Enhanced Emissions Control for SDA System with Dry Lime Addition

Performance of the well-proven spray dryer absorption (SDA) process for the control of acid gas and hazardous air pollutant (HAP) emissions in coal-fired boiler applications can be enhanced by the addition of dry hydrated lime powder to the process. In conventional SDA FGD systems, all of the reagent is introduced as a slurry to the absorber. The spray dryer functions to evaporate the water in the reagent slurry, providing sufficient wet phase reaction time for high utilization of the lime and alkaline flyash for acid gas emissions control while producing a dry byproduct.

Under some operating conditions such as low inlet flue gas temperature or high inlet SO₂ concentrations, the amount of reagent that can be added to the process may be limited by the spray dryer’s capacity to evaporate the water in the reagent feed slurry. Dry, hydrated lime powder may be added to the process to increase the amount of reagent available for reaction without adding to the evaporative load of the dryer.

This technique may be used to enhance SDA performance on cold boiler unit startup where low flue gas temperature limits the amount of slurry that can be introduced to the spray dryer. Dry hydrated lime addition increases the alkalinity of the solids in the limited amount of feed slurry which can be evaporated during these startup conditions. Dry hydrated lime injection may also be used to extend the upper range of inlet SO₂ concentration or SO₂ removal efficiency for an SDA with performance-limiting constraints which may include low inlet temperature, reagent slurry feed system limitations, or atomizer capacity limits.

PRB coal-firing 110-MW Wygen 3-Unit #5 began commercial operation in April 2010. The final air permit issued by the Wyoming Dept. of Environmental Quality to Black Hills Power (BHP) for Wygen 3-Unit #5 included a condition that required SO₂ compliance with the emission limits at all times, including startup and shutdown of the unit. Since the initial permit application for Wygen 3-Unit #5 did not contain provisions stipulating this condition, the plant design did not incorporate the equipment necessary for the unit to be able to maintain SO₂ compliance during startup and/or shutdown periods pursuant to the issued permit.

The existing dry FGD system cannot be put into service prior to coal firing due to inadequate flue gas temperatures entering the SDA vessel. During a cold startup, this period can range from 8 to 12 hours and may lead to the unit exceeding its SO₂ 3-hr block limit. BHP and Babcock & Wilcox Power Generation Group, Inc. (B&W PGG) began working together to develop a plan for the unit to remain in environmental compliance during startup.

Part of this project involved injecting hydrated lime into the unit at the bottom of the SDA vessel on Wygen 3-Unit #5. It was believed that if the fabric filter baghouse downstream of the SDA could be coated with hydrated lime prior to first coal fire, then SO₂ capture would be enhanced. The benefit of pre-coating for SO₂ removal only occurs while there is feed slurry to the atomizer with the resulting lower fabric filter flue gas temperature and increase in flue gas humidity. The test found that the addition of hydrated lime resulted in stack SO₂ emissions being reduced by 50 to 65 percent when compared to a unit startup in which hydrated lime was not injected.

BHP is currently in contract with B&W PGG for supply of a dry sorbent injection (DSI) system to provide hydrated lime injection during unit startup and allow for SO₂ emission compliance during startup of Wygen 3-Unit #5. This system will be operational by the 4th quarter 2012/1st quarter 2013.

Tests were also conducted at the  Unipetrol RPA power plant in Litvinov, Czech Republic, which consists of eight boilers connected to two type ACP-8000 SDAs, each 15 meter in diameter and equipped with GEA Niro F800 rotary atomizers. Flue gas is then directed to pulse jet fabric filters.

Tests were conducted by Unipetrol to investigate the possibility of handling coal with higher sulfur content than currently used and to operate at lower SO₂ emissions, considering future stricter SO₂ emission limits. The possibility of lowering the operating cost by use of a combination of lime slurry to the rotary atomizer and dry lime injection into the absorber was also investigated.

The dry hydrated lime for the entire test period was a locally-produced, high-surface area lime with >95 percent purity and BET surface area of 40 to 45 m²/g, supplied by Lhoist. The testing at Unipetrol, Czech Republic, confirmed that the GEA Niro Peak Control system developed originally for SDAs at waste incinerators works equally well at an SDA at a coal-fired power plant. It was possible to operate an SDA system with high SO₂ removal efficiency at high inlet SO₂ load with reagent injected only in the dry form and with the rotary atomizer at the plant operated with recycle slurry only. The SO₂ removal efficiency obtained at the test was approximately 94 percent, and even higher efficiencies are considered possible, reported Bryan J. Jankura and Kevin E. Redinger of Babcock & Wilcox Power Generation Group, Inc., Carly Miller of BHP Inc., Niels Jacobsen and Niels G. Hansen of GEA Process Engineering A/S, and Luděk Sklenář of UNIPETROL RPA, s.r.o. at the 2012 Mega Conference.