The capture and sequestering of carbon dioxide is an important option for the control of emissions of greenhouse gases to the atmosphere. The papers presented at the 5th Fifth International Conference on Greenhouse Gas Control Technologies, held in Cairns, Australia, 13-16 August 2000, provided an opportunity to review advances to fossil-fueled processes for the generation of electricity. It is timely to review this subject because of the increasing urgency to deal with this problem as evidenced by deliberations at the Sixth Conference of the Parties to the United Nations Framework Conventional on Climate Change held in The Hague 13-24 November 2000, and the findings of the Third Assessment Report of the Intergovernmental Panel on Climate Change, on circulation in draft form for final comments prior to its official release in January of 2001.
Despite the recent marked increase in natural gas prices in North America, the gas-fired combined-cycle process (NGCC) has cost advantages over the various coal-based options with or without the installation of additional equipment for the capture of carbon dioxide. Technical improvements are expected to reduce the costs of all options, but it is unclear these advances would necessarily change their relative ranking. Nevertheless, there are opportunities to link the use of coal with methane recovered from coal seams (CBM) for the generation of electricity.
There was general agreement among most authors at GHGT-51 as to the choice of the relevant technologies that might be applied in the immediate future for the capture of carbon dioxide released in the generation of electricity. There was somewhat more uncertainty concerning the techniques for sequestration of this gas once captured. The situation is now complicated (at least in North America) by the generally higher price for natural gas than the reference values used to calculate the results in several of the studies presented at the Conference. This paper was prepared to review the results published at GHGT-5 in the context of the increased price of natural gas in Canada and the U.S.
The North American gas market is steadily becoming more integrated. As the most recent example of these growing linkages, the Alliance Pipeline comes into service in late 2000 to move gas from North-Eastern B.C. to the Chicago district with the connecting Vector Pipeline starting deliveries to southwestern Ontario shortly thereafter. Late in 1999, the first gas from the Sable Island field off the Nova Scotia coast began serving the New England States. In the U.S., gas discoveries continue to be made in the Gulf of Mexico and some other regions. The four existing U.S. Liquefied Natural Gas (LNG) receiving ports in Massachusetts, Maryland, Georgia and Louisiana are becoming more active. It is possible exports will increase somewhat from Mexico to the U.S. in the next decades. Given continued high prices, it appears likely that at least one pipeline will be built to move gas south from reserves in both Alaska and the Canadian Arctic although at least six years will be needed before this new supply becomes available to markets in both countries.
As far as the supporting resource base is concerned, the National Energy Board, in its most recent assessment2 released in June of 1999, found that Canadian conventional natural gas production will peak in the 2008-13 range though higher than expected prices could delay the timing of this decline by encouraging greater supply. This report also identified methane recovered from coal seams (CBM) as the next likely source of major supply. This non-conventional option also requires continued high prices. (The U.S. currently derives about 5% of its gas production from coal beds.) On a world basis, the U.S. Geological Survey study of remaining natural gas resources released in June of 2000 identified large quantities though somewhat less than previous assessments.3 There may be ample supply from conventional sources on a world basis for many years to come but North America may have to turn to non- conventional supply for its incremental requirements in the next decades.
Three new sources of gas supply are considered in this paper. Both LNG and CBM are assumed available at $US3.50-4.00/GJ expressed on the LHV basis to be consistent with the process studies. Though the costs of these two new sources are in the same range, the location of the supply is very different. LNG is generally delivered to the end of long transcontinental pipelines where gas costs are highest due to the long distance from the gas fields and where the LNG may also serve as back-up storage to meet peak periods of demand. The exception is the LNG receiving facility in Lake Charles, La., which is at the supply end of the pipeline system. There are no LNG facilities on the Pacific Coast and there may be significant public opposition to any such new installations. LNG receiving facilities could be built at deep water ports in the Atlantic Provinces and the lower St. Lawrence region. In contrast, CBM activities would likely be mostly in Alberta although smaller-scale recovery is possible in Nova Scotia and perhaps New Brunswick. The combination of an incremental supply of natural gas from both LNG or CBM sources could conceivably cap the long-term price of gas at $US 3.50/GJ (expressed in $U.S. 2000) or a little higher. For this reason, this price is one of the two used to estimate the increase in the cost of electricity with higher prices for gas.
The price of natural gas could also be capped by the conversion of coal in synthetic production facilities (SNG). Coal resources are larger and generally more widely distributed than the other fossil fuels. One SNG facility is in operation in North Dakota based upon the large resources of low-cost lignite in that state. Carbon dioxide captured from this facility is now being pipelined to the Weyburn field in Saskatchewan for use in the enhanced recovery of oil. The construction of new such coal conversion facilities will likely require a stable price of some $US 5.00/GJ (LHV) which is significantly higher than the $US 3.50/GJ for LNG or CBM. There are no proposals known to build any such facility in North America at present. Nevertheless, this higher value is also used as a sensitivity case in Table 1 because the present prices on trading exchanges have at times recently approached the point at which such facilities could be contemplated.
For the case of coal, two values were used in Table 2, $US1.50/GJ LHV (as used in the reference paper4) and $US 1.00/GJ for the low-cost low-rank surface- mined coals consumed on or near site.
|Option||Technology||NG at $US|
|NG at $US|
A detailed break-down of the cost of generation was only provided for Options 1, 5 and the respective reference technologies. For this reason, fuel sensitivity values could only be calculated for those cases in Tables 1 and 2.
The five technologies did not include other important emerging options such as the retrofitting of existing power stations to coal/oxygen firing to lower the cost of capture of the carbon dioxide.6,7 Savings arising from improvements to chemical solvents of the MEA type were also not explored. These latter developments suggest generation costs may be somewhat less than given in Table 2 below.
|Option||Technology||Coal at $US|
The cost of electricity was always higher when provision was made for the capture of carbon dioxide as expected. With the fuel prices expected, the total electrical cost ranges from 3.1 to 6.9 U.S. cents/kWh for the various technologies equipped for the capture of carbon dioxde.The extra cost for capture ranged from 0.9 to 1.3 US cents/kWh in the natural gas cases and from 2.0 to 2.7 US cents/kWh in the coal cases. Costs were always lower for the NGCC options. For the cost of electricity generated in coal-based IGCC facilities equipped to capture carbon dioxide to equal that in natural gas-based NGCC facilities similarly equipped, the price of natural gas would have to be $US 6.31/GJ with coal at $US 1.00/GJ or $US 6.93/GJ for coal at $US 1.50/GJ. These equivalence values for natural gas prices seem high.
In another paper at GHGT-5, Jeremy David and Howard Herzog of M.I.T. also examined IGCC, PF, and NGCC technologies.8 These authors used somewhat different costs for fuel as perhaps appropriate to the U.S.: natural gas - $U.S. 2.78/GJ; coal - $U.S. 1.18/GJ. These authors found that the capture of carbon dioxide `increases the busbar electricity cost (COE) from 5.0 to 6.7 U.S. cents/kWh [at coal- based] IGCC plants, from 4.4 to 7.7 U.S. cents/kWh at [coal-based] PC plants, and, finally, from 3.3 to 4.9 U.S. cents/kWh at [natural gas-based] NGCC plants.' These authors conclude that today's capture technologies would add 1.5-2 U.S. cents/kWh to the busbar cost of electricity for either an IGCC or NGCC power plant. For a PC plant, the incremental cost of electricity would be over 3 U.S. cents/kWh. They conclude `the strongest opportunities for lowering the capture costs in the future were identified as gains in heat rates and reductions in the amount of energy required by the separation.' From the papers presented at Cairns, it is clear that the NGCC approach has a clear lead at the present time. Without carbon dioxide capture, the costs are low and emissions are of the order 370 grams of carbon dioxide per kWh. With capture, these emissions fall to 61-65 grams of carbon dioxide per kWh at costs lower than the two main coal alternatives even at projected increases in the price of natural gas combined with the lower coal costs expected in certain low-cost surface mining districts. Though technological advances are likely to reduce these estimates, it is far from clear the relative costs will be changed very much by these improvements.
For comparison, the cost of electricity from new nuclear facilities of current design is likely to be in the range 6.5-7 U.S. cents/kWh at present. Emissions of carbon dioxide chargeable to the full nuclear energy cycle would be small. Wind energy is probably feasible now at about 7 U.S. cents/kWh. Steady advances in both these technologies are to be expected over the next years but it is not clear these improvements will result in cost reductions greater than those to be expected over the same period in the carbon capture and sequestering sphere.
For this reason, an exploratory study10 was undertaken to explore how this technology might best be integrated with the generation of electricity with the production of hydrogen for other markets a possible option. This approach is particularly attractive in a carbon-constrained world since at least two moles of carbon dioxide are required to release one mole of methane from the coal seam.
Process considerations led to the proposal for a combined coal/methane option for the generation of electricity. Low-cost surface-mined coal, usually of sub-bituminous rank, would be gasified in an entrained flow reactor together with the crude methane recovered from the underground CBM operations. The product gas would be cleaned and shifted under pressure in the usual manner with much of the carbon dioxide separated by using a physical solvent. This captured carbon dioxide would be used to release the methane from the coal which is fed to the entrained reactor along with the entering coal. This combination may be attractive since the unit capital costs would be reduced for two reasons. First, the capacity of the entrained flow reactor is primarily set by its coal processing capacity. Adding the extra methane does not greatly increase the investment needed. Second, the product gas from the gasifier would be higher in hydrogen content than without the methane addition and thus less shifting capacity is needed per unit of production. This approach may be particularly attractive when a separate by-product hydrogen flow is also desired as an energy source for fuel cells, whether in mobile or stationary applications. There may, however, be limitations on the location of such facilities to avoid excess pipelining of the separated carbon dioxide to the CBM site and the return flow of recovered methane to the entrained-flow gasifier.
There is a special case for the generation of electricity from coal when it is linked to Coal Bed Methane (CBM) extraction techniques applied to both sequestering carbon dioxide and methane production that may be attractive in coal-rich regions such as Alberta.