熱能與動力工程專業畢業論文外文文獻及翻譯-wenkub.com

　 　

【正文】 M costs were conservatively estimated at $5/MWhth. . Gasification cofiring In the analysis of the gasification cofiring option, a generation loss of % was taken, thus reducing the plant capacity factor to %. The product gas produced by the gasifier can cause problems in the backpass of the boiler with increased tube corrosion/fouling. This would lead to a slight increase in time for boiler maintenance and repairs, and hence the lower capacity factor. The capital cost of the gasification cofiring option was calculated based on the analysis of Antares [14]. Antares proposed a capital cost estimate of 382 USD/kWe. The capital cost was then found using the heating rate of the existing coalfired plant. The Oamp。 Earning of renewable energy tax credits: The use of biomass as an energy source to displace fossil fuel can be eligible for special tax credits from many governments. Various pollutionreduction incentives: As cofiring, through synergetic effects, reduces the SOx, NOx and heavy metal emissions, the plant could claim the applicable pollutionreduction incentives offered by government agencies. Financial incentives for plant greenhouse gas (GHG) emission reduction: A cofiring plant that uses biomass to replace an amount of coal in an existing boiler will reduce almost an equal amount of CO2 emission from the plant. Fuel flexibility: Biomass as a fuel provides a hedge against price increases and supply shortages of coal ore. In cofiring, biomass can be viewed as an opportunity fuel, used only when the price is favorable. M costs of the gasifier were estimated at $6/MWhth. 外文文獻 及譯文 11 5. Economic evaluation criteria The economic evaluation of each cofiring option was based on any savings/increase in fuel cost arising from the price difference of coal and biomass, and ine generated through the sale of emissions credits, both carbon and sulphur. As biomass is a carbon neutral fuel, any reduction in coal use can be see as a subsequent reduction in CO2 produced. A further reduction in carbon emissions could be gained if the PC plant uses a sorbent based scrubber. Sorbents such as limestone, used to capture sulphur dioxide produced by coal bustion, release additional carbon dioxide in the capture process adding to the plant’s carbon emissions. As the sulphur content of biomass is nearly zero, sulphur produced from coal bustion is reduced by the corresponding cofiring carbon dioxide and sulphur dioxide produced from the offset coal were calculated using the following equations: where [CO2] is the carbon dioxide offset by cofiring (tons/year), [C] is the carbon fraction in coal, [SO2] is the sulphur dioxide offset by cofiring (tons/year), [S] is the sulphur fraction in coal andmco is the amount of coal displaced by biomass (tons/year). From bustion stoichiometry [15], to capture every mole of sulphur, mol of calcium is needed, and production of 1 mol of calcium is associated with the generation of 1 mol of CO2. The effect of NOx reduction is a little more plex. An increase in the volatile content of a fuel busted in a PC burner could potentially reduce the NOx produced, but it would not reduce the thermal NOx in direct cofiring. The reduction would therefore be small when pared to reductions in CO2 and SO2. In external cofiring using a CFB boiler or gasifier, NOx emissions from the plant would be reduced due to the lower bustion temperatures found in CFB furnaces. Actual NOx reductions through decreased coal firing are dependent on the PC burner design and would be difficult to quantify. Gases produced from the gasification of biomass could be used to reduce the NOx emissions from PC plants if the gas was used in a NOx reburning situation. The analysis 外文文獻 及譯文 12 indicates that the cost of CO2 reduction through direct cofiring works out to 33$/ton of CO2. For the purposes of this analysis, no sulphur capture technology was built into the design. . Carrying charge Each technology option has its associated costs of implementation over and above the regular plant operational costs. All three options had associated carrying charge for the initial capital cost of the cofiring system. This is calculated using the following equation (input values are presented in Table 1): where V is the initial investment, D/V is the debt fraction of investment and cc is the carrying charge fraction. Another annual cost associated with the implementation of biomass cofiring is increased plant operation and maintenance costs. The gasification and direct cofiring options also have increased cost due to reduced capacity factor and plant’s annual generation. From these yearly savings and costs, the yearly ine after tax was calculated. All inputs for the economic analysis are also listed in Table 3. The cost of biomass in this analysis is the cost of delivered chipped hardwood, as shown in Table 2. Cofiring costs could be less if a biomass waste material, such as sawdust from lumber mills or sewage sludge from nearby plants were available and fuels need to be sourced locally as the transportation costs of biomass could erode its cost advantage due to the low energy density of biomass fuels. The present analysis is very conservative as it did not include the avoided tipping fees that would otherwise be incurred through the disposal of unwanted biomass. In one analysis performed by the . Department of Energy (TR109496), the avoided tipping fees accounted for over 50% of the savings generated. The increasing demand for biomass products in the power generation industry has made them a modity in a number of regions around the world. For this reason the authors did not include this savings as owing to this demand, it is unlikely that the ine from tipping fee avoidance would continue in the future. For the ev