【正文】 at cofiring at low ratios does not pose any threat or major problems to the boiler operation. Fig. 2. Worldwide cofiring plant locationsFor higher cofiring ratios, however, it might be necessary to use an indirect cofiring method.4. Case study methodology The present analysis of cofiring options considers only the economic and emissive effects of cofiring biomass within the plant facility and does not include changes in fuel transportation requirements. In North America, many local sources of biomass are available, and the use of a locally available source of biomass could have benefits beyond those discussed in this paper, in terms of reduced costs and emission generated from transportation of fuel. In areas where the supply of high quality biomass is limited transportation of biomass to the plant would likely be an important part of the economic and environmental costs. The amount of fuel replacement with biomass is generally very low in cofiring because especially in direct firing, the boiler furnace designed for a specific fossil fuel may not respond favorably as there is a major departure in bustion and flame radiation characteristics when some other fuels in used. If cofiring is applied to a fluidized bed boiler, this limit may not be that stringent. The present economic analysis is based on a 150 MW pulverized coal plant located in Eastern Canada. As such, only 10% biomass cofiring rate is considered in all the three different cofiring options examined here. Engineering design of the indirect cofiring system, its capital cost estimation, including fuel requirements for all three options, was carried out through a puterbased analysis. Table 1 lists the inputs of the thermodynamic design. The properties of the biomass fuel used in the analysis were taken as that of the hardwood maple. Hardwood species are widely available in Eastern Canada and are often discarded when harvesting of softwood trees for the pulp and paper industry takes place, making hardwood very cost effective. For coal, a low ash bituminous type coal was considered, typical of the fuel type used in the specific pulverized coal boilers. Table 2 presents the results of the ultimate analysis of coal and biomass. For all three cofiring options, the energy input remains the same, and was determined using the overall plant generation and heat rate:where, Qplant is the plant heat input (MJ), Pplant is plant electrical generation (MWh) and HRplant is the plant heat rate (MJ/MWh). The heat input required from the biomass was calculated at 10% of the overall heat required by the plant. The amount of coal that would be offset through the cofiring of biomass, in a year, was found through the following equation:where, mco is the mass of coal offset by cofiring (tons/year), fbf is the biomass cofiring fraction, HHVcoal is the higher heating value of coal (MJ/ton), and CF is the plant capacity factor. The capacity factor specifies as to what extent the installed capacity of the plant is utilized, either for technical reasons, or for operational reasons. Technical reasons, leading to technical availability of the plant, may be less than 100% due to forced shutdown or routine maintenance. The higher the reliability of the cofiring option, the higher is this factor. Direct firing means, which could interfere with the operation of the existing plant, could result in lower CF.. Direct cofiring Biomass firing in coal plants can result in increased tube corrosion/fouling or problems in the fuel pulverization and feed system, leading to increased maintenance and down time for the plant. This reduces the CF further. In the analysis of the direct cofiring option, a generation loss of 1% was therefore considered, which reduced the plant capacity factor to 79%. The capital cost associated with the implementation of direct cofiring was calculated using a value of 279 USD/kWth, from Cantwell [7]. The increased Oamp。M costs due to direct cofiring were estimated at $ Analysis of the external cofiring option required a preliminary design of a Circulating Fluidized Bed (CFB) boiler. The required thermal input for the steam generated by the biomass boiler was determined using a turbine efficiency of 88%. A thermal design of the boiler was done using CFBCAD in order to calculate the efficiency of the CFB boiler and used in conjunction with the turbine efficiency to calculate the required biomass fuel flow rate. The capital costs of the external cofiring were determined using a detailed cost assessment. This included the estimated costs of engineering design work, project management, boiler fabrication, civil footing, secondary ponents, controls and instrumentation, and erection and missioning. This cost estimate was based on previous work done by Greenfield Research Inc. on the feasibility of a subpact, biomassfired CFB boiler for placement within an existing PCfired plant. The capital cost of the CFB boiler worked out to $139/kWth. The Oamp。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。M costs of the gasifier were estimated at $6/MWhth.5. Economic evaluation criteria The economic evaluation of each cofiring option was based on any savings/increase in fuel cost arising from the pr