Coal plants control sulfur dioxide (SO₂) and particulate matter with different equipment: sulfur controls remove or react with sulfur compounds in fuel or flue gas, while particle collectors capture fly ash and other solids. A typical system may combine fuel choices, a scrubber or sorbent injection, and an electrostatic precipitator or fabric-filter baghouse. Captured pollutants become residual materials that still need to be managed.
Why sulfur dioxide and particles need different controls
Burning coal turns some of its sulfur into sulfur oxides, including SO₂, carried in the flue gas. Combustion also produces fly ash, fine particles that travel with the gas. A scrubber or sorbent system targets SO₂ and other acid gases; an electrostatic precipitator (ESP) or fabric filter captures particles. Some systems create reaction solids that must then be collected by a particle-control device.
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How coal plants reduce sulfur dioxide
Lowering sulfur before combustion
Operators can select lower-sulfur coal, clean or blend fuels, or switch fuels where the boiler and plant can accommodate the change. Fuel blending or switching can reduce acid-gas emissions, but changing between coal ranks may require costly modifications. Natural gas may be an option in some circumstances, depending on plant configuration. The U.S. EPA describes fuel choices and sulfur controls in its power-sector progress report.
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Capturing sulfur in the boiler
In a fluidized-bed boiler, limestone can be injected into the furnace to react with sulfur compounds as fuel burns. This is an in-combustion control option; it is distinct from treating flue gas after combustion.
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Wet flue-gas desulfurization
Flue-gas desulfurization (FGD), commonly called scrubbing, is the principal post-combustion method for controlling SO₂ at coal-fired generating units. A wet scrubber brings flue gas into contact with an alkaline liquid slurry, often made with lime or limestone. SO₂ reacts with the reagent and moves into the liquid and residual stream rather than continuing out with the treated gas.
In its 2011 technical analysis, EPA described modern wet scrubbers as capable of 96% SO₂ removal. That is a technology capability, not a guaranteed result for every operating plant; reagent choice, design, and operating conditions matter. Wet systems use slurry and generate wet residuals, and EPA’s 1999 report says they produce more waste than dry systems. EPA’s 2011 MATS analysis discusses scrubber technologies and performance; its 1999 report describes waste from fossil-fuel combustion.
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Dry FGD and dry sorbent injection
Dry FGD contacts flue gas with a sorbent without saturating the gas as a wet scrubber does. The reaction creates solids, which are typically captured downstream with fly ash. EPA’s 2011 technical analysis says modern lime-based dry FGD paired with a downstream fabric filter can remove at least 93% of SO₂. As with the wet-scrubber figure, this is a technology capability rather than a unit-specific guarantee.
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How plants capture particulate emissions
Electrostatic precipitators
An ESP gives particles an electrical charge and draws them to oppositely charged collection surfaces. In a dry ESP, mechanical rappers dislodge collected material from the plates; a wet ESP washes particles from its collection surfaces. EPA says ESP collection efficiency can exceed 99%, but performance depends on factors such as particle resistivity and flue-gas operating conditions. The figure describes capability, not a result guaranteed at every plant.
Operators monitor indicators that help reveal changes in ESP performance, including outlet particulate concentration, opacity, voltage and current, spark rate, gas temperature and flow, rapper operation, and active fields. These indicators help diagnose equipment performance; they are not a substitute for emissions measurements. EPA lists ESP performance indicators and monitoring approaches.
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Fabric-filter baghouses
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Cyclones and other mechanical collectors
Cyclones and similar mechanical collectors can remove larger particles and serve as pre-collectors ahead of higher-efficiency equipment. EPA’s 1999 report notes that their collection efficiency falls well below 90% for the smallest particles, so a cyclone alone is not equivalent to an ESP or baghouse for fine particulate matter.
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How the control equipment fits together
A plant’s control train depends on its fuel, boiler, existing equipment, and emissions requirements. One common logic is to treat acid gases, then collect fly ash and the solids produced by dry controls. Wet and dry systems differ in residual form and handling; neither makes captured material disappear. The appropriate design also depends on factors such as gas flow, ash loading and resistivity, reagent needs, retrofit space, and how residuals can be managed.
There is no universally best setup. For example, EPA notes that ESPs can be less flexible than fabric filters for some fuel-switching circumstances. Equipment selection must account for the plant’s actual coal and operating conditions, rather than relying on a single efficiency number.
What current U.S. figures show—and what they do not
EPA’s power-sector report, updated November 21, 2024, presents control data through 2023. In the United States, FGD was installed at 75.2% of coal-fired units and accounted for 83.6% of coal-fired electricity generation, measured in MWh, in 2023. Those figures describe U.S. deployment for that year; they should not be treated as a current global share.
The same report says 99% of SO₂ emissions among reporting units covered by the Cross-State Air Pollution Rule (CSAPR) were measured by continuous emissions monitoring systems (CEMS) in 2023. It also says all coal-fired units in that reporting set monitored SO₂ using CEMS. This is a program-specific denominator, not a claim about every U.S. plant or every year. EPA’s report provides the deployment and monitoring figures.
How to interpret removal and monitoring figures
Removal percentages describe what a technology or system can achieve under defined design and operating conditions. They do not establish what a particular plant emits at a particular moment. Real performance depends on equipment configuration, fuel and ash properties, gas conditions, maintenance, and operation. Monitoring data and equipment indicators answer different questions: measured emissions show what leaves the plant, while indicators such as ESP voltage or bag condition help operators identify how controls are functioning.
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