EPA-452/F-03-034


# Air Pollution Control Technology Fact Sheet

EPA-CICA Fact Sheet Flue Gas Desulfurization 1 Name of Technology: Flue Gas Desulfurization (FGD) - Wet, Spray Dry, and Dry Scrubbers
Type of Technology: Control Device - absorption and reaction using an alkaline reagent to produce a solid compound.
Applicable Pollutants: Sulfur dioxide (SO 2 )

Achievable Emission Limits/Reductions: Scrubbers are capable of reduction efficiencies in the range of 50% to 98%. The highest removal efficiencies are achieved by wet scrubbers, greater than 90% and the lowest by dry scrubbers, typically less than 80%. Newer dry scrubber designs are capable of higher control efficiencies, on the order of 90%.
Applicable Source Type: Point
Typical Industrial Applications: Stationary coal- and oil-fired combus tion units such as utility and industrial boilers, as well as other industrial combustion units such as municipal and medical waste incinerators, cement and lime kilns, metal smelters, petroleum refineries, glass furnaces, and H 2 SO 4manufacturing facilities. Approximately 85% of t he FGD systems installed in the US are wet systems, 12% are spray dry and 3% are dry systems.

Emission Stream Characteristics:

a. Combustion Unit Size: SO 2scrubbers have been applied combustion units firing coal and oil ranging in size from 5 MW to over 1,500 MW (50 MMBtu/hr to 15,000 MMBut/hr). Dry and spray scrubbers are generally applied to units less than 3,000 MMBtu/hr (300 MW) (EPA, 2000).
b. Temperature: For wet scrubbers, typical inlet gas temperatures are 150°C to 370°C (300°F to 700°F) (FETC, 1996). For spray dry systems, the temperature of the flue gas exiting the absorber must be 10°C to 15°C (20°F to 30°F) above t he adiabatic saturation temperature. Optimal temperatures for SO 2removal for dry sorbent injection systems range from 150°C to 180°C (300°F to 350°F). Optimal temperatures for SO 2removal when applying dry sorbent injection systems vary between 150°C to 1000°C (300°F to 1830°F) depending on the sorbent properties (Joseph, 1998)

c. Pollutant Loading: SO 2scrubbers are limited to dilute SO 2waste gas streams of approximately 2000 ppm.(Cooper, 2002).

d. Other Considerations: The amount of chlorine in the flue gas affects the amount of water evaporated by the system due to the formation of salts. Chlorine c ontent improves the SO 2 removal but also results in salt deposition on the absorber and downstream equipment (Schnelle, 2002). An additional or upgraded induced draft (ID) fan may be required to compensate for flue gas pressure drop across the absorber.EPA-CICA Fact Sheet Flue Gas Desulfurization 2 Many wet systems reheat the flue gas downstream of the absorber to prevent corrosion caused by condensation inside the ducts and stack and reduce plume visibility.
Emission Stream Pretreatment Requirements: In spray dry and dry injection systems, the flue gas must be cooled to a temperature range of 10°C to 15°C (20°F to 30°F) above adiabatic saturation. This temperature range avoids wet solids deposition on downstream equipment and plugging of the baghouse. A heat recovery boiler, an evaporative cooler or a heat exchanger is typically used to cool the gas.

Cost Information:
Capital costs for SO 2scrubbers have decreased by over 30% si nce the beginning of the 1990's. Current costs for SO 2scrubbers applied to electric utilities are r eported to be approximately $100/kW (Smith, 2001). Retrofit of scrubbers on existing units can increase the capi tal cost up to 30%. Retrofit costs vary significantly between sites and depend on space limitations, major modi fications to existing equipment (e.g., ductwork and stack) and the operating condition of t he units (e.g., temperature, flowrate).
O&M costs increase with increasing su lfur content since more reagent is required to treat the same volume of gas. Typical reagents such as lime and limestone are inexpensive; however, the use of proprietary reagents or reagent enhancers or additives that can si gnificantly increase the O&M cost. Limestone is generally available for 10 to 20 $/ton and lime is ava ilable for 60 to 80 $/ton (Smith, 2001). Waste product disposal costs vary from $10/ton to $30/ton and byproduct saleable prices vary from 0 to 15 $/ton (Smith, 2001). The addition of a scrubbers causes a loss of energy available for generating steam due to evaporation of water and the energy required to drive t he reaction. New scrubber designs result in an energy penalty of less than 1% of the tota l plant energy (Srivastava, 2001).

Table 1a: Summary of Cost Information in $/MMBtu/hr (2001 Dollars) a

Scrubber Type Unit Size Capital Cost O&M Cost b Annual Cost Cost per Ton of Pollutant Removed (MMBtu/hr) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/ton) Wet > 4,000 10,000 -25,000 200 - 800 25 - 40 200 - 500 < 4,000 25,000 - 150,000 800 - 1,800 60 - 600 500 - 5,000 Spray Dry > 2,000 4,000 - 15,000 600 - 1,000 150 - 300 < 2,000 30,000 - 150,000 1,000 - 30,000 10,000 - 50,000 500 - 4,000

Table 1b: Summary of Cost Information in $/MW (2001 Dollars) a

Scrubber Type Unit Size Capital Cost O&M Cost b Annual Cost Cost per Ton of Pollutant Removed (MW) ($/kW) ($/kW) ($/kW) ($/ton) Wet > 400 100 - 250 2 - 8 20 - 50 200 - 500 < 400 250 - 1,500 8 - 20 50 - 200 500 - 5,000 Spray Dry > 200 40 - 150 4 - 10 20 -50 150 - 300 < 200 150 - 1,500 10 - 300 50 - 500 500 - 4,000

a ( EIA, 2002; EPA, 2000; Srivastava, 2001)
bAssumes capacity factor > 80%EPA-CICA Fact Sheet Flue Gas Desulfurization 3 Theory of Operation:

The FDG or SO 2scrubbing process typically uses a calcium or sodium based alkaline reagent. The reagent is injected in the flue gas in a spray tower or directly into the duct. The SO 2is absorbed, neutralized and/or oxidized by the alkaline reagent into a solid compound, either calcium or sodium sulfate. The solid is removed from the waste gas stream using downstream equipment.
Scrubbers are classified as “once-through” or “regenerable”, based on how the solids generated by the process are handled

. Once-through systems either di spose of the spent sorbent as a waste or utilize it as a byproduct. Regenerable systems recycle the sorbent back into the system. At the present time, regenerable processes have higher costs than once-th rough processes; however, regenerable processes might be chosen if space or disposal options are lim ited and markets for byproducts (gypsum) are available (Cooper, 2002). In 1998, approximately 3% of FDG systems installed in the US were regenerable.
Both types of systems, once-thr ough and regenerable, can be further categorized as wet, dry, or semi-dry. Each of these processes is described in the following sections.
Wet Systems
In a wet scrubber system, flue gas is ducted to a spray tower where an aqueous slurry of sorbent is injected into the flue gas. To provide good contac t between the waste gas and sorbent, the nozzles and injection locations are designed to optimize the size and density of slurry droplet s formed by the system. A portion of the water in the slurry is evaporat ed and the waste gas stream becomes saturated with water vapor. Sulfur dioxide dissolves into the sl urry droplets where it reacts with the alkaline particulates. The slurry falls to the bottom of t he absorber where it is collected. Treated flue gas passes through a mist eliminator before ex iting the absorber which removes anyentrained slurry droplets. The absorber effluent is sent to a reaction tank where the SO 2 -alkali reaction is completed forming a neutral salt. In a regenerable system, the spent slurry is recycled back to the absorber. Once through systems dewater the spent slurry for di sposal or use as a by-product.
Typical sorbent material is limestone, or lime. Li mestone is very inexpensive but control efficiencies for limestone systems are limited to appr oximately 90%. Lime is easier to manage on-site and has control efficiencies up to 95% but is significantly more cost ly (Cooper 2002). Proprietary sorbents with reactivityenhancing additives provide control efficiencies greater t han 95% but are very costly. Electrical utilities store large volumes of limestone or lime on site and prepare the sorbent for injection, but this is generally not cost effective for smaller industrial applications.
The volume ratio of reagent slurry to waste gas is re ferred to as the liquid to gas ratio (L/G). The L/G ratio determines the amount of reagentavailable for reaction with SO 2 . Higher L/G ratios result in higher control efficiencies. Higher L/G al so increases oxidation of the SO 2 , which results in a decrease of the formation of scale in the absorber. O&M costs are a direct function of reagent usage, so increasing the L/G increases annual costs. L/G ratios are appr oximately 1:1 for wet scrubbers and are expressed as gallons of slurry per 1000 ft 3of flue gas (liters of slurry/1000Nm 3of flue gas).

Oxidation of the slurry sorbent causes gypsum (calcium sulfate) scale to form in the absorber. Limestone forced oxidation (LSFO) is a newer process based on wet limestone scrubbing which reduces scale. In LSFO, air is added to the reaction tank wh ich oxidizes the spent slurry to gypsum. The gypsum is removed from the reaction tank prior to the slurry being recycled to the absorber. The recycle slurry has a lower concentration of gypsum and scale formation in the absorber is significantly reduced. Gypsum can be commercially sold, eliminating the need for landfilling of the wa ste product (Srivastava, 2001). In addition to scale control, the larger si ze gypsum crystals formed in LSFO settle and dewaterEPA-CICA Fact Sheet Flue Gas Desulfurization 4 more efficiently, reducing the size of the by product handling equipment (EPA, 2002). However, LSFO requires additional blowers which increase t he capital and annual costs of the system.
Wet limestone scrubbing has high capital and operati ng cost due to the handling of liquid reagent and waste. Nonetheless, it is the pr eferred process for coal-fired electric utility power plants burning coal due to the low cost of limestone and SO 2 control efficiencies from 90% up to 98% (Schnelle, 2002).
Semi-Dry Systems
Semi-dry systems, or spray dryers, inject an aqueous sorbent slurry similar to a wet system, however, the slurry has a higher sorbent concentration. As t he hot flue gas mixes with the slurry solution, water from the slurry is evaporated. The water that remains on the solid sorbent enhances the reaction with SO 2 . The process forms a dry waste product which is collected with a standard particulate matter (PM) collection device such as a baghouse or ESP. The wa ste product can be disposed, sold as a byproduct or recycled to the slurry.
Various calcium and sodium based reagents can be ut ilized as sorbent. Spray dry scrubbers typically inject lime since it is more reactive than limes tone and less expensive than s odium based reagents. The reagent slurry is injected through ro tary atomizers or dual-fluid nozzlesto create a finer droplet spray than wet scrubber system s (Srivastava, 2000).
The performance of a lime spray dry scrubber is mo re sensitive to operating conditions. A “close approach” to adiabatic saturation temperature is required to maximize the removal of SO 2 . However, excess moisture causes the wet solids to deposit on the absorber and downstream equipment. The optimum temperature is 10°C to 15°C (20°F to 50°F) below saturation temperature (Srivastava, 2000). Lower L/G ratios, approximately 1:3, must be utilized do to the limitation on flue gas moisture (Schnelle, 2002). Flue gas with high SO 2concentrations or temperatures reduce the performance of the scrubber (Schnelle, 2002).

SO 2 control efficiencies for spray dry scrubbers are slightly lower than wet systems, between 80% and 90% due to its lower reactivity and L/G ratios. App lication of a single spray dry absorber is limited to combustion units less than 200 MW (2,000 MMBtu/hr) (IEA, 2001). Larger combustion units require multiple absorber systems. The capital and operating cost for spray dry scrubbers are lower than for wet scrubbing because equipment for handling wet waste products is not required. In addition, carbon steel can be used to manufacture the absorber since the fl ue gas is less humid. Typically applications include electric utility units burning low- to medium- su lfur coal, industrial boilers, and municipal waste incinerators that require 80% SO 2 control efficiency (Schnelle, 2002).
Dry systems
Dry sorbent injection syst ems, pneumatically inject powdered sorbentdirectly into the furnace, the economizer, or downstream ductwork. The dry waste product is removed using particulate control equipment such as a baghouse or electrostatic precipit ator (ESP). The flue gas is generally cooled prior to the entering the PM control device. Water can be injected upstream of the absorber to enhance SO 2 removal (Srivastava, 2001).
Furnace injection requires flue gas temperatures between 950°C to 1000°C (1740°F to 1830°F) in order to decompose the sorbent into porous solids with high surface area (Srivastava 2001). Injection into the economizer requires temperatures of 500°C to 570°C (930°F to 1060°F) (Srivastava 2001). Duct injection requires the dispersion of a fine sorbent sp ray into the flue gas downstream of the air preheater. The injection must occur at flue gas temperat ures between 150°C to 180°C (300°F to 350°F) (Joseph, 1998).EPA-CICA Fact Sheet Flue Gas Desulfurization 5 Dry sorbent systems typically use calcium and sodi um based alkaline reagents. A number of proprietary reagents are also available. A typica l injection system uses several in jection lances protruding from the furnace or duct walls. Injection of water dow nstream of the sorbent injection increases SO 2removal by the sorbent.

An even distribution of sorbent across the reactor and adequate residence time at the proper temperature are critical for high SO 2removal rates (Srivastava 2001). Flue gas must be kept 10°C to 15°C (20°F to 50°F) below saturation temperature to minimize deposits on the absorber and downstream equipment.
Dry scrubbers have significantly lower capital and annual costs than wet sy stems because they are simpler, demand less water and waste disposal is less complex. Dry injection systems install easily and use less space, therefore, they are good candidates retrofit applications. SO 2removal efficiencies are significantly lower than wet syst ems, between 50% and 60% for calciu m based sorbents. Sodium based dry sorbent injection into the duct can achieve up to 80% control efficiencies (Srivastava 2001). Dry sorbent injection is viewed as an emerging SO 2control technology for medium to small industrial boiler applications. Newer applications of dry sorbent in jection on small coal-fired industrial boilers have achieved greater than 90% SO 2control efficiencies.
Advantages:
• High SO 2removal efficiencies, from 50% up to 98%. • Products of reaction may be reusable • Difficulty of retrofit is moderate to low • Inexpensive and readily available reagents Disadvantages:
• High capital and O&M costs • Scaling and deposit of wet solids on absorber and downstream equipment • Wet systems generate a wet waste produc t and may result in a visible plume • Cannot be used for waste gas SO 2concentrations greater than 2,000 ppm • Disposal of waste products signi ficantly increases O&M costs

References:
Cooper, 2002. Cooper, C.D. and Alley, F.C. Air Pollution Control : A Design Approach . Waveland Press, Inc. Prospect Heights, IL, 2002.

EPA, 2000. Srivastava Ravi K. Controlling SO2Emissions: A Review of Technologies. US Environmental Protection Agency, Office of Research and De velopment. EPA/600/R-00/093. Washington, D.C. 2002. http://www.epa.gov/ordntrnt/O RD/WebPubs/so2/index.html

FETC, 1996. Electric Utility Engineer’s FGD Manual, Volume 1: FGD Process Design . Department of Energy, Federal Energy Technol ogy Center. Morgantown, WV, 1996.
IEA, 2001. “ Coal Research, Sorbent Injection Systems for SO 2 Control”, Clean Coal Technologies Database. http://ww.iea-coal.org.u k/CCTdatabase/sorbing.htm.
Joseph, 1998. Joseph, G. T. and Beachler, D.S. “Scrubber Systems Operation Review APTI Course”. Developed by North Carolina State University under EPA Cooperative Assistance Agreement. Raleigh, N.C 1998.EPA-CICA Fact Sheet Flue Gas Desulfurization 6 Schenelle, 2002. Schenelle, K.B. Jr and Brown, C.A. Air Pollution Control Technology Handbook . CRC Press LLC. Boca Raton, FL. 2002.
Smith 2001. Smith, Douglas. “SO 2Controls: Cost of Scrubbers down to $100/kW”. Power Engineering, September, 2001.

Srivastava, 2001. Srivastava R. K., and W. Josewicz .. “Flue Gas Desulfurization: The State of the Art”. Air and Waste Management Assoc., 51:1676-1688, 2001.

EIA, 2002. EIA-767 Database; Annual Steam-Elect ric Plant Operation and Design Data, 2001. Energy Information Administration, Departm ent of Energy. November 26, 2002. http://www.eia.doe.gov/cneaf/e lectricity/page/eia767.html