Water-Saving FGD Technologies

By Anne Carpenter
Analyst and Author, IEA Clean Coal Centre

Coal combustion can lead to the formation of sulfur dioxide (SO2) and small amounts of sulfur trioxide (SO3). Further amounts of SO3 are generated in the selective catalytic reduction (SCR) system, which is widely used for NOx control. These oxides can lead to environmental and health problems. Consequently, both international and national regulations have been implemented that limit the amount of sulfur oxides (SOx) and other pollutants that can be emitted from coal-fired power plants. A wide range of commercial flue gas desulfurization (FGD) processes are available to remove SOx from the flue gas. Wet scrubbing is by far the most common system with over 80% of installed capacity worldwide. However, these systems require large supplies of water. FGD technologies that reduce water usage are becoming more important due to the large number of systems being installed globally. Reducing water usage for FGD is particularly important for power plants in arid regions of the world and areas subject to drought. These include areas in Australia, China, South Africa, and the U.S. In addition, the per capita availability of water is declining, and therefore competition between agricultural, urban/domestic, and industrial water use is likely to intensify. This will increase pressure on power plants to lower their water consumption.

The ReACT technology, shown above at the Isogo power plant, is an example of water-saving FGD.

The ReACT technology, shown above at the Isogo power plant, is an example of water-saving FGD.

FGD and Water Consumption

Large amounts of water are consumed within a coal-fired power plant for cooling purposes, FGD makeup, boiler makeup, and other uses. The amount consumed varies depending on the type of plant (subcritical, supercritical, or ultra-supercritical), the cooling system employed, the FGD system, and other factors. Cooling is responsible for most water usage at many plants. The FGD unit is the second-largest consumer of water, closely followed by the boiler.1 Adding a CO2 capture (amine-based) system increases the FGD makeup water consumption by 45–50% for both subcritical and supercritical plants. This is partly because a very low flue gas SOx level (<10 ppm) is needed to avoid contamination of the amine solvent.

For sites utilizing a dry/air cooling system instead of a wet tower, or once-through seawater cooling, the water consumption of the FGD wet scrubber is proportionally much higher: It can easily be responsible for 40–70% of the total site water usage. This article is focused on FGD processes that consume less than 60% of the amount of water used in conventional limestone wet scrubbers.

Semi-Dry Scrubber Technologies

Dry scrubbers are the second most common FGD system installed on coal-fired power plants with less than 10% of global installed capacity. Two principal types of dry scrubbers are in use today:

  • Spray dry scrubbers (SDS), also called spray dry absorbers or lime spray dryers
  • Circulating dry scrubbers (CDS)

Both of these systems use a calcium-based reagent (calcium hydroxide) which is introduced as a slurry in SDS or, in some CDS designs, as a dry powder with separate injection of water. All of the water introduced into the SDS/CDS vessel is evaporated, and therefore no wastewater is generated. So although they are termed dry scrubbers, they do, in fact, consume water and are more accurately classified as semi-dry FGD systems. They typically consume approximately 60% less water than wet scrubbers.2

Spray Dry Scrubbers

Around 40 GW of coal-fired capacity worldwide are equipped with SDS, the majority of which are installed in the U.S. In the SDS process (see Figure 1), a concentrated lime slurry is introduced into the top of the absorber vessel through rotary atomizers or dual fuel nozzles. These atomize the slurry creating a fine mist of droplets containing the reagent, which reacts with SO2 and SO3 in the downward flowing flue gas to form calcium sulfite and sulfate. Simultaneous cooling of the flue gas occurs.

Figure 1. Spray dry scrubber system particulate control device stack solids recycling or disposal

Figure 1. Spray dry scrubber system particulate control device stack solids recycling or disposal

The flue gas exits the absorber and passes through the particulate collector where the reacted sulfur compounds, fly ash, and unreacted sorbent are removed. The clean flue gas is then emitted to the atmosphere through the stack. A portion of the solid products collected from the bottom of the scrubber and the particulate collector is typically mixed with wastewater from elsewhere in the plant and recycled back to the scrubber to improve sorbent utilization, as well as to promote droplet drying in the SDS vessel. The flue gas typically takes 12–15 sec to pass through the scrubber.

Circulating Dry Scrubbers

The total global capacity of utility units using CDS is 15 GW.3 There are units in Europe, Asia (in particular China), and the U.S. Unlike SDS, CDS are upflow reactors in which the flue gas and calcium hydroxide reagent are introduced at the bottom of the reactor. The removal of SOx can take place either in a fluidized bed [circulating fluidized bed (CFB) scrubbers and gas suspension absorbers] or in an entrainment process (NID™).

Circulating Fluidized Bed Scrubbers

A flow diagram of the CFB system at the Dry Fork power plant near Gillette, Wyoming, U.S., is given in Figure 2. The flue gas enters the CFB reactor through a bank of venturis. These increase the velocity of the flue gas before it mixes with the dry hydrated lime (calcium hydroxide) and recycled solids to create the characteristic fluidized bed. The fluidized bed allows a high degree of contact between the flue gas and solids for the desulfurization reactions to occur. In some designs, the fresh sorbent and recycled solids are injected above the venturis, whereas other designs introduce them below the venturis. Just enough water is sprayed into the fluidized bed to both humidify and cool the flue gas to the optimum level for the desulfurization reactions to occur, but no more than can be fully evaporated. Therefore no wastewater is produced.

Figure 2. CFB scrubber system at Dry Fork power plant4

Figure 2. CFB scrubber system at Dry Fork power plant4

A multistage humidification system has been applied in China in which the water is injected at several levels. This approach distributes the water more evenly throughout the reaction zone, and the time that the humidity content is above the critical moisture point is extended. This increases the effective residence time for the desulfurization reactions. SO2 removal efficiency increased by over 1% when the water was injected in two stages, while the total water consumed was the same as that consumed in single-stage humidification.5

The Gas Suspension Absorption process was developed in Denmark by FLS Miljø (now FLSmidth) and is installed on only a few power plants. The process is similar to CFB scrubbers but has an integral cyclone for recirculating the solids via a recirculation box to the fluidized bed reactor.

NID™ System

Alstom’s Novel Integrated Desulfurization (NID™) technology is installed on over 60 coal-fired power plants in Europe, Asia, and the U.S. The unique feature of NID™ technology (see Figure 3) is its J-shaped duct reactor, which has a square cross section and is integrated with a pulse jet fabric filter or, less commonly, an electrostatic precipitator. Fresh reagent and the solid products collected from the fabric filter are hydrated in the humidifier mixer by the addition of water. The humidified calcium hydroxide mixture is then injected near the bottom of the NID™ absorber into the upward flowing flue gas. With the high solids-to-water ratio, evaporation occurs rapidly, cooling and humidifying the flue gas, while flash drying the particulates. No water is sprayed into the absorber, unlike CFB scrubbers. The chemical reactions and drying times within the absorber take less than 2 sec.7

Figure 3. NID™ process6

Figure 3. NID™ process6

How Do Semi-Dry Scrubbers Compare?

The water consumption of the different types of semi-dry scrubbers is similar, and they all consume about 60% less water than wet scrubbers. SDS are typically used on small- to medium-sized units burning low- to medium-sulfur coals. CDS can be applied to larger units burning low- to high-sulfur coals. Single-unit CFB scrubber designs of up to 750 MW are now available.4 SO2 removal efficiency is 90–98% for SDS, and over 98% for state-of-the-art CDS, a value approaching that for wet scrubbers. In addition, dry scrubbers remove nearly 99% of SO3, over 95% of the HCl, HF, and other acid gases, and over 95% of mercury (especially if a mercury sorbent is also used). An advantage of the systems over wet scrubbers is that they capture more SO3 and oxidized mercury. Wet scrubbers typically capture only about 50–80% of oxidized mercury—a pollutant that is now being regulated.

Both SDS and CDS systems have a good turndown capability, enabling operation at low loads, and there is no significant difference in their load-following ability. A CDS system, though, consumes more reagent than a SDS for the same conditions of coal sulfur and SO2 removal efficiency.3 Power consumption is similar at less than 1% of a power plant’s output. This is lower than the 1.2 to 2% consumed by wet scrubbers. Although investment costs are lower for SDS and CDS than for a similar-sized wet scrubber, operating costs are generally higher mainly due to the higher sorbent costs: Lime is more expensive than limestone. Unlike wet scrubbers, dry scrubbers produce no wastewater (and hence no wastewater treatment facilities are required), and the by-products are dry and therefore more easily handled. Unfortunately, there is no market for the by-products, whereas saleable gypsum is produced in the limestone wet scrubbing processes. Disposal of the by-products can be expensive.

Dry Technologies

Dry sorbent injection processes offer the least water consumption of the FGD processes discussed. They consume no water, or only a minimal amount if the sorbent needs hydrating or the flue gas is humidified to improve SO2 removal efficiency. They account for roughly 2% of installed FGD capacity worldwide. The sorbent can be directly injected at several locations, as shown in Figure 4; actual injection locations will be plant specific because not all of the units shown are necessarily present in every power plant. Unlike the wet and dry scrubber processes, the flue gas is not passed through a separate desulfurization vessel—the sorbent is injected directly into the furnace (furnace sorbent injection, FSI), the inlet to the economizer (economizer sorbent injection, ESI), or duct (duct sorbent injection, DSI). Hence there is a smaller footprint and thus the technology is easier to retrofit. The solid reaction products, unreacted sorbent and fly ash, are collected in the downstream particulate control device.

Figure 4. Possible sorbent injection locations

Figure 4. Possible sorbent injection locations

Sorbent injection systems are one of the simplest and cheapest commercial FGD systems to install and operate. The major cost is the sorbent itself. Limestone or hydrated lime (calcium hydroxide) is commonly injected into the furnace as these sorbents can withstand the high temperatures within the furnace. Hydrated lime has been employed for ESI, but the process is little used today. A wider range of sorbents can be used for duct injection. These include calcium- and sodium-based reagents, and can be injected dry, as a slurry, or, in some cases, as a solution (sodium sulfite/sodium bisulfite solution). Generally, sodium-based sorbents are more reactive than calcium-based ones, resulting in a higher SOx removal efficiency. But they are more expensive. A co-benefit of FSI and DSI is the capture of some of the HCl, HF, and mercury in the flue gas, although this does depend on the sorbent used. The by-products are dry, and thus are relatively easy to handle and manage; no wastewater is produced. Sorbent injection systems are best suited to small- or medium-sized power plants (depending on the sorbent) burning low- to medium-sulfur coals, and where only a moderate SO2 removal efficiency is required.

The main drawback of the sorbent injection processes is their lower SO2 removal efficiency compared to wet and semi-dry scrubbers. Injecting sodium-based reagents, such as sodium carbonate-based ones, into the duct can remove only 70–90% of SO2, but 90–98% of the SO3. SO2 removal efficiency with calcium hydroxide is lower. Power consumption is low, 0.2% of the plant’s output. Capital costs are less than for semi-dry and wet scrubbers, but operating costs can be high, mainly due to the cost of the sorbents.

Multi-Pollutant Systems

Multi-pollutant processes remove several regulated pollutants in one system and may be more cost-effective than installing a series of traditional systems that remove the same number of pollutants. Two of the commercial systems that effectively consume negligible amounts of water are the ReACT™ and SNOX™ processes. Additional processes, such as the CEFCO process, which has only been demonstrated at pilot scale, and Cansolv®, are discussed in the full report by Carpenter.2

ReACT™ Process

The ReACT™ (Regenerative Activated Coke Technology) process has been, or is being, installed on coal-fired units in Japan, Germany, and the U.S. It employs a dry activated coke sorbent which is regenerated. Over 99% of SO2 and SO3, 20–80% NOx, >90% of mercury (both elemental and oxidized), and 50% of the remaining particulates are removed in the process when burning low- to medium-sulfur coals.8 The ReACT™ system is installed after the particulate control device.

The process consists of three stages: adsorption, regeneration, and by-product recovery (see Figure 5). The flue gas enters through the side of the adsorber where it passes through the bed of coal-derived activated coke that is moving slowly downward. SO2, SO3, NOx, and mercury are removed by the sorbent through adsorption, chemisorption, and catalytic reactions. Ammonia is injected into the duct upstream of the adsorber and into the regenerator to promote the removal of SO2 and NOx. The clean flue gas exits the adsorber and is released through the stack. The activated coke takes 80–120 hr to pass through the adsorber and the residence time for the flue gas is 10 s. The spent sorbent is then passed into the top of the regenerator where SO2, nitrogen, water, and mercury are released. The SO2-rich gas flows upward where the mercury is readsorbed by the activated coke. The mercury is removed with the activated coke during planned outages every few years. After cooling, the regenerated activated coke is screened to remove fines and captured fly ash, and returned to the adsorber. The SO2-rich gas exits the regenerator and passes to the by-product recovery unit. Here, the SO2 is converted into a saleable product, such as sulfuric acid or gypsum.

Figure 5. ReACT™ process.8 Note: The numbers 1, 2, and 3 represent the streams that reenter the process.

Figure 5. ReACT™ process.8 Note: The numbers 1, 2, and 3 represent the streams that reenter the process.

No water is added to the system as no flue gas humidification or saturation is required. As a result, only 1% of the water required by limestone wet scrubbers is consumed. Power consumption is lower than wet scrubbers at 0.7% of the plant’s gross output. No liquid wastes are produced. Mercury can be recovered from the activated coke and the spent activated coke can be sold and utilized in other applications. However, ReACT™ may not be economical for high-sulfur coals.

SNOX™ Process

The SNOX™ process, developed in Denmark, is a dry regenerative catalytic process that removes up to 99% of SO2, SO3 and NOx, and essentially all of the remaining particulates.9 The flue gas exiting the particulate control device is reheated in a heat exchanger to 400°C and ammonia is injected before it enters the SCR reactor (see Figure 6). Here NOx is catalytically reduced by ammonia to nitrogen and water. The flue gas is then heated and SO2 is catalytically oxidized to SO3 in a second reactor. Later designs have integrated the two catalytic reactors into a single vessel. The flue gas exiting the oxidation reactor passes through the hot side of the heat exchanger where it is cooled as the incoming flue gas is heated. SO3 reacts with water in the flue gas to form sulfuric acid vapor, which is then condensed into 94–95% concentrated sulfuric acid in the WSA (Wet Sulfuric Acid) condenser.

Figure 6. SNOX™ process10

Figure 6. SNOX™ process10

The process was designed for high-sulfur fuels and thus is more cost effective for high-sulfur coals. No water is consumed in the process and saleable sulfuric acid is produced. The process also recovers heat from the flue gas. It has been estimated that, for a 500-MW coal-fired power plant, the heat recovery would be more than the supplemental power needed for the SNOX™ plant, and could provide a potential net gain equivalent to 8 MW.11


There are a number of commercial low-water FGD systems available that are suitable for coal-fired power plants in areas where water is scarce. These are either essentially dry, such as the sorbent injection, SNOX™, and ReACT™ processes, or have a relatively low water usage. Moreover, technologies that produce a low-temperature flue gas with low SOx and water vapor contents, such as ReACT™, could lower CO2 scrubbing costs, if future regulations require CO2 to be captured.


  1. Zhai, H., Berkenpas, M.B., & Rubin, E.S. (2009). IECM technical documentation: Vol. III. Plant water usage. DE-AC26-04NT41917. Pittsburgh, PA: Office of Systems, Analyses and Planning, National Energy Technology Laboratory.
  2. Carpenter, A.M. (2012, November). Low water FGD technologies. CCC/210. London: IEA Clean Coal Centre.
  3. Jones, J.K., & Weilert, C.V. (2011). Comparison of two semi-dry FGD technologies: Spray dryer absorber (SDA) vs. circulating dry scrubber (CDS). Paper presented at Power-Gen International Conference, Las Vegas, Nevada, U.S., 13–15 December.
  4. Bönsel, T., Graf, R., & Krzton, B. (2012). Operating experience of circulating fluidized bed scrubbing technology in utility size power plants and refineries. Paper presented at International Conference on Power Plants, Zlatibor, Serbia, 30 October–2 November.
  5. Gao, X., Zhong, Y., Wu, Z., Zhang, G., Evans, A., Jiang, M., et al. (2010). Operating experience of CFB semi-dry FGD with novel humidification technology in China. Presented at Coal-Gen 2010 Conference, Pittsburgh, Pennsylvania, U.S., 10–12 August.
  6. Electric Power Research Institute. (2007). CoalFleet guideline for advanced pulverized coal power plants. Version 1. Report 1012237. Palo Alto, CA.
  7. Buecker, B., & Hovey, L. (2011). Circulating dry scrubbers: A new wave in FGD? Power Engineering, 115, 176.
  8. Peters, H.J. (2011). Operating flexibility in the ReACT™ multipollutant control system. Paper presented at PowerGen International Conference, Las Vegas, Nevada, U.S., 13–15 December.
  9. Schoubye, P., & Ibæk, P. (2012). SNOX™ technology for cleaning of flue gas from combustion of high sulfur fuels. 9th European Conference on Coal Research and Its Applications, Nottingham, U.K., 10–12 September.
  10. Lindenhoff, P. (2011). Efficient and reliable solutions for flue gas cleaning. Paper presented at EXPPERTS 2011 Conference, London, U.K., 27–28 September.
  11. National Energy Technology Laboratory. (2000). SNOX™ Flue Gas Cleaning Demonstration Project: A DOE assessment. DOE/NETL-2000/1125. Morgantown, WV.

The author can be reached at Anne.Carpenter@iea-coal.org.


The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.

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