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Chapter 3: Capture of CO2 table 3.11. CO2 capture costs: Hydrogen and multi-product plants using current or near-commercial technology. (Continued on next page) 159 Simbeck 2005 NRC NRC 2004 2004 H2 H2 HyDROGEN AND ELECtRiCity PRODuCtS Study Assumptions and Results Parsons 2002a Conv E-Gas, CGCU, H2SO4 co-product Pgh #8 Coal 0.89 2627 1419 mitretek 2003 Texaco quench, CGCU, Claus/Scot sulphur co-product Coal Kreutz Kreutz Range min max 0.89 5.26 2627 9848 1419 7504 -121 78 55.9 74.6 80 90 1.80 7.40 0 0 78 174 2627 11495 1434 7504 Reference Plant (without capture) * Plant products (primary/secondary) H2 Production process or type Steam reforming * H2+ electricity * H2+ electricity 2005 2005 et al. et al. Feedstock Natural gas Feedstock cost, LHV (US$ GJ−1) 5.26 Ref. plant input capacity, LHV (GJ h−1) 9848 Ref plant output capacity, LHV: Fuels (GJ 7504 h−1) Steam Texaco reforming quench, CGCU H2+ electricity Texaco quench Coal 1.26 6706 3853 H2+ electricity Texaco quench Coal 1.26 6706 3853 Natural gas Coal 4.73 1,20 7235 8861 5513 6004 1.03 2954 1579 Electricity (MW) -44 Net plant efficiency, LHV (%) 74.6 Plant capacity factor (%) 90 CO2emitted (MtCO2 yr−1) 4.693 Carbon exported in fuels (MtC yr−1) 0 Total carbon released (kg CO2 GJ−1 products) 81 Capture Plant Design -32 -121 74.6 62.9 90 90 3.339 7.399 0 0 78 168 MEA Not scrubber reported 8339 8861 6004 6004 -91 -187 68.1 60.2 90 90 0.604 1.181 0 0 13.5 28.1 3.378 6.385 13.7 13.7 9.5 4.5 83 83 2000 2000 16.0 16.0 469 1192 646 1218 37.7 2.2 45.0 45.0 45.0 45.0 38 20 78 78 59.2 55.9 61.7 61.7 80 85 80 80 1.795 0 164 Selexol 2627 1443 12 56.6 92 0.143 0 13.7 1.654 13.4 4.7 92 2.148 0 174 Not reported 2954 1434 27 51.8 87 0.279 0 24.5 1.869 20 7.9 86 4.215 4.215 0 0 145 145 CO2 capture/separation technology Amine scrubber, SMR flue gas Selexol CO2 H2S co- capture, Capture plant input capacity, LHV 11495 (GJ h−1) Capture plant output capacity, LHV: Fuels 7504 (GJ h−1) Selexol 6706 6706 Electricity (MW) -129 Net plant efficiency, LHV (%) 61.2 CO2 capture efficiency (%)** 90 CO2 emitted (MtCO2 yr−1)*** 1.280 Carbon exported in fuels (MtC yr−1) 0 Total carbon released 23.0 (kgCO2 GJ−1 products) 3853 3853 39 35 59.5 59.3 91 95 0.338 0.182 0 0 12.1 6.5 3.882 4.037 15 15 3.6 3.9 92 96 -187 39 51.8 68.1 87 95 0.14 1.280 0.0 0 6.5 28.1 CO2 captured (MtCO2 yr−1) 4.658 CO2 product pressure (MPa) 13.7 CCS energy requirement (% more input/GJ 21.8 plant output) 1.7 6.4 13.4 20.0 3.6 21.8 72 96 13.0 20.0 CO2 reduction per unit product (%) 72 Cost Results Cost year basis (constant dollars) 2003 Fixed charge rate (%) 20.0 Reference plant TCR (million US$)**** 668 Capture plant TCR (million US$)**** 1029 % increase in capital cost (%) 54.1 Ref. plant electricity price (US$ MWh−1) 50.0 Capture plant electricity price 50.0 (US$ MWh−1) 2000 2000 2002 2002 14.3 13.0 15.0 15.0 357 1192 357 415 16.5 30.8 30.8 365 887 409 935 11.9 5.4 35.6 46.2 53.6 62.3 887 872 409 1218 -1.7 -1.7 54.1 46.2 30.8 50.0 60.5 30.8 62.3 % increase in assumed electricity price 0.0 0.0 0.0 0.0 50.6 34.8 31.0 0.0 50.6 7.19 6.51 10.03 7.52 7.52 13.29 0.32 0.32 3.26 4.5 4.5 32.5 2.2 2.2 38.9 2.3 2.3 56.3 Ref. plant fuel product cost, LHv 10.03 (uS$ GJ−1) Capture plant fuel product cost, LHv 13.29 (uS$ GJ−1) 8.58 7.99 6.51 7.29 7.19 increase in fuel product cost 3.26 (uS$ GJ−1) % increase in fuel product cost 32.5 Cost of CO2 captured (US$/tCO2) 38.9 Cost of CO2 avoided (US$/tCO2) 56.3 Confidence level (see Table 3.6) 10.14 8.61 1.56 0.62 7.90 1.38 8.27 7.86 0.98 0.67 18.2 7.7 21.1 13.4 9.3 high 20.7 4.1 24.1 4.4 high 8.7 9.2 6.0 4.8 6.5 5.0 Notes: All costs in this table are for capture only and do not include the costs of CO2 transport and storage; see Chapter 8 for total CCS costs. * Reported HHV values converted to LHV assuming LHV/HHV = 0.96 for coal, 0.846 for hydrogen, and 0.93 for F-T liquids. ** CO2 capture efficiency = (C in CO2 captured) /(C in fossil fuel input to plant - C in carbonaceous fuel products of plant) x100; C associated with imported electricity is not included. ***Includes CO2 emitted in the production of electricity imported by the plant. ****Reported total plant investment values increased by 3.5% to estimate total capital requirement. increase in hydrogen production cost for CO2 reductions of 72- 96% per unit of product. The case with the lowest incremental product cost and highest CO2 reduction assumes co-disposal of H2S with CO2, thus eliminating the costs of sulphur capture and recovery. As noted earlier (Section 3.7.6.1), the feasibility of this option depends strongly on local regulatory requirements; nor are higher costs for transport and storage reflected in the Table 3.11 cost estimate for this case. moderate those discussed earlier, can significantly affect the outcome of cost calculations when there is not one dominant product at the facility. Several of the coal-based hydrogen production plants in Table 3.11 also produce electricity, albeit in small amounts (in fact, smaller than the electricity quantities purchased by the stand-alone plants). Most of these studies assume that the value of the electricity product is higher under a carbon capture regime than without CO2 capture. The result is a 5-33% Table 3.11 also presents examples of multi-product plantsPDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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