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Show water and allowed to slake (hydrate). The resulting slurry is then pumped to the dry scrubber and reinjected into the flue gas stream. In the dry scrubber, the flue gases are cooled and humidified. Under these conditions, a portion of the S 0 2 in the gas reacts with the slurry allowing additional S 0 2 removal to occur. Finally, the flue gas enters the fabric filter (baghouse) where additional S 0 2 removal occurs across the filter cake on the bags. Clean flue gas exits the facility through the stack. Several impacts on the other subsystems of the power plant were assessed in order to evaluate the integration of LIDS into the LEBS plant. One important consideration when injecting a sorbent into the boiler is the impact on the upper furnace/convection pass. The impact was considered in terms of the following: Heat Absorption. Previous studies have indicated that heat absorption In the high temperature banks of the boiler convection pass is impacted by the presence of the sorbent. This is due to the increased deposition in the upper furnace and convection pass due to the additional solids content in the flue gas. The important determining factors are the amount of sorbent. type of sorbent (limestone, hydrated lime, etc.). and sorbent particle size distribution. The potential problem can be alleviated by incorporating a combination of the following methods: 1) designing the sootblower arrangement and operation for optimal boiler thermal performance while Injecting a sorbent into the boiler and 2) choosing the sorbent particle size distribution such that deposition minimization and sulfur capture maximization are optimized. Heat Transfer Surface Arrangement. The residence time/temperature profile of the boiler and convection pass was evaluated to determine the residence time in the calcination /sulfate temperature "window" for optimal S 0 2 capture with the furnace limestone injection process. Proper mixing, calcination, and sulfation must all be completed before exiting the boiler subsystem. Through the proper integration of the furnace limestone injection process into the boiler, optimum S 0 2 removal can be achieved while retaining a cost-effective boiler design. Another important criterion for LIDS integration is the Impact on the power plant's overall thermal efficiency. There is evidence that the Injection of a calcium- based sorbent into the upper furnace of a boiler effectively removes S 0 3 from the boiler flue gases. There is the potential to reduce air heater flue gas exit temperature below current standards due to the elimination of acid condensation concerns. Operation at lower air heater flue gas exit temperatures could improve boiler efficiency. Proper integration of the S 0 2 and Particulates Subsystem requires a particulate removal device that is capable of complementing the S 0 2 control system while maintaining the desired particulate removal performance. With LIDS. S 0 2 removal is enhanced by the use of a pulse-Jet fabric filter baghouse for particulate removal. The baghouse removes S 0 2 from the flue gas as the gas passes through the Alter cake collected on the bags. With the union of a baghouse within LIDS, high fine particulate removal and high S 0 2 removal can be accomplished with the integrated baghouse and LIDS system. Wet Flue Gas Desulfurization (FGD) The application of wet scrubbing processes to the boiler has no detrimental Impacts on the boiler. The equipment used for S 0 2 capture and particulate control follows the boiler and therefore is not an integral part of the boiler itself. One advantage of utilizing a wet scrubber for S 0 2 capture is the potential for adding a condensing heat exchanger upstream of the wet scrubber. The condensing heat exchanger can decrease the flue gas temperature and extract the additional heat returned to the power plant heat cycle. This offers the potential to increase the LEBS power plant efficiency. A condensing heat exchanger could not be integrated with LIDS and dry scrubbing systems which require a minimum amount of heat in the flue gas to achieve successful evaporation of moisture. NOx CONTROL SUBSYSTEM The N O x Subsystem includes coal preparation and handling, combustion air preheating, coal burners and their locations, air/fuel injectors and their locations, the boiler furnace, and control system hardware and software. N O x Subsystem design should provide for reliable operation of the L E B S plant at NOx emissions at or below the target levels over a range of loads typical of a base-loaded generating plant. Not only must the boiler be designed to achieve time-temperature mixing histories that minimize NOx. it must also be designed to operate that way throughout its working lifetime. Therefore, N O x minimization strategies must be integrated Into the control systems for every boiler component from the pulverizers to the stack. Low N O x emissions must be maintained in spite of pulverizer wear, steam temperature variations, and startup or shutdown conditions. Furthermore. N O x performance must be met without increases in carbon loss and C O emissions from the levels achieved with current low-NOx combustion systems. Therefore, the N O x Subsystem addresses not only the mechanical designs of burners, furnace surface, and staging air/fuel injectors. but also appropriate sensors and software to control their operation. Advanced Staged Combustion One promising N O x control concept considered for 5 Paper No. 11-13 |