920
Energy & Fuels 2007, 21, 920-926
Economics of CO2 Capture Using the Calcium Cycle with a Pressurized Fluidized Bed Combustor A. MacKenzie,† D. L. Granatstein,‡ E. J. Anthony,*,§ and J. C. Abanades| Neill and Gunter Limited, 845 Prospect Street, Fredericton, New Brunswick, Canada E3B 2T7, Granatstein Technical SerVices, 489 1/2 Cooper Street, Ottawa, Ontario, Canada K1R 5H8, CETC-Ottawa, NRCan/RNCan, 1 Haanel DriVe, Ottawa, Ontario, Canada K1A 1M1, and Instituto Nacional del Carbo´ n-CSIC, Fco Pintado Fe 26, 33011 OViedo, Spain ReceiVed July 21, 2006. ReVised Manuscript ReceiVed October 30, 2006
Flue gas CO2 capture using a Ca-based chemical looping system has been shown to be potentially more cost-effective than traditional amine-based systems in bench-scale testing. The results of these initial tests are projected, using an Excel-based economic model, to estimate the 30-year levelized cost of CO2 capture per metric ton (t) for a utility-scale power plant. An order of magnitude capital and operating estimate for a 360 MW pressurized fluidized bed combustor (PFBC) is presented, assuming a western Canadian location. Additional costs for calciners, O2 plant, and related equipment necessary to create a Ca-based CO2 chemical capture loop are presented separately. These costs are evaluated in a series of spreadsheets, and the impact of process flows, as well as capital, operating/maintenance, and feedstock costs are determined in a sensitivity analysis. The financial results for CO2 capture are found to compare favorably with amine-based capture systems.
Introduction There is general agreement in the scientific community that climate change is a serious threat to the world’s biological and economic health and that increased atmospheric CO2 is a significant contributor to this trend.1 At the same time, a majority of the world’s energy needs are supplied by fossil fuels that produce CO2. A move to less harmful “green” energy sources is possible, and efficiency gains can be introduced to lower CO2 per unit of energy output, but these will only have a limited impact on total CO2 production. On the other hand large-scale and rapid reduction in CO2 emissions by changing the world’s energy mix will result in dramatic economic penalties. The middle ground can be reached by development of economic CO2 capture technologies that allow existing fossil fuel-powered generation facilities to operate while restricting CO2 emissions. Currently there are a limited number of commercial CO2capture technologies, primarily developed by the chemical and oil industries to remove hydrogen sulfide and CO2 contaminants from gas streams. These processes have also been used to isolate limited amounts of CO2 for the food and related industries. They result in significant energy penalties and costs when scaled up to capture the large CO2 volumes emitted from power plants.2 The need for economic and dependable ways to capture large quantities of CO2 has led to the development of numerous emerging technologies involving adsorption, absorption, membrane separation, cryogenics, and O2/CO2 recycling. * To whom correspondence should be addressed. E-mail: banthony@ nrcan.gc.ca. Phone: (613) 996-2868. Fax: (613) 992-9335. † Neill and Gunter Ltd. ‡ Granatstein Technical Services. § CETC-Ottawa. | Instituto Nacional del Carbo ´ n-CSIC. (1) Metz, B., Davidson, O., de Coninck, H., Loos, M., Meyer, L., Eds. IPCC Special Report on Carbon Dioxide Capture and Storage; Cambridge University Press: Cambridge, U.K., 2005. (2) Simmonds, M.; Hurst, P.; Wilkinson, M. B.; Watt, C.; Roberts, C. A. Amine Based CO2 Capture from Flue Gas; Gas Processors Association Europe: Fleet, Hampshire, U.K., 2002.
The most common of these commercially developed methods involves scrubbing the gas with a chemical solvent such as monoethanolamine (MEA), which has been successfully used in the oil and chemical industries for over 60 years. However, amines can be expensive and suffer from several potential problems. Flue gases can contain significant concentrations of SO2, SO3, and NO2 that react irreversibly with amines to produce non-reclaimable and potentially corrosive salts, and hot flue gas can cause solvent degradation and decrease the absorbent’s efficiency. Much research has been done in recent years to develop less-expensive solvents with higher CO2-absorption capacities, faster CO2-absorption rates, greater resistance to degradation, and lower regeneration costs. The Fluidized Bed Combustion Group of Natural Resources Canada, CANMET Energy Technology Centre-Ottawa (CETC-O), along with its partners the Spanish Research Council (CSIC)3 and the University of British Columbia (UBC) are investigating the use of lime (from limestone) as an effective, inexpensive chemical sorbent. Other workers are also exploring the use of lime-based sorbents for CO2 removal in the combustion environment.4 Bench-scale test results have shown Ca-based sorbents to be promising substitutes for traditional amine-based systems with excellent CO2 capture and release characteristics, which are able to effectively remove CO2 in a fluidized bed environment.5,6 As part of this ongoing effort, an order of magnitude economic study was carried out on a calcium-based chemical looping (3) Abanades, J. C.; Anthony, E. J.; Alvarez, D.; Lu, D. In Proceedings of the 17th International Conference on Fluidized Bed Combustion; Jacksonville, FL, May 2003, 18-20; Pisupati, S., Ed.; American Society of Mechanical Engineers: New York, 2003; Paper 10. (4) Fennell, P. S.; Pacciani, R.; Davidson, J. F.; Dennis, J. S.; Hayhurst, A. N. The Use of Limestone Particles for the Capture of CO2: Its Initial Reactivity and Loss of Reactivity after Repeated Cycles of Calcination and Carbonation. Presented at FBC19, Vienna, Austria, May 21-24, 2006. (5) Salvador, C.; Lu, D.; Anthony, E. J.; Abanades, J. C. Chem. Eng. J. 2003, 96, 187-195. (6) Abanades, J. C.; Anthony, E. J. Lu, D.; Salvador, C.; Alvarez, D. AIChE J. 2004, 50, 1614-1622.
10.1021/ef0603378 CCC: $37.00 © 2007 American Chemical Society Published on Web 02/03/2007
Economics of CO2 Capture
Energy & Fuels, Vol. 21, No. 2, 2007 921
Figure 1. Calcium sorbent cycle for carbon dioxide capture.
system in combination with a pressurized fluidized bed combustor (PFBC). Here we have not considered the possibility that sorbent reactivation may be used to enhance limestone performance over multiple cycles, although there are preliminary results that suggest average utilizations of 50% or more over 20 cycles may be possible.5,7
Table 1. Project Capital Cost item no. 1 2 3 4
Plant Description The power plant was assumed to be a 360 MW PFB combined cycle constructed in a western Canadian location. The basic calcium cycle used for the estimate is shown in Figure 1, and the capital cost summary, listing the main plant components, is given in Table 1. There are two possibilities for CO2 removal: either CO2 is removed in the PFBC itself, or as has been evaluated in the concept plant, flue gas from the combustor is directed through the gas turbine and heat exchangers, before passing through a series of carbonators at a temperature of 650-700 °C. CO2 in the flue gas will readily react with CaO in the carbonator to form calcium carbonate (CaCO3) in an exothermic reaction. The resulting CaCO3 is then directed to a series of calciners, where a high-carbon fuel such as petroleum coke or anthracite coal is burned in an oxygen atmosphere. This provides the heat needed to reverse the carbonation reaction and release the CO2 captured earlier. The calciner exhaust gases will be highly concentrated CO2 suitable for storage, use, or further treatment. The oxygen required in the calciners is only 1/3 that required for an oxyfuel process, reducing air separation unit (ASU) capital and operating costs accordingly. Heat released during the carbonation process and generated in the calciners can be directed to the steam cycle to improve overall plant efficiency. It is estimated that a realistic CO2 capture rate of up to 78% is possible in the carbonator using CaO as a sorbent,6,8 as well as 100% of the CO2 generated in the calciner, resulting in an overall capture/ removal of approximately 85% of the total CO2 produced. Specific key assumptions include the following. Facilities and Capital Cost. (1) The PFBCC plant components were modeled after the Karita Unit 1 power station, owned by Kyushu Electric Power Company, Japan, consisting of an ABB P800 combustor module and an Alstom GT140P gas turbine. (2) The plant cost estimate is based on a western Canadian location, and the figures are in 2005 Canadian dollars. Since an actual site has not been chosen, site-specific conditions have not been incorporated into the cost analysis. (3) The accuracy (7) Hughes, R. H.; Lu, D.; Anthony, E. J.; Wu, Y. Ind. Eng. Chem. Res. 2004, 43, 5529-5539. (8) Abanades, J. C.; Anthony, E. J.; Wang, J.; Oakey, J. E. EnViron. Sci. Technol. 2005, 39, 2861-2866.
5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37
description process plant coal receiving, storage, and reclaiming limestone receiving and storage system coal and limestone handling systems fuel/sorbent preparation and delivery system PFBC module gas turbine and auxiliaries steam turbine and auxiliaries calciner/carbonator modules generators (gas & steam) O2 plant balance of plant general site preparation (greenfield) roads, retaining walls, fences, gates, and railings raw water supply and treatment sewage and treatment systems chemical waste water treatment systems auxiliary fuel systems main powerhouse building calciner/carbonator buildings auxiliary structures building auxiliary systems stack and foundations compressed air system interconnecting piping cooling water system fire fighting system ash collection and handling systems particulate collection system instrumentation, controls, and communications electrical switchyard/distribution environmental monitoring electric power and control systems, general engineering, PM, construction mgmt., and site commissioning costs spare parts costs field supervision interest capitalized construction overheads project weighted total project dollars per kilowatt calciner and calciner building cost calciner and calciner building cost as a percentage of total direct costs calciner and calciner building cost including indirect costs
total cost $8,600,000 $6,500,000 $9,000,000 $10,000,000 $162,000,000 $38,800,000 $45,600,000 $45,000,000 $30,000,000 $40,000,000 $7,000,000 $2,000,000 $5,000,000 $500,000 $2,500,000 $1,300,000 $50,000,000 $14,000,000 $15,000,000 $1,500,000 $9,500,000 $2,500,000 $6,000,000 $46,300,000 $1,500,000 $12,200,000 $17,200,000 $11,500,000 $7,200,000 $1,200,000 $8,000,000 $50,000,000 $12,700,000 $2,000,000 $24,000,000 $44,000,000 $20,000,000 $770,100,000 $2,139.20 $99,000,000 16.03% $123,485,423
of the capital cost estimate is believed to be +50/-30% (including contingency), in line with an order of magnitude study. Most costs were based on parametric estimation tech-
922 Energy & Fuels, Vol. 21, No. 2, 2007
MacKenzie et al. Table 2. Input and Output Summaries input
net plant size (MW) in-service date total heat rate (kJ/kWh) debt financing preferred share financing common share financing return on debt return on preferred shares return on common shares weighted cost of capital inflation rate Ca/S ratio Ca/C ratio CO2 captured in combustora (%) SO2 captured (combustor and calciner) (%) CO2 credit ($/t) SO2 credit ($/t) CO2 credit esc. rate (%)
plant data 360 electric generation efficiency (%) 2007 capacity factor (%) 8845 financial data (%) 50.0 interest on sinking funds 10.0 sinking fund factor 40.0 fed tax rate (preferred) 7.0 fed tax rate 5.0 capital tax rate 10.0 Alberta tax rate 8.0 capital cost allowance (class 1) 1.5 plant operations 1.2 SO2 credit esc. rate (%) 4 recycle from calciner (%) 78.6 CaO deactivation rate (%) 90.0 O2 plant auxiliary power demand (MW) 5.00 calciner operation cost (% plant O&M) 0.50 calciner fuel (% plant fuel) 1.5 calciner energy loss (% calciner fuel)
40.7 80
6.5 1.05 40.0 28.0 0.225 14.5 4.0
1.5 92.5 15 32.0 25.0 30.0 10
ouput limestone purity (% CaCO3) cost ($/t)
92.0 25.00
cost escalation rate (%)
1.5
fuel: coal coal used as fuel (%) heat content (kJ/kg) carbon content (%) ash content (%)
0.0 29500 70.0 5.0
sulfur content (%) cost ($/GJ) cost escalation rate (%)
3.0 3.40 1.0
petroleum coke used as fuel (%) heat content (kJ/kg) carbon content (%) ash content (%)
fuel: petroleum coke 100 sulfur content (%) 32000 cost ($/GJ) 88.0 cost escalation rate (%) 0.5
4.0 1.80 1.0
capital costs project capital cost ($M) decommissioning cost (% of capital)
770.1 4.0
core staff costs ($k/a)
fixed O&M costs 635.0
annual maintenance ($/MWh) O&M escalation (%) water content of ash (%)
project life (years)
variable O&M costs 4.0 waste disposal cost/creditb ($/t) 1.5 waste disposal esc rate (%) 10.0
30
-0.7 1.0
plant outputs fuel consumption (combustor kt/a) fuel consumption (calciner kt/a) energy production (GWh/a) CO2 capturedc (kt/a) CO2 released (kt/a) SO2 capturedd (kt/a) SO2 released (kt/a) CaO required for CO2 (kt/a)e capital operating (including credits) limestone
488.1 209.2 2522.9 1913.1 337.1 50.2 5.6 8018.7
CaO required for SO2 (kt/a) effective CaO recycled (kt/a) unreactive CaO recycled (kt/a) CaSO4 recycled (kt/a) ash recycled (kt/a) fresh limestone usage (kt/a) waste production (kt/a)
30-year levelized costs (¢/kWh) total plant 2.731 fuel 0.139 taxes 0.931 total
30-year levelized costs (¢/kWh) calciner, O2 plant, and associated equipmentf capital 0.438 taxes operating 0.116 CO2 credit fuel (associated with C capture) 0.052 total 0.870 limestone (assoc with C capture)g capital operating (including O2 plant) fuel limestoneg
30-year levelized cost of CO2 capture ($/t CO2)f 5.776 taxes 9.588 CO2 credit 0.692 total 11.469
58.6 7599.2 1340.0 1315.9 43.0 814.3 835.0
1.750 0.919 6.471 0.147 -0.438 1.186
1.943 -5.771 23.697
a Assumes this percentage of combustor CO + 100% of calciner CO is captured. b Negative sign indicates a credit. c Total CO captured in combustor 2 2 2 and calciner. d Total SO2 captured in combustor and calciner. e CaO quantity includes recycled material. f Includes capital and operating costs of calciner and associated equipment only. g Assumes SO2 control alone would require Ca/S ratio of 1.2.
Economics of CO2 Capture
Energy & Fuels, Vol. 21, No. 2, 2007 923 Table 3. 30-Year Project Capital Charges project capital charges ($ × 1000)
year
capital
0 1 2 3 4 5 10 20 30
770,100
totals NPV
770,100
depreciation
debt interest
P shares
PS dividends
C Shares
CS dividends
25,670.0 25,670.0 25,670.0 25,670.0 25,670.0 25,670.0 25,670.0 25,670.0
26,953.5 26,055.1 25,156.6 24,258.2 23,359.7 18,867.5 9,883.0 898.5
77,010.0 74,443.0 71,876.0 69,309.0 66,742.0 53,907.0 28,237.0 2,567.0
3,850.5 3,722.2 3593.8 3,465.5 3,337.1 2,695.4 1,411.9 128.4
308,040.0 297,772.0 287,504.0 277,236.0 266,968.0 215,628.0 112,948.0 10,268.0
30,804.0 29,777.2 28,750.4 27,723.6 26,696.8 21,562.8 11,294.8 1,026.8
503.9 503.9 503.9 503.9 503.9 503.9 503.9 503.9
87,781.9 85,728.3 83,674.7 81,621.1 79,567.5 69,299.5 48,763.5 28,227.5
770,100.0 288,987.3
417,779.3 210,486.8
477,462.0 240,556.4
15,117.7 5,673.0
1,740,141.7 775,773.0
59,682.8 30,069.5
decomissioning
total capital
Table 4. Project Operating and Maintenance (O&M) Costs project O&M costs ($ × 1000) O&M costs year 1 2 3 4 5 10 20 30 totals NPV
calciner
variable
limestone
635.0 644.5 654.2 664.0 674.0 726.1 842.6 977.9
10,091.5 10,242.9 10,396.5 10,552.5 10,710.8 11,538.5 13,390.9 15,540.7
20,357.5 20,662.9 20,972.8 21,287.4 21,606.7 23,276.6 27,013.4 31,350.2
28,117.4 28,398.6 28,682.6 28,969.4 29,259.1 30,751.6 33,968.9 37,522.8
-642.9 -649.4 -655.9 -662.4 -669.0 -703.2 -776.7 -858.0
2,522.9 2,560.7 2,599.1 2,638.1 2,677.7 2,884.6 3,347.7 3,885.2
12,050.3 12,170.8 12,292.5 12,415.5 12,539.6 13,179.3 14,558.1 16,081.2
9,565.3 9,708.8 9,854.4 10,002.3 10,152.3 10,936.9 12,692.7 14,730.4
25.1 25.5 25.9 26.3 26.6 28.7 33.3 38.7
63,541.3 64,296.7 65,061.6 65,835.9 66,619.9 70,687.9 79,618.9 89,730.9
23,837.1 8,251.7
378,822.4 131,137.8
764,193.7 264,542.7
978,060.9 347,874.3
-22,364.5 -7,954.5
94,705.6 32,784.4
419,168.9 149,089.0
359,069.8 124,300.0
942.4 326.2
2,276,411.8 801,099.1
fixed
waste disposal
credit income
fuel (combustor)
niques or, where available, historical costs extrapolated to present values. Operating and Maintenance Issues. (1) The carbonators are expected to require a Ca/C molar ratio of 4 for effective CO2 capture. The choice of the Ca/C molar ratio in this study has been based conservatively on measured rates and results obtained in our previous work.6,8-10 (2) It is assumed that approximately 30% of the fuel is burned in the calciners and 70% in the combustor. (3) It is now well-established that the capacity of CaO to capture CO2 decays as it is cycled between the carbonators and calciners, probably because of sintering.9,10 A CaO deactivation rate, based on CETC-O’s experimental decay curve,10 was used to model this effect. The actual decay of this capacity has been shown to follow a declining logarithmic curve,10 which is only approximated by the model’s 15% rate of decay (for each cycle, loss of activity is 15% of the activity in the previous cycle). For the purposes of this study, it is believed that this provides sufficiently accurate results. (4) A recycle rate of 92.5% from the calciners was assumed to accommodate this loss, as well as to remove the ash liberated and CaSO4 generated during combustion/processing. This low recycle ratio is equivalent to a large makeup flow of fresh limestone (7.5%) which means that a large fraction of particles have only been in the loop a few times and have experienced only a limited level of deactivation. (5) An overall plant efficiency of 40.7% was used. (6) Conservative CO2 credits of $5.00/t and SO2 credits of $0.50/t were included in the analysis. (7) Fuel is assumed to be petroleum coke, although anthracite coal is acceptable. Economic Model The main purpose of this study was to provide an initial estimate of the costs of capturing CO2 using a calcium-based (9) Abanades, J. C.; Alvarez, D. Energy Fuels 2003, 17, 308-315. (10) Wang, J.; Anthony, E. J. Ind. Eng. Chem. Res. 2005, 44, 627-629.
O&M costs
fuel costs
CO2 credit
SO2 credit
total O&M costs
dry sorbent cycle and to identify the most significant variables making up these costs. A sensitivity analysis using a range of key variables was used to determine the relative importance of the “critical” inputs, which in turn identified key areas for future research. The economic model was developed in Microsoft Excel and is shown in Tables 2-8. Note that, in the interests of clarity, Tables 3-8 have been abridged to show years 0-5, 10, 20, and 30. Inputs into the model are summarized in Table 2. A single fuel or a mixture of two fuels can be input, as well as the capital costs, which are fed from a separate spreadsheet. The plant is assumed to have a constant capacity factor and heat rate. Its key operational processes are also assumed to be constant. In most cases, these assumptions are reasonably close to actual plant characteristics. The model’s main outputs are summarized in Table 2. Yearly fuel and limestone consumption, tonnage of CaO, CaSO4, and ash recycled, waste produced, and CO2/SO2 captured are all listed in the table from calculations done on other spreadsheets. Model outputs have also been presented in Table 2 as 30year levelized costs of (1) the total plant, broken down into its components to identify their relative importance, (2) the plant directly related to capturing CO2, also broken down into its components, and (3) the plant directly related to capturing CO2, as a cost per metric ton (t) of CO2 captured. Table 3 shows the capital charges associated with the project over its 30-year life. The figures assume a steady pay down of capital as represented in the straight-line depreciation column. A sinking fund, to pay for demolition of the plant after its useful life is over, is also included. Table 4 presents the plant’s operating and maintenance (O&M) costs, fuel and feedstock charges, waste disposal charges (or credit), direct calciner costs, and credit payments using the inputs from Table 2. Table 5 summarizes the tax charges levied on the project, based on the costs and returns shown in the earlier tables.
924 Energy & Fuels, Vol. 21, No. 2, 2007
MacKenzie et al. Table 5. Tax Charges Levied on the Project income taxes ($ × 1000)
year 0 1 2 3 4 5 10 20 30
UCC
CCA
P shares
federal
provincial
capital
total taxes
770,100.0 754,698.0 724,510.1 695,529.7 667,708.5 641,000.2 522,654.0 347,477.5 231,014.3
15,402.0 30,187.9 28,980.4 27,821.2 26,708.3 21,777.3 14,478.2 9,625.6
1,540.2 1,488.9 1,437.5 1,386.2 1,334.8 1,078.1 564.7 51.3
21,781.6 14,022.1 14,050.7 14,055.8 14,038.3 13,642.6 11,603.1 8,372.3
11,279.7 7,261.4 7,276.3 7,278.9 7,269.8 7,064.9 6,008.8 4,335.7
1,732.7 1,675.0 1,617.2 1,559.5 1,501.7 1,212.9 635.3 57.8
36,334.2 24,447.3 24,381.7 24,280.3 24,144.7 22,998.6 18,811.9 12,817.1
539,085.7 239,540.1
23,873.1 12,027.8
372,606.9 155,129.6
192,957.2 80,335.0
26,857.2 13,531.3
616,294.4 261,023.6
totals NPV
Table 6. Project Yearly As-Spent Costsa capital costs
operating costs
fuel costs
tax costs
cost summary
year
total
¢/kWh
total
¢/kWh
total
¢/kWh
total
¢/kWh
total
¢/kWh
1 2 3 4 5 10 20 30 NPV
87,781.9 85,728.3 83,674.7 81,621.1 79,567.5 69,299.5 48,763.5 28,227.5 775,773.0
3.479 3.398 3.317 3.235 3.154 2.747 1.933 1.119
23,373.5 23,727.3 24,086.5 24,451.1 24,821.2 26,757.0 31,091.9 36,126.9 304,135.8
0.93 0.94 0.95 0.97 0.98 1.06 1.23 1.43
40,167.7 40,569.4 40,975.1 41,384.8 41,798.7 43,930.8 48,527.0 53,604.0 496,963.3
1.59 1.61 1.62 1.64 1.66 1.74 1.92 2.12
36,334.2 24,447.3 24,381.7 24,280.3 24,144.7 22,998.6 18,811.9 12,817.1 261,023.6
1.44 0.97 0.97 0.96 0.96 0.91 0.75 0.51
187,657.4 174,472.4 173,118.0 171,737.4 170,332.1 162,986.0 147,194.4 130,775.5 1,837,895.8
7.44 6.92 6.86 6.81 6.75 6.46 5.83 5.18
a
Totals are in $ × 1000. Table 7. Project 30-Year Levelized Costsa capital costs
operating costs
fuel costs
tax costs
total costs/revenue requirement
year
levelized
¢/kWh
levelized
¢/kWh
levelized
¢/kWh
levelized
¢/kWh
costs
levelized
¢/kWh
1 2 3 4 5 10 20 30 NPV
68,909.9 68,909.9 68,909.9 68,909.9 68,909.9 68,909.9 68,909.9 68,909.9 775,773.0
2.731 2.731 2.731 2.731 2.731 2.731 2.731 2.731
27,015.6 27,015.6 27,015.6 27,015.6 27,015.6 27,015.6 27,015.6 27,015.6 304,135.8
1.07 1.07 1.07 1.07 1.07 1.07 1.07 1.07
44,144.0 44,144.0 44,144.0 44,144.0 44,144.0 44,144.0 44,144.0 44,144.0 496,963.3
1.75 1.75 1.75 1.75 1.75 1.75 1.75 1.75
23,186.1 23,186.1 23,186.1 23,186.1 23,186.1 23,186.1 23,186.1 23,186.1 261,023.6
0.92 0.92 0.92 0.92 0.92 0.92 0.92 0.92
187,657.4 174,472.4 173,118.0 171,737.4 170,332.1 162,986.0 147,194.4 130,775.5 1,837,895.8
163,255.6 163,255.6 163,255.6 163,255.6 163,255.6 163,255.6 163,255.6 163,255.6 1,837,895.8
6.47 6.47 6.47 6.47 6.47 6.47 6.47 6.47
a
In $ × 1000 or ¢/kWh. Table 8. Effect of Capacity Factor (CF) on Overall Project Costsa annual costs
CF ) 90%
CF ) 80%
CF ) 70%
CF ) 60%
CF ) 50%
year
total
fixed
variable
¢/kWh
variable
¢/kWh
variable
¢/kWh
variable
¢/kWh
variable
¢/kWh
1 2 3 4 5 10 20 30 NPV
187,657.4 174,472.4 173,118.0 171,737.4 170,332.1 162,986.0 147,194.4 130,775.5 1,837,895.8
124,751.1 110,820.2 108,710.6 106,565.5 104,386.2 93,024.2 68,418.1 42,022.5 1,045,048.4
70,769.5 71,608.7 72,458.3 73,318.4 74,189.1 78,707.0 88,623.3 99,847.1 891,953.3
6.9 6.4 6.4 6.3 6.3 6.1 5.5 5.0
62,906.3 63,652.2 64,407.4 65,171.9 65,945.9 69,961.8 78,776.3 88,753.0 792,847.4
7.4 6.9 6.9 6.8 6.8 6.5 5.8 5.2
55,043.0 55,695.7 56,356.5 57,025.4 57,702.6 61,216.6 68,929.3 77,658.9 693,741.5
8.1 7.5 7.5 7.4 7.3 7.0 6.2 5.4
47,179.7 47,739.2 48,305.6 48,878.9 49,459.4 52,471.4 59,082.2 66,564.7 594,635.5
9.1 8.4 8.3 8.2 8.1 7.7 6.7 5.7
39,316.4 39,782.6 40,254.6 40,732.4 41,216.2 43,726.1 49,235.2 55,470.6 495,529.6
10.4 9.6 9.4 9.3 9.2 8.7 7.5 6.2
a
In $ × 1000 or ¢/kWh.
Tables 6-8 summarize the results of the previous tables using a variety of methods. Table 6 provides the yearly “as-spent” costs and cents/kWh summary apportioned into capital, operating, fuel, and tax costs. Table 7 gives this same breakdown in 30-year levelized costs. In Table 8, costs are broken down into fixed and variable components; then the plant capacity factor is adjusted from 90 to 50% to show the importance of the capacity factor to overall plant costs. The capital cost breakdown is given in Table 1. Costs have been estimated using previous study results wherever possible, as well as modified cost estimates from the Karita PFBC plant, escalated to current (2005) Canadian dollars. Since an actual
site has not been chosen, site-specific conditions could not be incorporated into the cost analysis. However, certain general assumptions were made with respect to site conditions. The estimated cost per metric ton for CO2 capture was found to be approximately $23.70. This figure was compared to the amine scrubbing technologies, which are currently the dominant CO2 capture option. A literature search, summarized in Table 9 found a wide range of equivalent capture costs from $39 to $96 (2005 Canadian dollars), depending on report specifics. This indicates that Ca-based sorbents have the potential to be cost competitive with other existing capture technologies. Further study and testing are required to improve information on Ca-
Economics of CO2 Capture
Energy & Fuels, Vol. 21, No. 2, 2007 925
Table 9. Amine-Based CO2 Capture Costsa amine scrubbing ref 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 2 29 spread
capital cost ($/kW) 1,120-1,520 1,375 920 1,500 1,440
efficiency drop (%) 13% 11% 10.3% 10-12%
capture cost ($/t avoided) 43/MWh 50 56 39 45-96 80 90
12% 1,690 1,125-1,220 1,380
8-13% 7.7-12.6% 12%
48 75-84 50-75
2,250 920-2,250
56 75 70
7.7-13%
39-96
a
Costs have been converted to 2005 Canadian dollars using the following: 1.2 Canadian dollars ) 1.0 U.S. dollar, 1.5 Canadian dollars ) 1.0 Euro, 2% escalation per year.
Figure 2. Project sensitivity analysis.
sorbent performance and capital costs and to provide a more detailed comparison between this process and alternative technologies. Sensitivity Analysis A series of sensitivity analyses were run using the Excel model described above. Eight potentially key parameters were identified, and each had its rates increased and decreased by up to 30%, while all other parameters were held at their base values. The impact this had on the project’s 30-year levelized cost per metric ton of CO2 captured was noted, and the results are summarized in Figure 2. The horizontal axis on Figure 2 represents the percentage change in each variable from -30% of its base value to +30%. The vertical axis represents the 30year levelized cost per metric ton of CO2 captured. Figure 2 shows that at 0% change from the base case parameters, all lines intersect at the base case 30-year levelized cost of $23.70/t of CO2 captured. As each parameter is adjusted, its effect on the vertical axis value can be seen by following the appropriate line. Variables with the steepest slopes have the greatest sensitivities. The dominant variables by far were related to the use (cost) of the sorbent. Not surprisingly, the cost of limestone, Ca/C ratio, CaO deactivation ratio, and CaO recycle rate were found to be closely related. The CO2 cycling process requires large quantities of CaO to capture the specified volumes of CO2. The sorbent quantities are large enough to dominate the economics of the capture process. This finding is also reflected in Table 2, where the 30-year levelized cost summary shows limestone as the single-most expensive plant cost component, as well as the most expensive component of CO2 capture. The cost of limestone at a particular plant site is likely to be largely outside the control of the plant. Negotiations will result in a market-driven charge to supply the limestone, and there will be limited scope to decrease this cost over time. In addition, the CaO recycle rate was assumed to be 92.5%. It is unlikely that this rate can be increased, and it may in fact be more advantageous to reduce the recycle flow, and thus the cost of recycling large volumes of waste material through the combustor
and calciner. This leaves the two remaining key variables, the Ca/C ratio and the CaO deactivation rate. If one or both of these variables can be reduced and if the sorbent can be made to “work” more efficiently, there are potentially huge benefits to be gained. Not only will reducing these rates reduce feedstock costs but will also reduce operation costs because less material will need to be moved and waste volumes will be reduced. Improvement of the efficiency of the Ca/C ratio or CaO deactivation rate appears to offer the best hope of significantly improving the economics of the emissions capture system. The remaining four variables, including capital cost, were found to be much less sensitive than the sorbent-related costs. Capital and operating costs would have to increase or decrease by substantial percentages to have a significant impact on the cost per metric ton of CO2 removal. One variable that has indirectly been included is the possibility that sulfation will also cause deterioration in limestone performance in the carbonation and calcination cycles. Since an adverse effect seems likely,11 the authors have chosen values of makeup flow of fresh sorbent sufficiently high to accommodate the deactivation of sorbent to form CaSO4 in the carbonator and calciner. However, if it proves necessary, it (11) Sun, P.; Grace, J. R.; Lim, J. C.; Anthony, E. J. In Proceedings of the 18th International Conference on Fluidized Bed Combustion; Toronto, ON, May 22-25, 2005; Jia, L., Ed.; American Society of Mechanical Engineers: New York, 2005; Paper FBC2005-78125. (12) Marion, J.; Nsakala, N.; Bozzuto, C.; Liljedahl, G.; Palkes, M. Engineering Feasibility of CO2 Capture on an Existing US Coal Fired Power Plant. Presented at the 26th International Conference on Coal Utilization and Fuel Systems, Clearwater, FL, March 5-9, 2001. (13) Parsons, E. L.; Shelton, W. W.; Lyons, J. F. AdVanced Fossil Power Systems Comparison Study; NETL USDOE Final Report; United States Department of Energy: Washington, DC, 2002. (14) Chapel, D.; Ernest, J.; Mariz, C. Recovery of CO2 from Flue Gases: Commercial Trends. Presented at the Annual Meeting, Canadian Society of Chemical Engineers, Saskatoon, SK, October 1999. (15) Khambaty, S.; Reddy, S. Application of the Econamine FG Plus Process to Canadian Coal Based Power Plant. Presented at the Combustion Canada Conference, Vancouver, BC, September 21-24, 2003. (16) David, J.; Herzog, H. The Cost of Carbon Capture. Presented at the MIT Carbon Sequestration Forum, Cambridge, MA, October 31November 1, 2000.
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would be possible to separate the combustion process from the carbonation/regeneration (which may occur at temperatures below the optimum for sulfur capture) to ensure that sulfation does not negatively influence carbonation. Conclusions The purpose of this paper was to provide a preliminary economic review of a Ca-based dry sorbent CO2-capture system and to determine if it could be competitive with other, more commercialized technologies. The initial results presented in the paper indicate Ca-based sorbents have the potential to be (17) McDonald, M. M.; Palkes, M. A Design Study of the Application of CO2/O2 Combustion to an Existing 300 MW Coal Fired Power Plant. Presented at the Combustion Canada Conference, Calgary, AB, May 1999. (18) McCartney, M. S. CO2 Separation. Presented at the 1st National Conference on Carbon Sequestration, Washington, DC, May 14-17, 2001. (19) Herzog, H. The Economics of CO2 Capture. Presented at the 4th International Conference on Greenhouse Gas Control Technologies, Interlaken, Switzerland, August 30-September 2, 1998. (20) Rubin, E. S.; Rao, A. B.; Berkenpas, M. B. A Multi-Pollutant Framework for Evaluating CO2 Control Options for Fossil Fuel Power Plants. Presented at the 1st National Conference on Carbon Sequestration, Washington, DC, May 14-17, 2001. (21) Singh, D.; Croiset, E.; Douglas, P. L.; Douglas, M. A. Energy ConVers. Manage. 2003, 44, 3073-3091. (22) Gambini, M.; Vellini, M. CO2 Emission Abatement from Fossil Fuel Power Plants by Exhaust Gas Treatment. Presented at the 2000 International Joint Power Generation Conference, Miami Beach, FL, July 23-26, 2000.
MacKenzie et al.
an economically attractive option for CO2 capture. Further research is needed to improve our understanding of Ca-sorbent performance and testing at larger scale is required to better define capital costs before a determination can be made as to the commercial viability of the Ca-based sorbent process studied here. EF0603378 (23) Carbon Dioxide Capture from Power Stations; IEA Greenhouse Gas R & D Programme Report; International Energy Agency: Paris, 1994. (24) IEA Committee on Energy Research and Technology Working Party on Fossil Fuels. Solutions for the 21st Century: Zero Emissions Technologies for Fossil Fuels; International Energy Agency: Paris, 2002. (25) IEA Committee on Energy Research and Technology Working Party on Fossil Fuels. CO2 Capture at Power Stations and Other Major Point Sources; International Energy Agency: Paris, 2003. (26) Thambimuthu, K.; Davison, J.; Gupta, M. CO2 Capture and Reuse. In Proceedings of the IPCC Workshop on CO2 Capture and Storage; Regina, SK, November 18-21, 2002; Intergovernmental Panel on Climate Change: Geneva, Switzerland, 2002. (27) Freund, P.; Davison, J. General Overview of Costs. In Proceedings of the IPCC Workshop on CO2 Capture and Storage; Regina, SK, November 18-21, 2002; Intergovernmental Panel on Climate Change: Geneva, Switzerland, 2002. (28) White, C. M.; Strazisar, B. R.; Granite, E. J.; Hoffman, J. S.; Pennline, H. W. J. Air Waste Manag. Assoc. 2003, 53 (10), 1172-82. (29) Wong, S.; Bioletti, R. Carbon Dioxide Separation Technologies, Alberta Research Council Report; Alberta Research Council: Edmonton, AB, 2002.
