|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|
The results of the sequestration cost analysis are best understood in the context of the relative costs for energy services for transport using alternative fuel/vehicle combinations, without the sequestration of separated CO2.
Consider first a comparison of costs without sequestration on a $/GJ of fuel basis (see fig. 6.2). The first observation one can make about these costs is that gasoline would be far less costly than hydrogen derived from any source. Second, the least costly option for providing hydrogen is from natural gas, for which the cost per GJ to the consumer is likely to be nearly 60 per cent higher than the gasoline price. Third, the cost of hydrogen is about the same for both coal and biomass, despite the assumption that the biomass price is about 50 per cent higher than the coal price - a reflection of the facts that costly sulphur removal is not needed for biomass and that biomass is more reactive than coal and thus easier to gasify (Williams et al. 1995a,b). Fourth, the cost of hydrogen from biomass or coal is about 10 per cent higher than for hydrogen from natural gas. Fifth, all the electrolytic hydrogen options are far more costly than hydrogen derived thermo-chemically from natural gas, coal, or biomass; for the least costly electrolytic option, which represents what might plausibly be realizable for advanced thin-film photovoltaic technologies,18 the cost of hydrogen to the consumer is 60 per cent higher than the indicated cost of hydrogen from biomass.
A more meaningful comparison than the cost of fuel per GJ is the cost of fuel per km of driving the vehicle that the fuel might be used in. The consumer prices and lifecycle CO2 emissions for hydrogen shown in figure 6.2 are converted in figure 6.3 to fuel costs and lifecycle CO2 emissions per km of driving a fuel cell vehicle (FCV), along with a comparison of gasoline costs and lifecycle CO2 emissions per km of driving, for both internal combustion engine vehicle (ICEV) and FCV applications. The reference gasoline ICEV is a year-2000 version of the Ford Taurus automobile with a fuel economy of 11.0 km/litre (25.8 mpg). The hydrogen FCV has performance characteristics that are comparable to those for this ICEV and a gasoline-equivalent fuel economy of 30.4 km/litre (71.6 mpg) (Williams 1995). The cost of hydrogen derived from natural gas and biomass without sequestration of the separated CO2 would be 1.49 and 1.73 cents/km, respectively, compared with 2.65 cents/km for gasoline. Initially fuel cell cars would probably be operated on gasoline converted to a hydrogen-rich gaseous fuel mixture via a process that begins with partial oxidation. The estimated fuel economy of such a fuel cell car having the same performance as the internal combustion engine alternative would be 18.0 km/litre (42.3 mpg). The fuel cost per km for this vehicle would be 1.62 cents/km (see fig. 6.3).19
Consider next the penalties for sequestration associated with hydrogen derived from natural gas for the situations depicted in figure 6.2. These penalties are low - increasing the cost of hydrogen to the consumer by only 0.8 to 2.6 per cent. The low value of the penalty is a result of: (i) being able to sequester the separated CO2 near where it is produced (thus avoiding the costs of long-distance CO2 pipeline transport), (ii) the relatively low penalty for storage in depleted natural gas fields compared with aquifers,20 and (iii) receiving a modest credit for extra natural gas produced as a result of depressurization of the natural gas reservoir - a credit almost large enough to cover the incremental cost of sequestration.
The penalties for sequestration shown in figure 6.2 for natural gas feedstocks are for the case where hydrogen is produced at the natural gas field both without and with sequestration. In this case the carbon tax needed to make equal the costs of hydrogen with and without sequestration, and thereby induce hydrogen producers to sequester the separated CO2, is US$932/tC, depending on the cost of sequestration and the magnitude of the credit for enhanced natural gas recovery (see table 6.5). Such a carbon tax would increase the hydrogen cost by US$0.2-0.7/GJ, some 1.6 to 5.5 per cent of the cost of hydrogen to consumers without sequestration. The magnitude of the carbon tax in this instance is independent of the length of the hydrogen transmission line and thus would apply equally to situations where large potential hydrogen markets are located near the natural gas field.
If instead hydrogen production without sequestration were to take place 1,100 km from the natural gas field near major remote hydrogen markets (see table 6.8), the hydrogen cost penalty to the consumer for sequestration would increase to the range 3.2-5.1 per cent, for a natural gas wellhead price of US$3/GJ. In this instance the carbon tax required to make equal the costs of hydrogen produced without and with sequestration is US$39-63/tC; with this carbon tax in place the cost of hydrogen to the consumer would be 7-11 per cent higher than without sequestration and with no carbon tax.21 Though the impact of this tax on the cost of hydrogen to the consumer is still modest, it is considerably higher than for the scenario where hydrogen production without sequestration takes place near the natural gas field. Since the latter scenario is most realistic for situations where there are large potential hydrogen markets near the natural gas field, the sequestration option is likely to be pursued first in such regions e.g. in the Netherlands and Texas. If nearby hydrogen markets can be served, there is no need to seek the economies of large-scale hydrogen transmission capacity by building very large hydrogen production plants. This makes it possible to begin sequestration much earlier in the evolution of a hydrogen economy than would be the case if the only potential hydrogen markets were remote from natural gas fields.
For the base case sequestering scenario for coal, in which CO2 is sequestered in aquifers, the cost penalty is higher - giving rise to a 611 per cent increase in the cost of hydrogen to the consumer for the situations indicated in figure 6.2. For the high sequestration cost estimate, the cost of hydrogen to the consumer per km of driving would still be 29 per cent less than the cost of gasoline with an internal combustion engine. In this instance, a carbon tax of US$29-54/tC would be needed to make equal the costs of hydrogen without and with sequestration, a tax that would increase the cost to the consumer of hydrogen derived from coal by 8-15 per cent.
For the base case sequestering scenario for biomass, the cost penalty is somewhat higher but still modest - giving rise to a 10-14 per cent increase in the cost of hydrogen to the consumer for the situations indicated in figure 6.2. But even if the high sequestration cost estimate proves to be valid, the cost of hydrogen to the consumer per km of driving would still be 26 per cent less than the cost of gasoline with an internal combustion engine.
The percentage cost penalties associated with sequestering the separated CO2 would be smaller still if calculated as a contribution to the total cost of owning and operating a car, to which the cost of fuel makes a relatively modest contribution (see fig 6.4).22 Consider, for example, the total lifecycle cost of owning and operating a fuel cell car operated on hydrogen derived from coal without sequestering the separated CO2. The estimated cost is 20.1 cents/km (slightly less than for a gasoline internal combustion engine car of comparable performance) for the assumptions indicated in figure 6.2, of which the price of hydrogen fuel accounts for only 1.71 cents/km. With a carbon tax sufficient to induce producers of hydrogen from coal to sequester, the lifecycle cost of the car would increase only 0.14-0.25 cents/km, or 0.71.3 per cent.
These calculations suggest that deep reductions in CO2 emissions can be achieved in the transport sector at low incremental cost by shifting to hydrogen or a hydrogen carrier derived from chemical fuel feedstocks. Such cost calculations could of course be refined as more knowledge is gained about the various technologies involved. But this basic finding is robust. It is not sensitive to the outlook for the relative prices of the three feedstocks considered. If natural gas prices remain low for the indefinite future, and if high estimates of remaining ultimately recoverable natural gas resources prove to be valid, hydrogen would be predominantly natural gas based in many parts of the world for decades to come, and sequestration could be pursued on large scales at very low incremental cost. If, instead, natural gas prices rise rapidly beyond the year 2010,23 then biomass- and coal based hydrogen production strategies would eventually supplement hydrogen supplies provided by natural gas.
Biomass without sequestration would tend to be favoured over coal with sequestration wherever adequate land resources are available for biomass production,24 because hydrogen production costs would be as low or lower under most conditions (for all the cases considered here - compare tables 6.6 and 6.7), and because lifecycle emissions would be only half as large (see table 6.1). However, in regions where coal is cheap and the availability of land for biomass production is limited, coal-based hydrogen strategies would be favoured.
Biomass-based production strategies with sequestration would be favoured where land-use constraints limit the extent of hydrogen production from biomass,25 or when it is desired to offset emissions from other sectors or parts of the world.
The largest uncertainties underlying this analysis are: (i) the extent to which society will adopt low-temperature fuel cells and their fuels for transportation and distributed combined heat and power applications, (ii) the prospects for converting existing natural gas transmission lines to hydrogen service and building new pipelines dedicated to hydrogen, and (iii) the extent and security of saline aquifers as storage reservoirs for separated CO2.
Major research, development, and demonstration commitments are needed on the hardware for low-temperature fuel cell technology and for the production, storage, and transport of hydrogen and hydrogen carriers. Although there is rapidly growing R&D activity on low temperature fuel cells for transportation applications, the overall level of the R&D effort in this area is still minuscule. Moreover, there is very little ongoing R&D on the production of hydrogen from coal or biomass.
The issues relating to converting existing natural gas transmission and distribution lines to hydrogen service are discussed in Appendix C. Being able to make this conversion would be especially important for the already industrialized world, where a large natural gas pipeline infrastructure is already in place. It appears to be feasible to convert low-pressure distribution lines without great difficulty, but hydrogen embattlement looms as a serious issue for high-pressure transmission lines. Technical fixes might be possible. For example, would mixing trace quantities of another gas with the hydrogen be a suitable strategy for coping with the embattlement problem (see Appendix C)? More research is needed to find out.
More research is also needed on the various issues raised regarding sequestration in depleted oil and gas fields and saline aquifers especially the latter.