|Eco-restructuring: Implications for sustainable development (UNU, 1998, 417 pages)|
|Part I: Restructuring resource use|
|6. Fuel decarbonization for fuel cell applications and sequestration of the separated CO2|
1. The use of coal for power generation in the IS92a scenario accounts for 19 per cent of total CO2 emissions from fossil fuels in 2100, the same percentage as in 1990.
2. If there were no coal and if those concerned about climate change had only conventional oil and gas resources to worry about, it might be feasible to stabilize the atmospheric concentration of CO2 near the present level. According to the US Geological Survey (Masters et al. 1994), remaining ultimately recoverable conventional oil and gas resources (proved reserves plus estimated recoverable undiscovered resources) amount (as of 1992) to 11,300 exajoules (EJ) of oil and 12,500 EJ of natural gas. Assuming CO2 emission coefficients of 19.5 million tonnes of carbon per EJ (MtC/EJ) for oil and 13.5 MtC/EJ for natural gas, cumulative emissions associated with burning all conventional oil and gas resources amount to 390 GtC, which is within the range of cumulative emissions consistent with stabilizing the atmosphere at the present concentration of CO2 (IPCC 1996).
3. Hydrogen produced electrolytically is more costly than hydrogen derived from fuels largely because electricity is far more expensive than fuel per unit of contained energy. Averaged over all users in the United States in 1993 the electricity price was three times the price of all petroleum products, five times the price of natural gas, and 14 times the price of coal (EIA 1995). Hydrogen derived from electricity will be even more expensive than the electricity "feed" used in its manufacture, both because of inefficiencies in electrolytic conversion and because of the capital needed for electrolytic equipment.
Although hydrogen derived from carbon-rich fuels via thermochemical processes will be more expensive than these feedstocks per unit of contained energy, it will not be nearly so expensive as electrolytic hydrogen, because the basic processes involved in "turning carbon into hydrogen" (see Appendix A) are relatively simple and not nearly so capital intensive as the process of making electricity.
4. When hydrogen is derived electrolytically from off-peak power sources that have low running costs, it can be economically attractive, because the capital charges can be avoided. However, the total quantities of hydrogen potentially available via this route are tiny in relation to the demand for fluid fuel. Nevertheless, hydrogen derived electrolytically from off-peak hydroelectric power will play important roles in providing hydrogen for various demonstration projects and other niche applications in helping launch a hydrogen economy.
5. In late 1995, Ballard introduced a 60 passenger, 275 hp. hydrogen PEM fuel cell "commercial prototype" bus having a 400 km (250 mile) range. It has sold three hydrogen fuel cell buses each to the Chicago Transit Authority and to BC Transit in Vancouver, British Columbia; the first bus was delivered to Chicago in September 1996. In 1998 Ballard expects to be producing commercially 75 passenger, 275 hp. hydrogen fuel cell buses having a 560 km (350 mile) range. In collaboration with Ballard and using Ballard fuel cells, Daimler-Benz has introduced three experimental fuel cell vehicles: a proof-of-concept hydrogen PEM fuel cell van (NECAR I) in April 1994, a prototype hydrogen powered fuel cell passenger van (NECAR II) in April 1996, and a small prototype methanol-fuelled fuel cell passenger car (NCAR III) with an onboard fuel processor in September 1997. In joint ventures with Ballard, Daimler-Benz hopes to produce 100,000 engines per year for fuel cell vehicles by 2005. Also Toyota has introduced two experimental fuel cell vehicles: a prototype hydrogen fuel cell passenger car using metal hydride storage in October 1996, and a prototype methanol fuel cell passenger car with onboard fuel processing in September 1997.
6. In one study carried out for the US Department of Energy by the Allison Gas Turbine Division of General Motors (AGTD 1994), it is estimated that, in mass production, the cost for a 60 kWe continuous output (~90 kWe peak output) automotive electrochemical engine system based on use of the PEM fuel cell operated on methanol would be US$3,899 - consisting of USS1,752 for the fuel cell stack, plus US$1,077 for the fuel processor, US$195 for the heat rejection and water management system, and US$875 for system auxiliaries - so that the total unit installed cost would be USS65/kWe continuous (US$46/kWe peak).
In another study carried out for the US Department of Energy by Directed Technologies, Inc. (James et al. 1994), the cost of mass-produced automotive hydrogen/air PEM fuel cells (for production at a rate of 106 units per year in the year 2004) is estimated to be US$31/ kWe, and the cost of an 85 kWe hydrogen/air PEM fuel-cell-based automotive power system (inducing the cost of the fuel cell, the heat management system, the power conditioning, an ultra capacitor for peak power, an electric motor, and storage tanks for compressed hydrogen) is estimated to be US$4,400-5,100, compared with US$3,000-4,000 for the cost of the internal combustion engine equipment that would be displaced.
7. At the site or, in transport applications, onboard the vehicle, methanol is "re-formed" to produce a gaseous mixture of hydrogen and carbon dioxide via reactions that are summarized as:
CH3OH + H2O(g) ® CO2 + 3 H2
This gaseous fuel mixture can be utilized directly by proton-exchange-membrane fuel cells, which (unlike the alkaline fuel cells used in the space programme) are not poisoned by CO2.
8. Hydrogen and methanol can be produced from natural gas with commercially available technology. These energy carriers can also be produced from coal using commercially ready oxygen-blown coal gasifies plus commercially available technologies for the needed further processing. In the case of biomass, the fuel-processing technologies downstream of the gasifier are also commercially available. Although suitable gasifies tailored to biomass are not commercially available, such gasifies could be commercially available by 2000 with a relatively modest R&D effort (Williams et al. 1995a,b).
9. When hydrogen is produced from natural gas, the carbon content of the natural gas feedstock amounts to 15.2 kg C per GJ of produced hydrogen, and the CO2 stream separated at the PSA unit has a carbon content of 10.7 kg C per GJ of produced hydrogen. When hydrogen is produced from coal, the carbon content of the coal feedstock amounts to 31.8 kg C per GJ of produced hydrogen, and the CO2 stream separated at the PSA unit has a carbon content of 29.8 kg C per GJ of produced hydrogen.
10. When hydrogen is produced from biomass, the carbon content of the biomass feedstock amounts to 34.4 kg C per GJ of produced hydrogen, and the CO2 stream separated at the PSA unit has a carbon content of 23.8 kg C per GJ of produced hydrogen.
11. In this paper, all costs are presented in 1991US$ and lifecycle costs are evaluated using a 10 per cent real (inflation-corrected) discount rate. Corporate income, property, and sales taxes are neglected. Also, the energy content of fuels is given in terms of the higher heating value.
12. The present analysis is limited to hydrogen because the sequestration potential is much larger than for methanol production (see table 6.1). However, the general finding that sequestration costs are low holds for methanol as well. In fact, the costs for CO2 compression would be less with methanol production. In this case, the CO2 is generally released at higher pressures using Selexol CO2 separation technology (e.g. 13 bar for methanol produced from biomass using the Battelle Columbus Laboratory biomass gasifier and 21.8 bar for methanol produced from coal using the Shell gasifier Katofsky 1993) than is the case for the PSA technology used in hydrogen production (1.3 bar). If the CO2 must be compressed to 110 bar, the required compression ratio is just 8.5 for biomass- and 5.0 for coal-derived methanol, compared with 85 for hydrogen produced from natural gas, coal, or biomass.
13. The costs for drying and compressing CO2 to the pressures needed for pipeline transport and reservoir injection are based on Farla et al. (1992) at Utrecht University- see note d, table 6.5.
14. The costs of CO2 transport by pipeline are based on analyses carried out at the Statoil R&D Centre in Trondheim, Norway (Skovholt 1993) - see note e, tables 6.6 and 6.7.
15. The costs for disposal in both depleted natural gas fields and saline aquifers are based on the work of Hendriks (1994) at Utrecht University - see note e, table 6.5, and note f, tables 6.6 and 6.7.
16. Drawing on commercial plantation experience in Brazil (Carpentieri et al. 1993), biomass supply curves (potential production vs. long-run marginal production cost) have been generated on a country-by country basis for Africa, Latin America, and Asia, for the year 2025, taking into account land requirements for food production at that time (Larson et al. 1995). Marginal costs were related to prospective yields, and prospective yields were estimated via a correlation with rainfall. It was found that 70 EJ/year (35 EJ/year) of biomass could be produced on 10 per cent (5 per cent) of "available" land in those countries where biomass can be produced at or below this cost. Available land is defined here as non-forest, non wilderness land that is not needed for producing food crops. To put these energy quantities into perspective, consumption of coal, oil, and natural gas in 1990 was 35.8 EJ, 40.5 EJ, and 12.2 EJ, respectively, for developing countries.
17. In a major assessment carried out by a team with participants from the Oak Ridge National Laboratory and the US Department of Agriculture, it is estimated that if R&D goals for plantation biomass in United States can be realized, 5 EJ/year of plantation biomass could be produced in 2020 on 17 million hectares at a long-run marginal cost of US$1.5/GJ (Graham et al. 1995). For comparison, about 3 EJ/year of biomass would be required to support a fleet of 120 million cars (the total number in the United States in 1992) powered by hydrogen fuel cells, assuming the gasoline-equivalent fuel economy of these fuel cell cars is 34 km/litre (80 mpg).
18. The least costly electrolytic option is for a photovoltaic (PV) module efficiency of 18 per cent, a PV installed system cost of US$1,030/kW, and a plant siting in an area of high insolation (270 W/m2). These PV performance and cost parameters are optimistic but plausible for advanced thin-film PV technologies (Ogden and Nitsch 1993).
19. With a cost of service companson, even costs for electrolytic hydrogen used in fuel cell vehicles are not much different from the 2.65 cents/km cost of gasoline for an internal combustion engine vehicle ranging from 2.75 to 3.90 cents/km for the electrolytic options shown in figure 6.3.
20. Storage costs estimated by Hendriks (1994) range from US$3/tC to US$13/tC for depleted natural gas fields, compared with US$9/tC to US$34/tC for saline aquifers.
21. For comparison, a carbon tax in the range US$39-63/tC would increase the retail price of gasoline shown in figure 6.2 by 11-17 per cent.
22. It is assumed that hydrogen is stored onboard vehicles in carbon-fibre-wrapped aluminium tanks at high pressure (550 bar). Because of the bulkiness of gaseous hydrogen storage, the hydrogen FCV is designed for a range between refuellings of 400 km, compared with 640 km for a gasoline ICEV. The weight of the hydrogen FCV is estimated to be 1.3 tonnes, compared with 1.4 tonnes for the ICEV. Initial costs are estimated to be US$17,800 for an ICEV and US$25,100 for a hydrogen FCV (in mass production). The initial cost for a gasoline FCV is assumed to be US$21,700, the same as the estimated cost for a methanol FCV (Ogden et al. 1994). Retail fuel taxes are included under "other non fuel operating costs" at the average US rate for gasoline used in ICEVs; to ensure that road tax revenues are the same for all options, it is assumed that retail taxes are 0.75 cents/km for all options (equivalent to 8.2 cents/litre or 31 cents/gallon for gasoline used in ICEVs).
23. The US Department of Energy has projected that the wellhead price of natural gas in the United States will increase at an annual average rate of 3.1 per cent per year. 1993-2010 (EIA 1995).
24. Considerable hydrogen production from biomass is likely to be possible before land scarcity becomes a major limiting factor for the growing of biomass. See, for example, the calculation presented in Appendix B. and discussions of land-use availability for industrialized countries in Williams (1994a) and for developing countries in Larson et al. (1995).
25. With sequestration of the separated CO2, the amount of biomass grown on a given land area could make a much larger contribution in reducing global emissions than without sequestration.