OCR Text |
Show concept satisfies the four criteria stated previously. TIffiRMOECONOMIC CONSIDERATIONS The decision by industry to pursue any carbon dioxide removal scheme ultimately will depend on government intervention in the form of restrictions on carbon dioxide emissions and associated penalties or incentives. Assuming that such action is imminent, cost will be a primary factor in the selection of a specific carbon dioxide removal process. To this end, thermoeconomic analyses were performed on a hypothetical 500 MW (net) combustion power plant to determine the capital and fuel requirements for the aforementioned Case A and Case B pre-combustion carbon dioxide removal alternatives. Conservative values for component efficiencies and process parameters were used in the calculations. Expenditures for labor and equipment maintenance were not included in this analysis. Details of the Case A analysis have been reported by Mori, et ale (199Ia), and for Case B, by Mori, et ale (199Ib). While the bases used in those two reports were not identical, the present analysis adopts a common basis in the thermoeconomic evaluations of both Cases (which accounts for the minor differences between the present analysis and the previous reports). The basis for the thermoeconomic analysis and salient results for the Base Case (the unmodified power generation plant), Case A, and Case B systems, are summarized in Table I. In the analysis, the flXed (capital) and fuel costs for the Base plant are 3.09 cents!kWh and 2.76 cents/kWh, respectively. The sum of these two costs, hereafter referred to as the power cost, is 5.85 cents!kWh. To maintain the gross power output at the level of the Base plant, 526.3 MW, while extracting nearly 90% of the fuel-bound carbon, approximately 28,000 and 23,000 kmollh (56,000 and 45,000 kg/h) of hydrogen gas must be produced by the reformer in Case A and Case B, respectively. The corresponding flow rates of disposed liquid carbon dioxide would be 2.8 x 105 and 2.3 x 105 kg/h for Case A and Case B, respectively. Operation of the carbon dioxide separation equipment would increase the in-plant power consumption (back-work). Methane compression, carbon dioxide separation and liquefaction, and ocean disposal pumping requirements, would increase the back-work fraction from 5% to approximately 12% and 19%, respectively, of the gross generated electrical power for Case A and Case B (the higher parasitic load for Case B is due primarily to increased refrigeration load). As a result, the plant net thermal efficiency (net electrical power output divided by gross fuel energy input) would decrease from 37.1 % to 26.8% (Case A) and 30.2% (Case B). The lower efficiency for Case A is due primarily to latent heat loss in the stripping steam. The capital costs of the reformer and the carbon dioxide separation equipment were estimated on the basis of comparable commercial units described in the literature to be $65.5 million and $74.0 million for Case A and Case B, respectively. Assuming that the desired 500 m ocean discharge depth can be reached within 100 km from shore, up to 100 km of 30 cm diameter insulated pipe would be required to transport the liquid carbon dioxide from the plant to the point of release. Based on data on OTEC and undersea oil pipelines, the unit deployed cost of the pipeline was taken to be $300/m. The total cost for this item therefore could reach $30 million. Finally, boiler modifications to accommodate hydrogen fueling and other changes to the boiler system were estimated to cost $6.5 million for Case A and $1.5 million for Case B (the higher cost for Case A is due primarily to more extensive integration of the fuel reforming and steam/power generation subsystems). The overall capital cost to modify the 500 MW Base plant to facilitate carbon dioxide separation and disposal is expected to be slightly more than $100 million for either case, which translates to approximately $220 and $250 per kilowatt of net electrical power generated for 7 |