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Show C~m?lete implementation of this technology at the Cogentrix plant compared to the ~XlStIng ~NC~ system will provide: 1) The same or better NOx reduction; 2) An Increa~e m boIler efficiency 2 to 3%, 3) Additional environmental benefits due to the reductIon of CO2 and the elimination of potential for ammonia slip; 4) Improved boiler start-up, load change, and operations; 5) Annualized plant cost benefit advantage of about $1.5 to 2.5 million depending on plant capacity factor. BACKGROUND Historically, the thousands of stoker boilers in the United States firing coal, municipal solid waste (MSW), biomass, and refuse derived fuel (RDF) have gaseous and particulate emissions, erosion, slagging, and fouling. Environmental regulations are becoming more restrictive (1990 Clean Air Act Amendments) and ultimately w:ll require industries to retrofit many existing solid fuel-burning operations, such as stoker boilers, with technologies that will allow them to meet new emission requirements for NOx, CO, total hydrocarbons (THC), sulfur dioxide (S02), particulate, and other pollutants. SmaIl quantities of natural gas injection combined with flue gas recycle has been demonstrated effective in meeting new emission requirements. Cogentrix, an independent power producer headquartered in Charlotte, North Carolina, owns and operates 10 cogeneration facilities in North Carolina, Virginia, and Pennsylvania. The largest and newest facility is located in Richmond, Vrrginia. It is a 240 gross MW coal-fired facility serving Virginia Power and a local fiber and chemical plant. The Richmond plant contains eight spreader stoker type coal fired boilers, rated at 295,000 lb/h each. The boilers are ABB VU40 type, burning low sulfur coal from Eastern Kentucky. Each boiler at the Richmond plant is equipped with a SNCR system. The system is the urea based NOxOUT system. Since initial plant start-up in th,e Spring of 1992 there have been problems related to the operation of the SNCR system. Each boiler is also equipped with a spray-dryer flue-gas desulfurization (FGD) system with a pulse-jet fabric filter downstream for particulate removal. The plant is a fully dispatchable facility and operates through automatic generation--control (AGe) from the Virginia Power operating center. AGe allows the plant electric output to be controlled remotely by the Virginia power system operator. Boiler loads are rarely constant, as plant electric output is varied to match system demand. At low system demand levels, electrical production ceases; however, steam is still required by the fiber and chemical plant. During these periods, the boilers are operated without the benefit of the regenerative feedwater heating cycle used when producing electricity. The challenges in applying downstream NOx control to a unit that varies widely in load has been previously published (3,4). The urea-based SNCR system is used for NOx control. Because the SNCR reaction is limited to a temperature window of about 1600 to 1950 F, multiple levels of injectors are required for complete furnace coverage. Initially, water dilution of the urea was controlled by a relief valve on the discharge of the water dilution pump. Water and urea were then pumped to the boiler local-zone control panels, where steam was used for atomization, and the mixture injected into the furnace. Urea solution is metered to 2 |