for methane. the principal constituent of natural gas.
Table 6.2 Net lifecycle CO2 emissions with photosynthetic offsets and/or CO2 sequestration for alternative transport fuel options
Emissions per unit of transport fuel provideda (kg C/GJ)
Emissions per unit of transport service providedb (gr C/km of car driving)
|MeOH from natural gas||23.0||64.9||30.7|
|H2 from natural gas w/o CO2 sequestering||21.8||59.9||25.0|
|H2 from natural gas w/CO2 sequestering||11.1||30.5||12.7|
|MeOH from coal w/o CO2 sequestering||40.8||115.1||54.5|
|MeOH from coal w/O2 sequestering||22.3||62.9||29.8|
|H2 from coal w/o CO2 sequestering||41.2||113.0||47.2|
|H2 from coal w/CO2 sequestering||11.4||31.3||13.1|
|MeOH from biomass w/o CO2 sequestering||2.3||6.6||3.1|
|MeOH from biomass w/CO2 sequestering||-8.8||-25.3||- 11.9|
|H2 from biomass w/o CO2 sequestering||5.4||14.7||6.1|
|H2 from biomass w/cO2 sequestering||-18.4||-50.1||-20.7|
a. From table 6.1 (right-most column).
b. Net lifecycle emissions Ekm (in gr C per km of driving) are obtained from net lifecycle emissions EGJ (kg C per GJ) of the energy carrier via
Ekm = (1000 gr/kg)*(0.0348 GJ/litre)*EGJ/FE,
where FE is the fuel economy of the vehicle, in km/litre of gasoline equivalent. (Gasoline has a higher heating value (HHV) of 0.0348 GJ/litre.) Emissions Ekm are given both for internal combustion engine vehicles (ICEVs) and for fuel cell vehicles (FCVs). For ICEVs, the gasoline-equivalent fuel economies are assumed to be: for gasoline, 11.0 km/litre (25.8 mpg); for MeOH, 12.4 km/litre (29.1 mpg); and for H2, 12.7 km/litre (29.9 mpg). For FCVs, the gasoline-equivalent fuel economies are assumed to be: for gasoline, 20.4 km/litre (47.7 mpg), based on the use of onboard partial oxidation; for MeOH, 26.1 km/litre (61.5 mpg), based on the use of an onboard steam re-former; and for compressed H2 gas, 30.4 km/litre (71.6 mpg). See Williams et al. (1995 a,b.
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