Economics of CO2 and Mixed Gas Geosequestration of Flue Gas

Sep 14, 2005 - Greenhouse gas emission sources generally produce mixed gases. Previous studies of CO2 capture and storage have typically examined only...
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Economics of CO2 and Mixed Gas Geosequestration of Flue Gas Using Gas Separation Membranes Minh T. Ho,§ Greg Leamon,‡,§ Guy W. Allinson,§ and Dianne E. Wiley*,†,§ UNESCO Centre for Membrane Science and Technology, The UniVersity of New South Wales, Australia, School of Petroleum Engineering, The UniVersity of New South Wales, Australia, and Australian CooperatiVe Research Centre for Greenhouse Gas Technologies (CO2CRC), Australia

Greenhouse gas emission sources generally produce mixed gases. Previous studies of CO2 capture and storage have typically examined only sequestration of pure CO2. This paper analyzes the cost of separating a gas mixture from a power station flue gas stream and injecting it into an offshore subsurface reservoir. The costs of separating and storing various gas mixtures were analyzed at two extremes. One extreme in which the entire flue gas stream containing both CO2 and N2 is stored. The other extreme in which as much CO2 is separated as is technically possible using gas membrane capture coupled with chemical absorption. The results indicate that for the gases investigated, using a gas membrane capture system, the lowest sequestration cost per tonne of CO2 avoided occurs when a mixed gas with a CO2 content of about 60% is sequestered. Lower costs and higher tonnages of CO2 avoided can be achieved using an amine based absorption capture system. At the lowest cost point, and for most of the range of cases studied, the cost of capture is significantly greater than the cost of storage. However, this depends on the source of the CO2, the distance between the source and the injection site, and the reservoir into which CO2 is injected. Introduction Growing international concerns over the rising levels of atmospheric CO2 emissions and the resulting environmental and economic impacts present a challenge to industrial point sources of CO2 to stabilize these emission levels. One mitigation approach proposed is to capture the CO2 emissions and sequester the CO2 into geological formations.1 Since 1992, there have been several international studies investigating the cost of CO2 capture and subsequent storage.2-11 These studies examined the cost of separating the CO2 from a range of power plant flue gases using CO2 separation technologies such as chemical and physical absorption. The objective of these studies was to examine the economic feasibility and cost implications of sequestering CO2 in geological formations as a greenhouse gas mitigation option. Of the nine studies, only two examined the recovery of CO2 from flue gas using gas separation membranes,5,6 and these studies focused on the capture and subsurface storage of a pure stream of CO2. However, the stream of CO2 recovered using gas separation membranes is generally not pure CO2 but rather a stream of mixed gases enriched with CO2. Only a few studies12-14 have investigated the costs of storing other gases in conjunction with CO2. The objective of these studies however was to explore if geological storage of CO2 could also include other environmentally toxic gases such as NOx and SO2 rather than the component gases of the flue gas stream such as nitrogen or oxygen. In our previous work, it was demonstrated that storage of mixed gases is more expensive than storage of pure CO2. This is because larger volumes for mixed gases require larger pipelines and larger compressors.14 * To whom correspondence should be addressed. Tel.: +61 2 93854304. Fax: +61 2 9385-5966. E-mail: [email protected]. † UNESCO Centre for Membrane Science and Technology, The University of New South Wales. ‡ School of Petroleum Engineering, The University of New South Wales. § Australian Cooperative Research Centre for Greenhouse Gas Technologies.

Figure 1. Process scheme for CO2 capture and storage (CCS).

The aim of this study is to investigate if there exists an optimum gas mixture for recovered CO2 using gas separation membranes, for which the combined cost of capture and storage is the lowest. This study reports the results of a conceptual study investigating the recovery of CO2 from a flue gas stream of a typical Australian pulverized black coal fired power station and then injecting it into an offshore geological storage site. The cost estimates rely on computerized engineering and economic models for CO2 capture and storage developed especially for Australian conditions.14 These models enable estimation of the costs of CO2 and mixed gas capture and storage given any stationary source and sink combination in Australia. Concept Throughout this paper ‘CO2 capture’ is defined as the extraction of one or more gases from a mixed feed gas stream, and ‘storage’ encompasses the initial compression, transport, and injection of one or more gases into a subsurface reservoir. Depending on the location of the selected injection site, several additional compression stages may be required for transport. The whole process is defined as CO2 capture and storage (CCS) as shown in Figure 1. The conceptual basis for the analysis in this study is shown in Figure 2. The first option shown in Figure 2 (‘option A’) assumes that all of the flue gas (CO2 plus other gases) emitted from the source is stored. The feed gas is compressed,

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atmosphere and not captured. Therefore, they contribute to the total CO2 emissions of the system. The net tonnes of CO2 avoided is the difference between the tonnes of CO2 stored and the tonnes of CO2 emitted after capture. The percent CO2 avoided is calculated as

CO2 captured CO2 emitted from supplementary power % CO2 avoided ) CO2 original emission from source (1) The amount of recovered CO2 is the same as that stored in the subsurface. The Case Study We base our analysis on a 14-mole/volume % CO2 and 86 mole/volume % N2 feed gas mixture. This is close to the typical flue gas composition of 14% CO2, 81% N2, and 5% O2 for an Australian black coal fired power plant assuming that the gas has been dehydrated and that all of the SOx and NOx has been removed.6 For simplicity, we ignore the small amount of O2. The feed gas flow rate is taken as 5 million tonnes per year, containing 1 million tonnes per year of CO2 and 4 million tonnes of N2 on a mass basis. The inlet feed gas pressure is assumed to be atmospheric with an inlet temperature of 93 °C.5 CO2 Capture Using Gas Separation Membranes and Chemical Absorption Figure 2. Capture and storage options for CO2 mitigation.

transported, and then injected into the subsurface. Thus, there is no separation of the flue gas. This is one extreme of the range of options examined. ‘Option B’ in Figure 2 shows the other extreme, where 95% of the CO2 from the inlet feed gas is recovered and a gas stream of pure CO2 is compressed, transported, and injected. Other options between the two extremes are also examined in which varying portions of CO2 and other gases are separated and stored. In this study, it was assumed that the power requirement needed for the CO2 separation process and compression stages is provided from a supplementary power supply. This approach was taken rather than assuming that the base power plant and source of CO2 parasitically provided energy for the capture and storage process. This was done to ensure that the output from the power plant was maintained to the grid and that alternative sources of energy could be investigated as a power source to the capture and storage process. A standard assumption made purely for the purposes of this study is that the “auxiliary” energy will come from a new natural gas combined cycle power plant (‘NGCC’). This is because an NGCC plant has lower CO2 emissions than fossil fuel energy sources such as black or brown coal. The CO2 emissions from the NGCC power plant are fixed at 0.4 kg of CO2 per kWh.15 In practice, whether a new or existing power plant is used for supplementary power and what type of energy it uses will depend on the particular circumstances and location of the actual CCS scheme. While the choice of the auxiliary energy source will change the absolute costs of CCS, it does not affect significantly the relative costs of the different options considered here. Because the concentrations of CO2 in NGCC flue gases are lower, we assume that such CO2 emissions are vented to the

For the CO2 capture process, we investigate the use of gas separation membrane technology, coupled in some instances with chemical absorption. This allows us to model the capture of a wide range of gas mixtures with varying proportions of CO2 and other gases. The performance of gas separation membranes relies on the fact that different components in the gas mixture interact differently with the membrane material. One component in the flue gas (for instance, CO2) dissolves preferentially into the membrane and diffuses through it, giving the “product stream” or the “permeate”. Other gases also diffuse through the membrane and become part of the permeate, but they do so to a lesser extent. The portion of CO2 in the permeate is referred to as its “purity”. The gases that do not diffuse through the membrane are considered waste gases in this study and are emitted to the atmosphere. This includes the CO2 that does not permeate through the membrane. The waste gases therefore contain both CO2 and other gases. The extent of capture of the different components is governed partly by the selectivity of the membrane. A high selectivity for CO2 gives a higher concentration of CO2 in the permeate. However, as selectivity increases, the permeability usually becomes lower, and the rate of flow through the membrane decreases.6 A compromise between producing a high purity stream and sufficient flow rate is required. To enable us to estimate the cost of storage for a range of CO2 gas mixtures, we use both a one-stage membrane layout and a two-stage membrane layout for the separation process.16 The single one-stage membrane layout (Single Membrane System - “SMS”) shown in Figure 3 is the simplest. It comprises of only the flue (feed) gas compressor and the membrane, which incorporates both the membrane housing pipe work and the membrane fibers. The permeate from this layout is the mixed gas stream to be compressed for pipeline transport and geological storage. In practice, SMS layouts consist of many

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Ind. Eng. Chem. Res., Vol. 45, No. 8, 2006 Table 2. Operating Conditions for MEA Chemical Absorption System absorber pressure absorber temperature CO2 rich loading solvent loss due to SO2

1.2 bar 40 °C 0.4 mole CO2/mole MEA 1.6 kg MEA/tonne CO2 recovered

product stream.9 The capture of CO2 by chemical absorption is modeled using fundamental mass and energy balances as well as empirical relationships as described by Mariz.18-20 The key conditions assumed for the amine chemical absorption process are listed in Table 2.

Figure 3. Single-stage membrane system (SMS).

Transport and Storage

Figure 4. Two-stage cascade membrane system (TCMS). Table 1. Operating Conditions for Both SMS and TCMS Layouts feed pressure permeate pressure membrane temperature pressure of expanded waste gas

20 bar 1 bar 30 °C 1 bar

physical membrane modules operating in parallel. Conceptually, however, these modules operate as a single unit or stage and are modeled and costed as a single stage. One of the consequences of using gas separation membranes is that the permeate stream contains other component gases such as N2 as well as the desired CO2. To increase the concentration of CO2 in the gas stream sent to storage, the rich CO2 stream from the first membrane can be recompressed and then passed through a second membrane. This layout is referred to as a twostage cascade membrane system (TCMS) as shown in Figure 4. The TCMS layout incorporates a feed gas compressor, an intermediate compressor, and two membrane stages. The permeate from the second membrane is the mixed gas stream to be compressed for transport and storage. The TCMS yields low volumes of high purity CO2, while the SMS yields high volumes of low purity CO2. With these two membrane layouts, and using a polymer-based membrane, a mixed gas stream with a CO2 content ranging from 30% to 95% can be obtained. Higher concentrations of CO2 (almost 100% CO2) can be achieved using chemical absorption as a stand-alone system or in combination with gas separation membranes. The capture of CO2 by gas separation membranes is modeled using the numeric cross-flow permeation model described by Shindo et al.17 For this study, the properties of a polymer based polyphenyleneoxide hollow fiber membrane with a CO2/N2 selectivity of 20 and a CO2 permeability of 72 Barrer and a membrane thickness of 0.125 µm were used. The operating conditions for the membrane systems are listed in Table 1.4,5 In this paper we also compare the costs of the membrane systems with a monoethanolamine (MEA) chemical absorption process. The MEA system typically removes 75-90% of the CO2 from the feed gas and produces a near pure (>99%) CO2

Earlier work by Geoscience Australia has shown that over 60 geological sites in Australia are suitable for geological storage of CO2.20 For the purposes of this study, we assume that the storage site is located offshore and transport of the gas to the site will be by both land and seabed pipelines as well as offshore platforms hosting injection wells and ancillary equipment. As part of the process scheme, the gas stream is first compressed to between 1250 and 2500 psi (86-172 bar). At these pressures, the CO2 is in a supercritical state, giving a reduced volume ready for transport. In our example, recompression is required at the junction of the onshore and offshore pipelines. The gas is then piped to an offshore platform in 60 m of water, from where the gas is injected into a sandstone reservoir at a depth of some 2000 m below sea level. Table 3 lists our main assumptions for the storage operation. The cost outputs of the economic model for Australian CO2 storage depend on both the conditions of the selected reservoir and distance between the CO2 source and storage site. This storage site was selected due to its proximity to nearby Eastern Australian CO2 sources such as power generators and industrial plants and its large capacity. Details of the processing assumptions and calculations for the storage economic model are presented in ref 22. Cost Estimates Estimates of the cost of equipment items were obtained mainly from equipment vendors, publications, and industry contacts.10,19-20,24 The breakdown of total capital costs and operating costs is based on chemical engineering estimating procedures.25 The membrane costs are based on the procedure described by van der Sluijs et al.26 All cost estimates are in U.S.$ in the year 2004. Other economic assumptions are consistent with those of Allinson and Nguyen14 and Hendriks6 and are listed in Table 4. The real cost of CO2 capture and storage in U.S.$ per tonne of CO2 avoided is estimated as n

cost of CO2 avoided )

∑ i)1

Ki + Oi

(1 + d)i (2)

n

∑ i)1

(CO2 avoided)i (1 + d)i

where Ki and Oi are the real capital and operating costs (U.S.$ million) in the ith year, d is the discount rate (% pa), and CO2 avoided is the annual amount of CO2 avoided in million tonnes.

Ind. Eng. Chem. Res., Vol. 45, No. 8, 2006 2549 Table 3. Summary of Inputs for the Storage Model reservoir onshore pipe length offshore pipe length water depth reservoir depth reservoir thickness reservoir temperature reservoir pressure average reservoir permeability reservoir radius

Gippsland 110 km 60 km 60 m 2063 m 120 m 85 °C 3154 psia 1500 mD 9.0 km

Table 4. Summary of Economic Inputs for the Capture and Storage Models discount rate cost of external power fixed annual operating cost project life construction period membrane cost

7% pa 20 $/MWh 4% of total capital costs 20 years 2 years 150 $/m2

We assume that operating costs for storage are sufficient to cover the costs of monitoring the CO2 storage system. Monitoring activities involve seismic surveys, well logging, and reservoir analysis. Results The costs shown in this paper are for a hypothetical mixed gas stream comprising 1 MM tonnes of CO2 and 4 MM tonnes of other gases. Scaling these volumes up or down would yield different absolute costs. In particular, because of economies of scale, larger volumes would, in general, lower the cost per tonne avoided for both capture and storage. For instance, the costs of storage would fall significantly compared to the costs shown here. However, this feature of the analysis does not alter our main conclusions, which are based on the relative movements in costs per tonne avoided as we change the gas composition of the output of the capture process. Purity. The relationships between the rate of CO2 recovered from the feed gas, the total amount of CO2 avoided, and purity of the product obtained using the SMS and TCMS layouts for gas separation membranes are shown in Figure 5. The results show that the different layouts produce vastly different product purities (around 30%) at similar levels of CO2 recovery and

Figure 5. CO2 avoided as a function of the percentage of CO2 in the product for both the SMS (s) and TCMS (- - -) layouts.

Figure 6. The capture, storage, and total cost using gas separation membranes, SMS (s) and TCMS (- - -).

CO2 avoided. The TCMS layout is more suited to applications where a high product purity of CO2 is required. Using the TCMS layout, CO2 purities of greater than 65% are obtained with CO2 recoveries of 60-90%. However, to achieve even higher levels of CO2 purity in the permeate (greater than 90%), the corresponding CO2 recovery from the feed gas would be less than 75%. In contrast, the SMS layout yields higher removal efficiencies but lower product purity. To recover 70-90% of the CO2 from the feed gas using the SMS layout, the purity of the enriched CO2 permeate is only 30-60%. Costs of SMS and TCMS Compared. Figure 6 shows the capture, storage, and total costs of sequestering streams of CO2 enriched mixed gases. The capture costs are shown for both gas separation membrane layouts, SMS and TCMS. Because the two layouts generate permeates with vastly different CO2 purity levels there is a difference in the costs for both storage and capture for the two systems. Although the total costs for both layouts are similar, the results in Figure 6 show that the SMS has a lower capture cost than the TCMS layout. Feron5 also showed in his work on CO2 capture from flue gas that the SMS layout has the lowest compression costs, membrane area requirement, and operating costs of different membrane layouts. From Figures 3 and 4, the TCMS layout contains an additional compressor compared to that of the SMS as well as an extra membrane stage. These extra equipment components add to the total capital costs and hence the higher capture cost for the TCMS layout. However, the storage cost for the SMS layout is higher than for the TCMS layout at all rates of CO2 recovery and CO2 avoided studied. This occurs because the product stream contains a lower volume percentage of CO2 than for the TCMS layout. Figure 5 shows that at equivalent amounts of CO2 avoided, the quantity of N2 to be stored along with the CO2 is also considerably higher in the SMS layout than in the TCMS layout. The larger volume to be stored increases the size of the transport pipeline and storage compressors required, resulting in higher capital and hence storage costs.

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Figure 7. The total capital and annualized operating costs for a SMS recovering 80% CO2.

Figure 8. The behavior of cost for capture and storage, as a function of CO2 avoided for gas separation membranes, MEA absorption, no ‘capture’, and maximum capture (95% CO2 recovered).

Interestingly, for both membrane systems the total capture plus storage cost is similar, regardless of the differences in the capture and storage costs. The total costs are influenced by many factors including the properties of the site selected for storage, the distance between the source and storage, and the processing and economic assumptions. Further study investigating the total end-to-end costs using different membranes, with different processing and economic assumptions, needs to be undertaken to confirm the effect of the layouts on the total capture and storage cost. Economies of Scale. The results in Figure 6 show that, for low amounts of CO2 avoided and hence low CO2 removal rates (below 0.5 million tonnes), the total cost is dominated by the capture component. With increasing CO2 recovery rates and CO2 avoided, the capital cost increases due to an increase in the membrane area required for separation. For membrane capture systems, the cost of the compressors needed for feed gas compression dominates the capital costs, which can account for up to 80% of the total capital cost.6 This is confirmed in Figure 7 where the capital and operational breakdown using a SMS for 80% CO2 recovery is shown. The dominant capital cost components are the compressor and expanders (60%), with the membrane cost making up less than 10% of the total. Since the membrane cost is only a small proportion of the total capital cost, and the tonnage of CO2 sequestered changes by significantly more than the change in capital cost, the overall capture cost per tonne of CO2 avoided decreases as the amount of CO2 avoided increases. In other words, there are economies of scale, which result in a decrease in the cost of capture per tonne of CO2 avoided. Costs of Storage. At low values of CO2 avoided, less than 0.5 million tonnes of CO2 avoided, the cost of storage remains relatively low and constant. This is because as seen in Figure 5, at these rates of CO2 avoided the percentage of CO2 in the product stream is relatively high. The purity of CO2 in the enriched stream to be stored is greater than 55% in the SMS and greater than 80% in the TCMS. For the SMS layout, the storage cost increases by 10% at 0.55 million tonnes CO2 avoided compared to the cost at 0.5 million tonnes of CO2

avoided. This is because at a CO2 avoided of 0.55 million tonnes, the purity of the CO2 is less than 50% in the permeate. The larger gas volume of the stream requires significantly more compression adding to both the capital and operating costs. Therefore, for mixed gases containing less than 50% of CO2 by volume, the high cost of compression and storage makes geosequestration costly. Costs of Capture and StoragesThe Extremes. Figure 8 shows how the total costs of capture and storage vary as the mass of CO2 avoided increases for the SMS gas separation membranes, chemical absorption, no capture (option A in Figure 2) and for 95% recovery of CO2 as in option B of Figure 2. The “no capture” option sequesters the entire flue gas streams1 million tonnes of CO2 plus 4 million tonnes of N2. However, the power required to compress and transport such large volumes of gas generates a large amount of CO2 (approximately 0.5 million tonnes). Therefore, the total CO2 avoided is only 0.5 million tonnes per annum (50% of the CO2 in the flue gas). In sum, the “no capture” process is able to store very large volumes of CO2, but only a modest level of CO2 avoided is achieved and the cost per tonne of CO2 avoided is also very high.12 At the other end of the spectrum, with “95% recovery”, almost all of the CO2 is separated using a combination of membranes and MEA chemical absorption prior to storage. In this option, 0.95 million tonnes of CO2 and no N2 is sequestered. However, again large amounts of CO2 are generated: - 0.55 million tonnes of CO2 per annum from the multiunit capture system and 0.05 million tonnes from the storage system. Therefore, the amount of CO2 avoided is only of the order of 0.4 million tonnes (40% CO2 avoided), and the costs per tonne of CO2 avoided are high. Thus, both of the ‘extremes’ where all the CO2 in the flue gas stream is geologically stored are very costly and yield very low rates of CO2 avoided. The two extremes store a large amount of CO2 but with significant disadvantages. Costs of Capture and StoragesThe Optimum. In Figure 8, the lowest total cost using a membrane capture system occurs

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at 0.55-0.6 million tonnes CO2 avoided. As shown in Figure 5, at this point the amount of CO2 sequestered is also at a maximum; for this studys90% of the feed gas CO2 is recovered storing 0.9 million tonnes of CO2 per year. To power the capture and storage facilities, 0.3 million tonnes of CO2 is emitted from the auxiliary power supplies for capture and storage. This gives a maximum CO2 avoided of 0.6 million tonnes (60% of the CO2 in the flue gas stream). For the membrane system considered in this study, to be able to increase the avoidance value beyond 60% would require using an auxiliary power supply with lower emission rates and/or processing equipment with higher operating efficiency. Membranes vs MEA. The costs of CO2 mitigation utilizing MEA is also shown in Figure 8. In comparison to the membrane system, this process yields approximately 0.75 million tonnes of CO2 avoided (75% of the CO2 in the flue gas stream) at a maximum CO2 recovery of 90%. This compares with 0.60 million tonnes of CO2 avoided for the optimum membrane system. The capture cost of the amine based chemical absorption system is lower than for the membrane system for most CO2 avoided rates. This is because the large costs of the compressors in the membrane system make capital and operating costs greater than in the MEA system. In this study, the cost to power the compressors is approximately 40% of the total operating cost (Figure 7). Other investigations have reported energy consumption of MEA systems to be between 20 and 30% of the operating costs.9-11 In addition, the storage costs for the MEA system are substantially lower than for the membrane system. This is because the stored gas produced by the absorption system is a small volume of highly purified CO2. Allinson and Nguyen14 showed previously that the storage of pure CO2 is considerably less than mixed gas storage. The effect is that the total cost of sequestering a relatively pure stream of CO2 generated by MEA chemical absorption is less costly than sequestration of a mixed gas product stream produced using gas separation membranes. Comparison with Other Studies There have been are numerous published studies examining theeconomicsofCO2 capturefromcoal-firedpowerplants1-11,15,19,26 as well as studies examining the economics of CO2 storage.12-14,22 However very few studies have examined the total costs of endto-end capture and storage costs for specific cases. The study by Dave et al.3 is the only specific study of CO2 capture and storage for Australian conditions. The capture costs from this paper using gas separation membranes and MEA chemical absorption will be compared to those of Hendriks6 and the International Energy Agency’s5 as these studies have investigated capture cost using both membranes and chemical absorption. Figure 9 compares the capture costs in terms of U.S. $/tonne CO2 avoided for a CO2 recovery rate of 80%. For the gas separation membranes, the results show that the reported capture cost for the IEA study of $45/tonne CO2 avoided is lower than this study, even though similar conditions were used. This difference is because the IEA study only considered the change in CO2 emissions at the power plant without including any additional power losses that may be incurred for the transportation and storage. In this study, for a CO2 recovery rate of 80%, the CO2 avoided due to power losses in the capture plant is approximately 76% for the SMS and 70% for the MEA system, the rest of the power loss being for compression, transportation, and storage. If this additional power loss is taken into account,

Figure 9. Comparison of CO2 capture costs for gas separation membranes and MEA.

the amount of CO2 avoided is much lower than for the capture plant alone. If transport and storage power losses were taken into account for the IEA study, the capture cost would increase to $53/tonne CO2 avoided for the membrane system. Alternatively, if the power losses for transport and storage were neglected in this study, the capture cost decreases to $47/tonne CO2 avoided. The rest of the difference is the result of differences in economic assumptions such as operating capacity and cost for power. In comparison, the capture costs for the membrane system studied by Hendriks6 include some of the costs for CO2 transport and compression to 80 bar and accounts for the additional power consumption due to the compression. This compression cost however does not take into account the full transportation and associated storage costs. These three studies have been conducted at different levels of complexity and due to the different economic assumptions used such as discount rates, plant capacity, and choice of transport costs; the absolute costs are not directly comparable. Further study into the effect of different accounting methodologies and the effect of processing and economic assumptions on the capture and storage costs is required. Conclusion Sequestration of CO2 from stationary source emitters can be applied either with no capture of any gases from the feed gas stream, or it can include varying degrees of CO2 capture. The results in this paper indicate that storage of an entire flue gas stream, where CO2 comprises only a small proportion of the total mass/volume, is not as economically attractive as some form of separation to increase the concentration of CO2 in the gas prior to storage. Similarly, at the other extreme for 95% CO2 recovery, the cost for capture is also prohibitive. For the gas separation membrane cases studied, the lowest cost of capture and storage occurs when approximately 60% of the CO2 is avoided. In comparison, an amine based absorption capture system is able to achieve a higher rate of 70% CO2 avoided at an even lower cost. The results suggest that at the lowest cost point and over most of the range of cases studied here, the cost of capture is significantly greater than the cost of storage. However, in practice this would depend on the source of the CO2, the distance between the source and the injection site, and the reservoir into which the CO2 is injected.

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Acknowledgment This research was supported by the Australian Cooperation Research Centre for Greenhouse Gas Technologies (CO2CRC). Literature Cited (1) Herzog, H.; Drake, E.; Adams, E. CO2 capture, reuse and storage technologies for mitigating global change: a white paper, final report; DOE Order Number DE-AF22-96PC01257; Energy Laboratory, Massachusetts Institute of Technology: Cambridge, MA, 1997. (2) Audus, H. Leading Options for the Capture of CO2 at Power Stations. In Proceedings of the Fifth International Conference on Greenhouse Gas Control Technology (GHGT-5), Cairns, Australia, 2000. (3) Dave, N.; Duffy, G.; Edwards, J.; Lowe, A. Economic evaluation of capture and sequestration of CO2 from Australian black coal-fired power stations. In Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies (GHGT-5), Cairns, Australia, 2000. (4) David, J.; Herzog, H. The cost of carbon capture. In Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies (GHGT-5), Cairns, Australia, 2000. (5) Feron, P. CO2 Capture: The characterisation of gas capture/remoVal membrane systems applied to the treatment of flue gases arising from power generation using fossil fuel; IEA Greenhouse Gas R&D Programme Report IEA/92/OE8, Cheltenham, England, 1992. (6) Hendriks, C. Carbon dioxide RemoVal from Coal-fired Power Plants; Kluwer Academic Publishers: The Netherlands, 1994. (7) Masaki, I.; Takashi, K. Flue gas CO2 recovery and compression cost study for CO2 enhanced oil recovery. In Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies (GHGT6), Kyoto, Japan, 2002. (8) Reiner, P.; Audus, H.; Smith, A. Carbon Dioxide Capture from Power Plants; IEA GHG Report; Cheltenham, England, 1992. (Available at: www.ieagreen.org.uk/capt1.htm) (9) Rubin, E.; Roa, A. B.; Berkenpas, M. B. A technical, economic and environmental assessment of amine-based CO2 capture technology for power plant greenhouse gas control. EnViron. Sci. Technol. 2002, 36, 4467. (10) Simbeck, D. R. CO2 mitigation economics for coal-fired power plants. First Conference on Carbon Sequestration, Washington, U.S.A., 2001. (11) Singh, E.; Croiset, E.; Douglas, P.; Douglas, M. Techno-economic study of CO2 capture from an existing coal-fired power plant: MEA scrubbing vs O2/CO2 recycle combustion. Energy ConVers. Manage. 2003, 44, 3073. (12) Lavalin, S. N. C. Impact of impurities on CO2 capture, transport and storage; IEA Greenhouse Gas R&D Programme Report PH4/32; Cheltenham, England, 2003.

(13) Anheden, M. Considerations regarding CO2 purity required for CO2 capture and storage. Poster at the SeVenth International Conference on Greenhouse Gas Control Technologies (GHGT-7), Vancouver, Canada, 2004. (14) Allinson, G.; Nguyen, V. CO2 geological economics. In Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies (GHGT-6), Kyoto, Japan, 2002. (15) Narula, R. G.; Wen, H.; Himes, K. Incremental cost of CO2 reduction in power plants. In Proceedings of ASME Turbo Expo 2002, Amsterdam, The Netherlands, 2002. (16) Wiley: D. E.; Fell, C. J. D.; Fane, A. G. Optimisation of membrane module design for brackish water desalination. Desalination 1985, 52, 249. (17) Shindo, Y.; Hakuta, T.; Yoshitome, H. Calculation methods for multicomponent gas capture by permeation. Sep. Sci. Technol. 1985, 20(5&6), 445. (18) Aroonwilas, A.; Tontiwachwuthikul, P.; Chakma, A. Effects of operating and design parameters on CO2 absorption in columns with structured packings. Sep. Purif. Technol. 2001, 24, 403. (19) Chapel, D.; Mariz, C.; Ernest, J. RecoVery of CO2 from flue gases: commercial trends; Canadian Society of Chemical Engineers: Saskatoon, Canada, 1999. (20) Mariz, C. L. Carbon dioxide recovery: large scale design trends. J. Can. Pet. Technol. 1998, 37(7), 42. (21) Bradshaw, J.; Bradshaw, B.; Allinson, G.; Rigg, A.; Nguyen, D.; Spencer, L. The potential for geological sequestration of CO2 in Australia - preliminary technical and commercial findings. APPEA J. 2002, 42(1), 25. (22) Allinson, G.; Nguyen, D. The Economics of CO2 sequestration in Australia. In Proceedings of the Filth International Conference on Greenhouse Gas Control Technologies (GHGT-5), Cairns, Australia 2000. (23) Allinson, G.; Nguyen, D.; Bradshaw, J. The economics of geological storage of CO2 in Australia. APPEA J. 2003, 35(6), 623. (24) Stanwell Corporation. Personal communication, 2003. (25) Peters, M.; Timmerhaus, K. Plant Design and Economics for Chemical Engineers; McGraw-Hill: New York, 1980. (26) Van Der Sluijs, J. P.; Hendriks, C. A.; Blok, K. Feasibility of polymer membranes for carbon dioxide recovery from flue gases. Energy ConVers. Manage. 1992, 33(5-8), 429.

ReceiVed for reView May 12, 2005 ReVised manuscript receiVed July 26, 2005 Accepted July 28, 2005 IE050549C