Circulating fluid bed (CFB) dry scrubbing technologies provide distinct advantages over conventional spray dryer absorber scrubbers for removing SO2 from flue gases. The CFB also competes well against wet limestone flue gas desulfurization processes typically favored for large boilers firing high-sulfur coals. With high SO2 removal rates in a dry treatment process, the CFB scrubber appears to be the best of both technologies: a water-stingy scrubber with high SO2 removal rates.
The typical processes for removing sulfur dioxide (SO2) from coal-fired power plant flue gases include wet flue gas desulfurization (wFGD) and the more recent spray dryer absorber (SDA) technology. Both get the SO2 removal job done, although both process have a distinct advantages and disadvantages, such as producing large amounts of new waste products that require disposal or consuming large amounts of water. The circulating fluidized bed (CFB) process promises high SO2 removal efficiencies, extremely low water consumption, and the ability to bridge the size gap between the SDA and wFGD. To demonstrate why familiar options may not be the best, we begin by examining the merits of each system.
SDA Advantages and Limitations
SDA systems are typically used at plants firing low- to medium-sulfur (2%) coal. Depending on inlet SO2 loading, demonstrated SO2 removal efficiencies in the range of 90% to 95% with controlled SO2 emission rates as low as 0.065 lb SO2/million Btu are well documented with SDA systems. Removal rates in excess of 90% require the use of a fabric filter to provide additional contact time between the lime sorbent and the SO2. The filter cake on the fabric filter bags acts as a fixed bed of solids and provides an additional 1 second of contact time for enhanced mass transfer of SO2. For SDA systems, SO3removal efficiencies are typically 99%. Details of SDA technology applied to recent coal-fired projects are available online at http://www.powermag.com using the keyword “SDA.”
In the typical SDA system, the reagent slurry is pumped to the top of the SDA absorber vessel and introduced through one or more high-speed (11,000 rpm) spinning wheels within rotary atomizers located on the roof of the vessel (Figure 1). The atomizer(s) are centrally located within flue gas dispersers. As flue gas is accelerated and dispersed evenly around the perimeter of the spinning wheel, the pollutants are brought into intimate contact with a spray cloud of atomized droplets containing the sorbent. The sorbent reacts with SO2 and SO3 to form calcium sulfite and calcium sulfate while simultaneous cooling of the flue gas occurs. The flue gas then exits the absorber and is directed to a particulate collection device, either a fabric filter or electrostatic precipitator.
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| 1. Typical SDA dry scrubbing system schematic. Source: Nooter/Eriksen |
SDA absorbers are downflow reactors, with the atomizers and gas dispersers located on the roof of the vessel. The absorber design is limited by two basic parameters: capacity of the rotary atomizer(s) and dispersion of the flue gas. As SDA absorbers are applied to increasingly larger gas flow rates, the energy of the gas as it is compressed and accelerated through the disperser will overwhelm and imbalance the spray cloud of atomized droplets. One SDA absorber design splits the gas flow into a roof disperser and a centrally mounted disperser to balance the spray cloud from above and below. Another absorber design incorporates three roof-mounted gas dispersers to avoid any need to balance the spray cloud.
Ultimately, the application of SDA technology is limited by the motor, gear box, and wheel capacities of the rotary atomizer. SDA systems are in operation at numerous generating plants ranging in size from 10 MW to over 600 MW. However, multiple absorber vessels have historically been required for plants greater than 300 MW. Practically speaking, SDA absorbers with a single large 1,000 hp atomizer or three 250 hp atomizers designs are limited to facilities generating approximately 350 MW. For capacities in excess of 350 MW, a second absorber vessel will result in more complex system layout and additional capital costs.
Operating labor and maintenance costs for any FGD system are functions of the system complexity and the number of rotating pieces of equipment within the envelope of the system. All systems with atomizers must be taken off-line periodically for inspection, cleaning, and parts replacement. The high-speed atomizers will develop scaling on the wheels, causing a vibration in the output shaft of the gear box or motor. Wear components, including wheel inserts, gear box bearings, and motor bearings, require monthly inspections and cleaning and periodic replacement (typically annually).
Plants will experience a reduction in SO2 removal when a single large rotating atomizer must be removed and replaced with a spare. For SDA systems with multiple atomizers, there is less SO2 removal degradation during these maintenance periods, but there will be a higher frequency of interruptions due to a greater number of machines. Also, the slakers, screens, mix tanks, agitators, pumps, piping, and valves associated with the lime preparation system represent additional maintenance items.
All dry FGD processes incorporate an aqueous phase reaction between a lime sorbent and gaseous SO2 and SO3. With FGD systems incorporating SDA technology, the lime sorbent is usually (pebble) quicklime (CaO), which must be prepared as a slurry reagent, with water added during slaking of the quicklime. The complete lime-handling and preparation system consists of truck or rail car unloading, solids-handling equipment, storage silos, detention or ball mill slakers, and slurry storage tanks. The resultant lime slurry also contains dust from the system particulate collection device to increase the total solids content of the mixture. The final ratio of solids (slaked lime plus particulate dust) to water in the slurry is always less than 1:1.
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