Flue gas from combustion contains a mix of pollutants – SO2, HCl, HF, NOx, fly ash, and trace metals – each requiring a different removal mechanism. The most common mistake in flue gas scrubber selection is treating all flue gas as a single problem and specifying a generic FGD system without verifying that the other pollutants are also controlled. A 500 MW coal plant burning 3% sulfur coal produces approximately 1.5 million Nm3/h of flue gas containing 2,000-3,000 ppm SO2, 100-500 ppm HCl, 200-500 ppm NOx, and 2-10 gr/acf fly ash. The scrubber must remove SO2 to meet the EPA MATS limit of 0.07 lb/MMBtu while also capturing HCl, HF, and particulate to comply with separate emission limits for each.
This guide covers the types of flue gas scrubbers available (wet FGD, dry, seawater, condensing), the full range of pollutants they remove, key design parameters specific to flue gas service, and a decision framework for selecting the right technology. For the fundamentals of scrubber operation and system design, see our gas scrubber guide and gas scrubber system guide.
Key Takeaways
- Wet limestone FGD is the dominant flue gas scrubber technology (>85% of installed capacity) because it handles the widest range of coal sulfur contents (0.5-5% S) at 95-99% SO2 removal efficiency while producing saleable gypsum. For plants with <2% S coal or limited water supply, dry or seawater scrubbers are often the better economic choice.
- Flue gas scrubbers must handle multiple pollutants, not just SO2. HCl, HF, NOx, fly ash, and mercury each have separate emission limits. Wet FGD provides 99%+ removal of HCl and HF and 50-90% mercury capture as co-benefits, but NOx removal is limited to 70-90% without additional oxidation or SCR.
- Energy consumption is the dominant operating cost driver. The recirculation pumps for a 500 MW wet FGD system consume 8-15 MW of power – 2-3% of the unit’s output. Every 10 gal/1,000 acfm increase in L/G ratio raises pump power by 3-5% while improving SO2 removal by a similar margin.
- Material selection determines FGD system service life. Rubber-lined carbon steel is the standard material for absorber vessels, but high-alloy stainless steel (254SMO, C276) is required in the most corrosive zones – the gas inlet, absorber outlet, and mist eliminator where chloride levels reach 10,000-50,000 ppm and acid dew point corrosion attacks unprotected surfaces.
- FGD wastewater treatment is required and increasingly stringent. The blowdown stream contains concentrated chlorides, mercury, arsenic, selenium, and other metals. EPA Effluent Limitations Guidelines require mercury below 0.003 mg/L and selenium below 0.012 mg/L – levels requiring chemical precipitation plus advanced treatment for most FGD systems.
What Is a Flue Gas Scrubber?
A flue gas scrubber is an air pollution control system designed specifically for combustion exhaust – the gas produced by burning coal, oil, natural gas, biomass, or waste in boilers, furnaces, incinerators, and engines. The key distinction from a chemical process scrubber is the scale and conditions: flue gas volumes range from 100,000 to 5,000,000+ cfm (versus 1,000-50,000 cfm for most process vents), inlet temperatures range from 120-180C (versus ambient to 80C for process vents), the gas carries fly ash (2-10 gr/acf in coal-fired applications), and the flow rate varies with boiler load (typically 3:1 turndown).
Flue gas scrubbers use the same fundamental gas-liquid contact principle as other scrubbers, but the design must account for the high temperature (requiring a quench section), the high dust loading (ruling out packed bed designs unless preceded by particulate removal), and the variable gas composition caused by fuel changes. The most common type of flue gas scrubber is the wet limestone FGD system used in coal-fired power plants, but other types – dry scrubbers, seawater scrubbers, and condensing scrubbers – serve specific applications where wet FGD is not the best fit. For the general operating principles that apply to all scrubber types, refer to our gas scrubber guide.
Flue Gas Pollutants – What’s in the Stack
Flue gas contains five major pollutant classes, each requiring a different removal approach. The most common mistake is focusing exclusively on SO2 removal while neglecting the other pollutants that also have emission limits.
SO2 – Primary Target
Sulfur dioxide is the main target of flue gas scrubbers, driven by its role in acid rain formation and its regulation under EPA MATS, NSPS, and other standards. Coal sulfur content ranges from 0.5% to 5%, producing flue gas SO2 concentrations of 500-5,000 ppm. Wet limestone FGD removes 95-99% of SO2 through the reaction: CaCO3 + SO2 + 0.5 O2 + 2 H2O -> CaSO4.2H2O (gypsum). The reaction requires a controlled pH of 5.5-6.2, a liquid-to-gas ratio of 50-150 gal/1,000 cfm, and adequate oxidation air to convert calcium sulfite to gypsum. SO2 removal accounts for 60-70% of total FGD operating cost, driven primarily by the energy consumption of the recirculation pumps (8-15 MW for a 500 MW unit).
HCl and HF
Hydrogen chloride and hydrogen fluoride are present in flue gas at 50-500 ppm (HCl) and 5-50 ppm (HF), depending on fuel composition. Both are highly soluble and are removed at 99%+ as a co-benefit of wet FGD – the alkaline slurry neutralizes these acid gases alongside SO2 at no additional chemical cost. The design implication for HF is material selection: HF attacks the silica in glass fiber, so FRP vessels handling HF-laden flue gas must use a carbon fiber or thermoplastic barrier layer to prevent corrosion of the glass reinforcement.
NOx – The Problem Gas
Nitrogen oxides present the greatest challenge for flue gas scrubbers. NOx consists of approximately 90-95% NO and 5-10% NO2. NO has extremely low water solubility (Henry’s Law constant H ~ 180 atm/mole fraction, versus HCl at 0.0016), making physical absorption ineffective. NO2 is moderately soluble but typically constitutes less than 10% of total NOx. The result: conventional wet scrubbers remove only 70-90% of NOx, insufficient for most emission limits. Achieving higher NOx removal requires either oxidation of NO to NO2 using ozone or chlorine dioxide (adding 20-40% to operating cost), or placing a selective catalytic reduction (SCR) system upstream of the scrubber. For plants that need >90% NOx removal, a wet scrubber alone is not the answer.
Fly Ash and Particulate Matter
Coal fly ash loading ranges from 2-10 gr/acf (4.5-23 g/Nm3) depending on coal ash content and the efficiency of upstream particulate control. If an ESP or baghouse is installed ahead of the scrubber, the inlet loading to the scrubber drops below 0.1 gr/acf and a packed bed or spray tower is feasible. Without upstream PM control, the high ash loading rules out packed bed designs (the ash accumulates in the packing and increases pressure drop by 2-3x within weeks) and favors venturi scrubbers or tray towers. In wet FGD systems with upstream ESP, the scrubber provides additional PM removal as a co-benefit, achieving outlet levels below 0.015 lb/MMBtu.
Mercury and Trace Metals
Wet FGD systems provide 50-90% mercury removal as a co-benefit through absorption of oxidized mercury (Hg2+) into the slurry. Elemental mercury (Hg0) is not captured and requires upstream oxidation (activated carbon injection or SCR catalyst) for removal. The captured mercury reports to the gypsum and the wastewater, creating a disposal issue that must be managed under the EPA MATS Mercury and Air Toxics Standards (MATS). Trace metals including arsenic, selenium, and cadmium are also captured in the FGD slurry at 50-80% removal, concentrating in the wastewater stream that requires treatment under the Effluent Limitations Guidelines (ELG).
Flue Gas Scrubber Types
Four main types of flue gas scrubber are commercially available, each with a distinct operating principle and application range. The selection depends on fuel sulfur content, plant size, wastewater disposal options, and regulatory requirements.
Wet FGD Scrubbers (Limestone/Gypsum Process)
Wet flue gas desulfurization using limestone slurry is the dominant technology, installed on more than 85% of the world’s coal-fired FGD capacity. The process uses a spray tower absorber where limestone slurry (CaCO3) is sprayed into the flue gas. SO2 dissolves into the slurry droplets and reacts with the limestone to form calcium sulfite (CaSO3), which is oxidized to gypsum (CaSO4.2H2O) by injecting air into the reaction tank. The gypsum is dewatered and sold for wallboard and cement production.
Limestone Forced Oxidation (Standard)
The standard wet FGD configuration uses forced oxidation to produce gypsum. Key design parameters: liquid-to-gas ratio 50-150 gal/1,000 acfm, slurry pH 5.5-6.2, absorber gas velocity 10-15 ft/s, reaction tank retention time 4-8 minutes. SO2 removal efficiency is 95-99%, with the highest efficiencies achieved at lower pH (5.5-5.8) and higher L/G ratios. The byproduct gypsum (typically 90%+ purity) is saleable for wallboard manufacturing when the calcium sulfite content is below 1%.
Lime Scrubbing
Lime (CaO or Ca(OH)2) is more reactive than limestone and provides higher SO2 removal at lower L/G ratios, but lime costs 2-3x more per ton of SO2 removed. Lime scrubbing is used where space is limited (smaller absorber required), where limestone quality is poor, or where the plant already handles lime for other processes.
NaOH Scrubbing
Sodium hydroxide scrubbing is used for smaller installations where the capital cost of a limestone handling and dewatering system cannot be justified. NaOH is fully soluble, eliminating the slurry handling equipment. Operating cost is 4-6x higher than limestone because NaOH is more expensive and cannot be regenerated. Suitable for plants under 50 MW or for backup/emergency SO2 control.
Dry and Semi-Dry Scrubbers
Dry scrubbers use a lime slurry or sodium bicarbonate injected into the flue gas duct or a spray dryer absorber vessel. The water in the slurry evaporates as the gas is cooled, and the reaction product is collected as dry solids in a downstream baghouse. Dry scrubbers achieve 90-95% SO2 removal with no wastewater discharge. They are the preferred technology where water supply is limited, where wastewater discharge is not permitted, or for lower-sulfur coal applications (below 2% S). The capital cost is approximately 80% of a wet FGD system, but the operating cost is 1.5-2x higher due to reagent consumption.
Seawater Scrubbers
Seawater scrubbers use the natural alkalinity of seawater (pH 8.0-8.3, alkalinity 2.2-2.5 meq/L) to neutralize SO2 without chemical reagents. The flue gas is contacted with seawater in a packed bed or spray tower, where SO2 dissolves and reacts with bicarbonate: SO2 + H2O + 0.5 O2 -> SO42- + 2 H+. The acidified seawater is aerated before discharge to restore oxygen levels and convert sulfite to sulfate (natural seawater contains approximately 2,700 mg/L sulfate, so the added sulfate from scrubbing is minor). Seawater scrubbers achieve 95-98% SO2 removal with no chemical consumption and no solid waste. They are only feasible for coastal plants with access to large volumes of seawater – typically 40-80 m3 of seawater per MWh of power generated.
Condensing Scrubbers
Condensing scrubbers cool the flue gas below its dew point, causing water vapor to condense on fine particles and soluble gas molecules. The condensation process simultaneously captures SO2, HCl, HF, particulate, and mercury – and recovers the latent heat of condensation for district heating or feedwater preheating. Condensing scrubbers are an emerging technology used primarily in biomass and waste-to-energy plants where both emission control and heat recovery are economically valuable. The efficiency for SO2 removal is typically 90-98%, and the recovered heat can improve overall plant efficiency by 3-8%.
Type Comparison
| Parameter | Wet FGD | Dry/Semi-Dry | Seawater | Condensing |
|---|---|---|---|---|
| SO2 removal efficiency | 95-99% | 90-95% | 95-98% | 90-98% |
| Capital cost index | 1.0x (baseline) | 0.8x | 1.0-1.2x | 1.3-1.6x |
| Operating cost | Moderate | High (reagent) | Low (no reagent) | Low-Moderate |
| Wastewater generated | Yes (blowdown) | No | Yes (seawater discharge) | Yes (condensate) |
| Solid byproduct | Gypsum (saleable) | Fly ash + lime solids | None | Sludge |
| Max unit size | >1,000 MW | 300-500 MW | >500 MW (coastal) | 100-300 MW |
| Sulfur limit | Any (up to 5% S) | <3% S | <2% S | <2% S |
FGD System Components
A wet FGD system consists of five main subsystems, each with specific design requirements driven by the large gas volumes, abrasive slurry, and corrosive conditions of flue gas scrubbing.
Absorber Tower
The absorber tower is the main gas-liquid contact vessel. Most modern wet FGD systems use a countercurrent spray tower with 3-6 spray levels, each containing 50-200 nozzles depending on the absorber diameter. Design gas velocity is 10-15 ft/s – higher velocities increase mass transfer but also increase mist carryover and pressure drop. The reaction tank at the bottom of the absorber holds 4-8 minutes of slurry volume, providing residence time for limestone dissolution, SO2 reaction, and gypsum crystallization. Typical absorber dimensions for a 500 MW unit: 40-60 ft diameter, 80-120 ft total height.
Slurry Handling System
The slurry system includes limestone grinding and preparation, recirculation pumps, slurry piping, and agitators. Recirculation pumps are the largest single energy consumer in the FGD system – each pump handles 20,000-60,000 gpm at 60-100 ft head, requiring 1,000-3,000 hp per pump. A 500 MW unit typically operates 3-4 recirculation pumps simultaneously. The slurry contains 10-20% solids by weight, requiring abrasive-resistant materials (rubber-lined piping, hard metal impellers).
Oxidation Air System
Oxidation air is injected into the reaction tank to convert calcium sulfite (CaSO3) to gypsum (CaSO4.2H2O). The oxidation air requirement is approximately 1.5-2.0x the stoichiometric requirement based on SO2 removal. Oxidation air blowers supply 50,000-150,000 scfm at 8-15 psi for a 500 MW unit, consuming 2-5 MW of power. Inadequate oxidation produces calcium sulfite, which forms hard scale on tower internals and reduces the gypsum purity below saleable quality.
Mist Eliminator
Flue gas leaving the absorber is saturated with water vapor and carries entrained slurry droplets. Two-stage mist eliminators (typically chevron vane packs) are installed at the absorber outlet to reduce liquid carryover to below 50 mg/Nm3. The first stage removes coarse droplets, and the second stage polishes fine droplets to meet opacity requirements. Wash water sprays operate intermittently on each stage to prevent solids buildup on the vanes.
Gypsum Dewatering System
Gypsum slurry from the absorber is fed to a hydrocyclone cluster for primary dewatering (thickening to 50-60% solids), followed by a vacuum belt filter for final dewatering to below 10% moisture content. The dewatered gypsum contains >90% CaSO4.2H2O when the FGD system is operating correctly and can be sold for wallboard manufacturing. The filtrate is returned to the absorber to recover water and unreacted limestone.
Key Design Parameters for Flue Gas Scrubbers
Flue gas scrubber design parameters differ significantly from chemical process scrubbers. Applying chemical scrubber design rules to a flue gas application leads to undersized quench sections, corroded materials, and efficiency shortfalls.
Gas Temperature and Quench
Flue gas enters the scrubber at 120-180C (250-360F), depending on the heat recovery equipment upstream. The scrubber operates at the adiabatic saturation temperature of 50-70C (120-160F). A quench section at the gas inlet cools the flue gas to saturation temperature by direct water spray before it reaches the absorber zone. The quench system must be designed for the gas temperature, the water evaporation rate (approximately 0.5 g of water per m3 of gas per degree C of cooling), and the thermal stresses from temperature gradients. Inadequate quench design causes thermal damage to FRP or lining materials and condensation of sulfuric acid on cold surfaces downstream of the quench.
SO2 Load and Turndown
Coal sulfur content can vary by a factor of 10 between different coal sources. The FGD system design must be based on the maximum expected sulfur content with a 10-20% safety margin, not the average. Load following is equally important: a power plant may operate at 30-100% load, and the scrubber must maintain SO2 removal efficiency across this range. The primary control variable is slurry pH: lowering pH increases SO2 removal efficiency but reduces limestone utilization and increases the risk of corrosion. Typical pH control range is 5.0-6.2, with the setpoint adjusted based on inlet SO2 concentration and required outlet emission level.
Liquid-to-Gas Ratio
The liquid-to-gas ratio for wet FGD systems ranges from 50-150 gal/1,000 acfm – 10-30 times higher than chemical process scrubbers. The high L/G is required because the reaction between SO2 and limestone is relatively slow and mass transfer is limited by the low solubility of SO2 at the operating pH. Each additional 10 gal/1,000 acfm of L/G increases both SO2 removal and recirculation pump power by approximately 3-5%. Optimizing L/G is the primary tool for balancing removal efficiency against operating cost.
Material Selection for Flue Gas Service
Material selection is driven by three corrosion mechanisms: acid dew point corrosion from sulfuric acid condensing at 120-160C, chloride stress corrosion cracking in the absorber zone where chloride concentrations reach 10,000-50,000 ppm, and abrasive wear from limestone slurry and fly ash.
Rubber-Lined Carbon Steel
Rubber-lined carbon steel is the standard material for wet FGD absorber towers. The carbon steel provides structural strength, and the rubber lining (typically 3-6 mm thick chlorobutyl or bromobutyl rubber) protects against acid attack. Temperature limit is approximately 100C (210F) for continuous service. Cost index: 1.0x (baseline).
High-Alloy Stainless Steel (254SMO, C276)
High-alloy stainless steels are used in the most corrosive zones: the gas inlet duct (where acid dew point corrosion is most aggressive), the absorber outlet duct (where chlorides concentrate), and the mist eliminator (where chloride levels are highest). 254SMO (6% Mo) and C276 (16% Mo + W) provide resistance to pitting and crevice corrosion in high-chloride environments. Cost index: 3-5x.
FRP
FRP is suitable for the lower-temperature sections of flue gas scrubbers below 100C where chloride levels are moderate. FRP costs less than high-alloy stainless steel but cannot withstand the quench zone temperatures or the abrasive conditions of slurry handling. Resin selection (vinyl ester for acid service) and proper corrosion barrier thickness (90-120 mil) are critical for FRP service life in FGD applications.
FGD Technologies Comparison
Five FGD technologies are commercially available. The selection depends on fuel sulfur content, plant size, water availability, wastewater disposal options, byproduct marketability, and capital budget.
| Technology | Reagent | SO2 Removal | Byproduct | Capital Index | Wastewater | Best Application |
|---|---|---|---|---|---|---|
| Wet limestone FGD | CaCO3 | 95-99% | Gypsum (saleable) | 1.0x | Yes | >100 MW, >1% S |
| Dry SDA + baghouse | Ca(OH)2 | 90-95% | CaSO3 + fly ash | 0.8x | No | 50-300 MW, <2% S, water-limited |
| Seawater scrubber | Seawater | 95-98% | None | 1.0-1.2x | Seawater discharge | >300 MW coastal, <2% S |
| Ammonia FGD | NH3 | 95-99% | (NH4)2SO4 (fertilizer) | 1.2x | No | Plants with NH3 available |
| Magnesium oxide FGD | MgO | 90-95% | MgSO4 (recoverable) | 0.9x | No | 50-200 MW, medium S |
The capital cost index represents relative installed cost normalized to wet limestone FGD. Actual costs vary significantly by region, material choice, and site conditions. Operating cost comparison must include reagent consumption, energy (recirculation pumps, oxidation blowers, fans), wastewater treatment, byproduct disposal or sale, and maintenance. A detailed cost analysis specific to your fuel and site conditions is required for investment decisions.
FGD Wastewater Treatment
Wet FGD systems produce a wastewater stream that requires treatment before discharge. The blowdown from the absorber loop contains concentrated chlorides, heavy metals (mercury, arsenic, selenium, cadmium), and suspended solids. Typical FGD wastewater characteristics: pH 4-6, total dissolved solids 20,000-60,000 mg/L, chloride 10,000-50,000 mg/L, and heavy metals at 0.1-10 mg/L each.
Treatment follows a multi-stage process: chemical precipitation (lime or sulfide dosing to precipitate metals), flocculation and clarification to remove suspended solids, and pH adjustment before discharge. For plants facing zero liquid discharge (ZLD) requirements, additional treatment stages including evaporation, crystallization, or brine concentration are required. The EPA’s Effluent Limitations Guidelines (ELG) regulate FGD wastewater discharge, requiring mercury below 0.003 mg/L, arsenic below 0.008 mg/L, and selenium below 0.012 mg/L in most cases – levels that require advanced treatment beyond simple precipitation.
Case Study – 500 MW Coal-Fired FGD System
A 500 MW coal-fired power plant burning 3.5% sulfur coal with 15% ash content installs a wet limestone FGD system. The key design parameters and operating data provide a realistic reference for system sizing and costing.
Flue gas flow: 1.5 million Nm3/h at 150C. Inlet SO2: 3,200 ppm (8.6 t/h). Required outlet: below 0.07 lb/MMBtu (approximately 95 ppm at full load). Design SO2 removal: 98%. Limestone consumption: 14 t/h at 95% CaCO3 purity (1.03 stoichiometric ratio). Gypsum production: 24 t/h at 90% moisture-free purity. Recirculation pump power: 9 MW (4 x 2,250 kW pumps). Oxidation air blower: 3 MW. Total auxiliary power consumption: 14 MW (2.8% of unit output). System capital cost: approximately $80-120/kW (installed). Annual operating cost: $4-6/MWh including limestone, power, maintenance, and wastewater treatment.
Applications
Flue gas scrubbers are used across multiple industries: coal-fired power plants (the largest market, representing >80% of installed FGD capacity), fluid catalytic cracking units in refineries, municipal waste incinerators, industrial boilers (biomass, coal, and heavy fuel oil), and marine vessels (IMO-compliant exhaust gas cleaning systems). Each application has specific design requirements: refinery FCC scrubbers must handle catalyst fines (alumina-silicate particles that cause abrasive wear), incinerator scrubbers must handle dioxins and mercury, and marine scrubbers must handle varying engine loads and seawater chemistry.
Frequently Asked Questions About Flue Gas Scrubbers
What is a flue gas scrubber?
A flue gas scrubber is an air pollution control system designed for combustion exhaust – gas from coal, oil, gas, biomass, or waste burning in boilers, furnaces, incinerators, and engines. It removes SO2, HCl, HF, particulate, and trace metals from the flue gas using a liquid scrubbing medium, typically limestone slurry (wet FGD), seawater, or a lime-based dry sorbent.
What is the difference between FGD and a flue gas scrubber?
FGD (flue gas desulfurization) is a specific type of flue gas scrubber focused on SO2 removal. A flue gas scrubber is the broader category that includes FGD systems plus other technologies – dry scrubbers, seawater scrubbers, condensing scrubbers – that may remove multiple pollutants including SO2, HCl, HF, NOx, PM, and mercury.
What is the difference between wet and dry flue gas scrubbers?
Wet scrubbers use a liquid slurry (limestone, lime, or seawater) to absorb pollutants and produce a liquid or slurry byproduct. Dry scrubbers inject a dry sorbent or lime slurry that evaporates, producing dry solids collected in a baghouse. Wet scrubbers achieve higher SO2 removal (95-99%) and handle high-sulfur coal but produce wastewater. Dry scrubbers achieve 90-95% removal, produce no wastewater, and are preferred for lower-sulfur coal and water-limited sites.
How much does a flue gas scrubber cost?
Installed capital cost for a wet FGD system ranges from $80-120/kW for a 500 MW plant. Dry scrubber systems cost approximately 80% of wet FGD. Operating cost ranges from $4-6/MWh including limestone, power (recirculation pumps, oxidation blowers, fans), maintenance, and wastewater treatment. The operating cost is dominated by energy consumption of the recirculation pumps (8-15 MW for a 500 MW unit).
Conclusion
Selecting the right flue gas scrubber comes down to matching the technology to the fuel properties, plant size, site conditions, and regulatory requirements. Wet limestone FGD is the established standard for large coal-fired plants with high-sulfur coal where gypsum byproduct can be marketed. Dry scrubbers serve water-limited sites and lower-sulfur applications. Seawater scrubbers provide the lowest operating cost for coastal plants. Condensing scrubbers offer the highest environmental performance with heat recovery for biomass and waste-to-energy plants. The common thread across all types is that design must account for the high temperature, high volume, and variable load that distinguish flue gas from other scrubber gas streams. If you need assistance selecting the appropriate flue gas scrubber technology for your application, contact our engineering team with your fuel analysis, plant size, and emission limits for a preliminary technology assessment and cost estimate.
