Thermal coal-fired boiler

Figure 12 Theoretical and experimental NO emissions at coal combustion that were calculated by model (90)—(95) (curve 7) and presented in the work by Gorban (2001,2006) equilibrium (1), maximum (2) actual (3-6) fluidized bed combustion (3), low-temperature combustion of brown coals (4), high-temperature combustion of hard coals (5), averaged for coal-fired boilers (6) A— prompt NO, B— fuel NO, C— thermal NO.

The heat released from combustion of the fuel is transferred by radiation and convection to evaporate water and create superheated steam, which is then used to create electricity in a steam turbine. Steam temperatures in state-of-the-art coal-fired boilers are pushing close to 600°C (i.e. above the critical point of water) with net electricity production reaching 45% of the thermal energy of the burned fuel [43]. Modem subcritical boilers are closer to 39% net efficiency in electricity production, but older boilers can have efficiencies as low as 30% on a lower-heating-value basis. 

Figure 2 Process scheme thermal pre-treatment of biomass and rebuming of the biomass derived gas in a coal-fired boiler... 

The formation of ash deposits within coal-fired boilers may cause serious operating problems and reduction in thermal efficiency. 

The University of Utah pilot-scale combustion test furnace referred to as the "L1500" is a nominal 15 MMBtu/hr (4.4 MW) pilot-scale furnace designed to simulate commercial combustion conditions, particularly the thermal history of operating commercial coal-fired boilers. 

Modification of direct coal combustion for CO2 removal would be more difficult. CO2 could be removed from the flue gas after conventional combustion by acid gas removal technology. Although this approach has found some commercial application, the low pressure and low concentration of the CO2 in the flue gas makes it a relatively expensive method. Removing 90% of the CO2 from flue gas of a conventional coal-fired boiler would increase the capital cost by a factor of 3.0 and thermal efficiency drops by 12% compared to a conventional direct coal combustion power plant. The larger capital increase and efficiency loss with CO2 recovery is principally due to recovery at low pressure which requires a larger flue gas compression, CO2 absorbers, and increased steam requirements. Depending on the cost of coal and capital, the increased electric cost for CO2 removal with a direct coal combustion power plant is 2.0-3.0 times that of a conventional direct coal combustion power plant. 

Tetrachlorodibenzo-p-d1oxin (TCDD). At the detection limit of ten parts per trillion, no TCDD was found in the effluents from the combustion of coal in three different boilers at the Ames power plant (see summary table in reference 16 for description of boilers). This observation was confirmed at a second smaller coal-fired power plant located at Iowa State University. Even when the coal fuel was supplemented with RDF, which should contain the precursor compounds, no dioxins were observed in the vapor and particle samples taken from the effluents. Thus no de novo synthesis occurred during the combustion of coal alone and if dioxins were formed from precursor compounds in the co-combustion of coal and RDF, they were destroyed in the efficient combustion as explained above for the thermal destruction of the PCBs present in the RDF. 

SCR systems were installed first in Japan starting from the late 1970s on both industrial and utility plants for gas-, oil-, and coal-fired applications (7). SCR technology has also vmdergone a wide diffusion in Europe, since 1985 when it has been introduced in Austria and West Germany. This technology presently accounts for more than 90-95% of De-NOjc fine gas treatments in Europe. SCR applications in the United States were at first confined to Gas Turbines and were primarily located in California, but presently SCR systems have been installed in several industrial boilers, thermal power plants, and cogeneration units all over the United States. Several SCR plants have been installed also in Far East (eg, China and Republic of South Korea). 

In the SRC-11 process, the process steam is generated by direct gas-fired boilers and the process heating by direct gas firing. The fuels utilized are hydrocarbon-rich gas, or CO-rich gas, and purified syngas (i.e., no feed coal is used for fuel). It was shown that a 2 X 600 MW(t) PS/C-MHR can supply these thermal requirements principally by substituting for the fuel gases previously employed (Shenoy 1995). The displaced gases, which are treated already, may then be marketed. 

Xiang, Z., C. YuHaimiao, C. Xinyu, H. Zhenyu, L. Jianzhong, Z. Zhijun, Z. Junhu, and C. Kefa. 2003. The Application of Coal Water Slurry on the 220 t/h Utility Oil-Fired Boiler in Maoming Thermal Power Plant. Proc. 28 International Technical Conference on Coal Utilization Fuel Systems. Coal Technology Association. Clearwater, FL. March 9-13. 

Figure A1.5 Typical scheme of coal-fired thermal power plant (AuthorAJser BillC https // commons.wikimedia.org/wiki/File PowerStation2.svg website approached January 26, 2016) (1) Cooling tower (2) cooling-water pump (3) transmission line (3-phase) (4) step-up transformer (3-phase) (5) electrical generator (3-phase) (6) low-pressure (LP) steam turbine (7) condensate pump (8) surface condenser (9) intermediate-pressure steam turbine (10) steam control valve (11) high-pressure (HP) steam turbine (12) deaerator (13) feedwater heater (14) coal conveyor (15) coal hopper (16) coal pulverizer (17) boiler steam drum (18) bottom ash hopper (19) superheater (20) forced draught (draft) fan (21) reheater (22) combustion air intake (23) economizer (24) air preheater (25) precipitator (26) induced-draught fan and (27) flue gas stack.

With Flue Gas Recirculation (FGR), flue gas is introduced with the combustion air and acts as a thermal diluent to reduce the combustion temperature. Usually, the amount of flue gas recirculated corresponds to 10-20% of the combustion air. FGR reduces only thermal NO (. It is suitable only for oil- and gas-fired boilers. Results with coal have been generally disappointing. In coal-fired stoker units, FGR provides better grate cooling. FGR has been successfully applied on industrial solid fuel-flred units and is considered appropriate for waste-to-energy plants. Retrofit modifications include new ductwork, gas recirculation fan(s), flue gas/air mixing devices and controls (Makansi, 1988 Wood, 1994). Gas recirculation fans can be troublesome. 

Hurst, B. E., 1983, Improved THERMAL DeNO, Process for Coal-Fired Utility Boilers, paper presented at the 11th Annual Stack Gas/Coal Utilization Meeting, Paducah, KY, Oct. 6. (Sp>onsored by Battelle Memorial Institute, Columbus, OH.)... 

There has been increased interest in firing wood waste as a supplement to coal in either pulverized coal (PC) or cyclone boilers at 1—5% of heat input. This appHcation has been demonstrated by such electric utilities as Santee-Cooper, Tennessee Valley Authority, Georgia Power, Dehnarva, and Northern States Power. Cofiring wood waste with coal in higher percentages, eg, 10—15% of heat input, in PC and cyclone boilers is being carefully considered by the Electric Power Research Institute (EPRI) and Tennessee Valley Authority (TVA). This practice may have the potential to maximize the thermal efficiency of waste fuel combustion. If this practice becomes widespread, it will offer another avenue for use of fuels from waste. 

Thermal conductivity of sintered and fused deposits found by the Australian researchers range from 0.5 x 10" kW/mK at 800 K to 2.0 X 10" kW/mK at 1500 K. This is consistent with the recent findings of Fetters et al. (3 ) for crushed deposits from a boiler fired with Indiana coal and with other literature values ( ). The increase of thermal conductivity of sintered and fused deposits is due to a decrease of void space and increased transmissivity of the material. Wall et al. emphasize that values of k obtained from ground deposits in laboratory studies are questionable since bounding of the deposit occurs in situ which leads to an increase of k. This agrees with our results for a 700 MW boiler which yielded an overall value of k - 3.2 x lO"" kW/mK for deposits which could not be removed by soot blowing (see below). 

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