REVIEW OF HANDLING AND USE OF FGD 

MATERIAL 

CARRC Topical Report 

Prepared for: 

Mr. Robert Patton 

U.S. Department of Energy 

National Energy Technology Laboratory 

626 Cochrans Mill Road 

PO Box 10940, MS 922-273C 

Pittsburgh, PA 15236-0940 

U.S. Department of Energy Cooperative Agreement No. DE-FC26-98FT40321 

Prepared by: 

Tera D. Berland 

Debra F. Pflughoeft-Hassett 

Bruce A. Dockter 

Kurt E. Eylands 

David J. Hassett 

Loreal V. Heebink 

Energy & Environmental Research Center 

University of North Dakota 

PO Box 9018 

Grand Forks, ND 58202-9018 

 April 2003
REVIEW OF HANDLING AND USE OF FGD 

MATERIAL 

CARRC Final Report 

Prepared for: 

Mr. James Roewer 

Utility Solid Waste Activities Group 

701 Pennsylvania Avenue Northwest 

Fifth Floor 

Washington, DC 20004-2696 

CARRC Members 

U.S. Department of Energy Cooperative Agreement No. DE-FC26-98FT40321 

Prepared by: 

Tera D. Berland 

Debra F. Pflughoeft-Hassett 

Bruce A. Dockter 

Kurt E. Eylands 

David J. Hassett 

Loreal V. Heebink 

Energy & Environmental Research Center 

University of North Dakota 

PO Box 9018 

Grand Forks, ND 58202-9018 

2003-EERC-04-04 April 2003
DOE DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United 

States Government. Neither the United States Government, nor any agency thereof, nor any of 

their employees makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed or represents that its use would not infringe privately owned rights. 

Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The views 

and opinions of authors expressed herein do not necessarily state or reflect those of the United 

States Government or any agency thereof. 

ACKNOWLEDGMENT

This report was prepared with the support of the U.S. Department of Energy (DOE) 

National Energy Technology Laboratory Cooperative Agreement No. DE-FC26-98FT40321. 

However, any opinions, findings, conclusions, or recommendations expressed herein are those of 

the authors(s) and do not necessarily reflect the views of DOE. 

 The Authors gratefully acknowledge the input of CARRC members, with special thanks to 

Ms. E. Cheri Miller, Tennessee Valley Authority, who provided insightful review and comment. 

EERC DISCLAIMER

LEGAL NOTICE This research report was prepared by the Energy & Environmental 

Research Center (EERC), an agency of the University of North Dakota, as an account of work 

sponsored by DOE. Because of the research nature of the work performed, neither the EERC nor 

any of its employees makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement 

or recommendation by the EERC. 
i 

TABLE OF CONTENTS 

LIST OF FIGURES .......................................................................................................................iii 

LIST OF TABLES.........................................................................................................................iii 

INTRODUCTION .......................................................................................................................... 1 

BACKGROUND ............................................................................................................................ 1 

DISTRIBUTION OF FGD SYSTEMS .......................................................................................... 3 

COMPARISION OF FGD SYSTEMS........................................................................................... 3 

Wet FGD Systems....................................................................................................................... 4 

Limestone-Forced Oxidation .................................................................................................. 4 

Limestone-Forced Oxidation/Organic Acid ........................................................................... 5 

Lime Dual Alkali Process ....................................................................................................... 5 

Magnesium-Promoted Lime ....................................................................................................... 5

Seawater Processes ................................................................................................................. 5 

Sodium Scrubbing Process ..................................................................................................... 5 

Ammonia Scrubbing ............................................................................................................... 6 

Dry FGD Systems....................................................................................................................... 6 

Lime Spray Drying ................................................................................................................. 7 

Duct Sorbent Injection (DSI).................................................................................................. 7

Furnace Sorbent Injection (FSI).............................................................................................. 7 

Circulating Fluidized Bed....................................................................................................... 7 

FGD MATERIAL CHARACTERISTICS ..................................................................................... 7 

Chemical and Mineralogical Composition ................................................................................. 8 

FGD Material from Wet FGD Systems .................................................................................. 8 

FGD Material from Dry FGD Systems..................................................................................... 11 

Physical and Engineering Properties of FGD Material............................................................. 12 

FGD Material from Wet FGD Systems ................................................................................ 12 

FGD Material from Dry FGD Systems................................................................................. 12 

FGD AS A MULTIPOLLUTANT CONTROL TECHNOLOGY ............................................... 13 

Background on Mercury Emission ........................................................................................... 13 

Background on Regulations...................................................................................................... 14 

Control Technologies............................................................................................................ 16 

Human Risk .......................................................................................................................... 16 

HANDLING OF FGD MATERIAL............................................................................................. 17 

Continued . . . 
ii 

TABLE OF CONTENTS (continued) 

FGD MATERIAL UTILIZATION............................................................................................... 18 

ECONOMIC ISSUES ASSOCIATED WITH FGD UTILIZATION .......................................... 21 

DISPOSAL PRACTICES AND REQUIREMENTS ................................................................... 23 

FUTURE FGD SYSTEM INSTALLATIONS AND FGD MATERIAL MANAGEMENT....... 23 

SUMMARY.................................................................................................................................. 25 

REFERENCES ............................................................................................................................. 25 

FGD BY-PRODUCT GENERATED BY STATE, 1994..............................................Appendix A 

FGD SYSTEMS AND MATERIALS – DEFINITIONS ..............................................Appendix B 

FGD SYSTEMS AND MATERIALS – DEFINITIONS ..............................................Appendix C 
iii 

LIST OF FIGURES 

1 Comparison of wet–dry and regenerable FGD systems.........................................................4 

2 Diffraction of spray dryer material.......................................................................................13 

3 FGD material utilization applications ..................................................................................19 

LIST OF TABLES 

1 Typical Chemical Composition of FGD Residues.................................................................9 

2 Chemical Analysis of FGD Gypsum......................................................................................9 

3 Chemical Analysis of Spray Dry Scrubber Material............................................................11 

4 Gypsum Production in the United States .............................................................................18 

5 Potential Uses of Dry FGD Material....................................................................................21 
1 

REVIEW OF HANDLING AND USE OF FGD MATERIAL 

INTRODUCTION 

 Flue gas desulfurization (FGD) material is one of the “four large-volume wastes from the 

combustion of coal by electric utility power plants” as defined by the U.S. Environmental 

Protection Agency (EPA) (Federal Register; Code of Federal Regulations, Part 261, Title 4). 

FGD material is produced from the capture or scrubbing of sulfur dioxide (SO2) emissions using 

a sorbent. FGD technologies were developed and refined to aid coal-fired power plants in 

achieving emission reductions of SO2 mandated in the 1990 Clean Air Act Amendments 

(CAAA). 

 In 1987, the American Coal Ash Association (ACAA) reported that 14.2 million tons of 

FGD material was produced in the United States. In 2000, that number nearly doubled to 

26 million tons. In 1987, only about 1% of the FGD material produced was utilized, but in 2000, 

nearly 20% of the annual production was utilized. Despite the large increase in utilization, FGD 

material still remains a vastly underutilized, valuable material. Emission control regulations 

generally have a direct impact on coal combustion byproduct (CCB) production, and while EPA 

“encourage[d] the utilization of coal combustion byproducts and support[ed] State efforts to 

promote utilization in an environmentally beneficial manner,” federal actions are expected to 

impact the volumes of FGD material produced annually in the United States and potentially 

some management options for CCBs including FGD material. In fact, the annual production of 

FGD material is predicted to increase significantly in coming years as the number of FGD 

systems is expected to double in the next 7 years in response to new emission regulations 

(Government Panel, 2001). This production increase in FGD material, coupled with future 

federal guidance on the disposal and mine placement of CCBs, including FGD material, may 

have a significant impact on utility CCB managers and others involved in CCB management. 

 The purpose of this report is to provide information on the state of the FGD production; 

advantages and disadvantages of various FGD systems and materials; chemical and physical 

characteristics of FGD materials; current practices for handling, disposing, and utilizing these 

materials; and other information for those interested in CCB management. 

BACKGROUND 

Emissions from electric generating facilities, such as SO2, NOx, and mercury, can cause 

detrimental impacts to human health and the environment. Although concentrations are low, 

electric generation facilities account for the majority of SO2 and mercury emissions in the United 

States. The major health concerns associated with exposure to high ambient concentrations of 

SO2 include breathing difficulty, respiratory illness, and aggravation of existing cardiovascular 

disease. In addition to health impacts, SO2 leads to acid deposition in the environment. This 

deposition causes acidification of lakes and streams and damage to tree foliage and agricultural 

crops. Furthermore, acid deposition accelerates the deterioration of buildings and monuments 

(Srivastava and Jozewicz, 2001). Atmospheric mercury concentrations are usually low and of 
2 

little direct concern; however, atmospheric mercury contributes to the mercury loading in surface 

waters where it can bioaccumulate in fish and animal tissue in the form of, methylmercury (EPA, 

1998). 

The CAAA were designed to reduce SO2 and NOx air emissions. No mercury control 

policies from electric facilities are specified in the CAAA. Mercury emission reductions 

reflecting lower mercury release than available from coal are due to emission control 

technologies for other pollutants, such as SO2 and NOx, that can also incidentally capture 

mercury. Currently, emission control technologies are fairly broadly applied for control of 

particulate, SO2, and NOx from coal-fired power plants. U.S. utilities generally employ one of 

two strategies to control SO2 in the flue gas stream: 1) FGD units or 2) compliance fuels. 

Particulate control is typically accomplished by the use of fabric filters (also called baghouses or 

electrostatic precipitators [ESPs]). NOx is typically controlled through low-NOx burners, 

overfire, selective catalytic reduction (SCR), selective noncatalytic reduction (SNCR), or a 

combination of these technologies. Particulate NOx control technologies will not be discussed in 

this report except in relation to the issue to SO2 control. Other methods including fluidized bed 

combustion (FBC) units can also control SO2. Many western coals and some eastern coals are 

naturally low in sulfur and can be used to meet SO2 compliance requirements. Utilities may also 

physically clean or wash all or part of the fuel prior to combustion. Physical coal cleaning at the 

mine, transshipment point, or power plant is quite widespread in the United States not only 

because it reduces emissions, but also because an increase in steam generator efficiency is often 

possible if the fuel feedstock can be made more homogeneous. Utilities may also blend coals of 

different sulfur contents to achieve a mix that is in compliance with applicable regulations. Most 

utilities, approximately 70%, utilize compliance fuel to achieve the SO2 emission levels currently 

mandated. According to the U.S. Department of Energy (DOE, 1997), FGD scrubbing unit 

utilization is estimated to cost $322 per ton of SO2 removed and is the most expensive 

compliance method, although costs vary widely across regions. Also, according to DOE, 

modifying a high-sulfur bituminous coal-fired plant to burn lower-sulfur subbituminous coal is 

estimated to cost $113 per ton of SO2 removed and is the least expensive method. Although FGD 

scrubbing units are the most expensive compliance method, FGD can be cost-effective. The type 

of compliance method implemented needs to be carefully evaluated for the specific coal-fired 

plant. 

Approximately 22% of utilities in the United States utilize FGD systems to achieve the 

currently mandated SO2 emission levels. This percentage is expected to double in the next 

7 years in response to emission regulations (Government Panel, 2001). FGD systems can be 

classified as either wet or dry systems, and both systems produce a byproduct generically 

referred to as FGD material. FGD material is a high-volume byproduct included by EPA as one 

of the four high-volume CCBs in its 1993 RCRA (Resource Conservation and Recovery Act). 

The four high-volume CCBs (fly ash, bottom ash, boiler slag, and FGD material) are designated 

as solid wastes under RCRA Subtitle D as a result of RCRA. In the second phase (Government 

Panel, 2001) of the evaluation, EPA supported this determination. 

Nearly 26 million tons of FGD material was generated in the United States in 2000, but 

less than 20% of that production was utilized according to the ACAA statistics on “Coal 

Combustion Product Production and Use” (ACAA, 2001). These statistics do not differentiate 
3 

between FGD material generated from wet or dry FGD systems, but a review of existing FGD 

systems indicates that wet FGD systems are the preferred control technology, accounting for 

over 80% of the total FGD capacity worldwide (IEA, 2000).

DISTRIBUTION OF FGD SYSTEMS 

 Coal-fired power plants in the United States and Japan began using FGD equipment in the 

early 1970s. Western Europe followed in the 1980s. In the 1990s, the application of FGD 

became more widespread and today includes countries in central and eastern Europe, Asia, and 

elsewhere. Today, there are approximately 1140 coal-fired power plants in the United States. The 

states generating the bulk of the FGD material in 1996 were Texas, Kentucky, and Indiana, 

accounting for almost 50% of total FGD material produced (Kalyoncu and Matos, 1997). An 

illustration of FGD generation by state is included in Appendix A. 

According to the IEA Coal Research, the most widely used FGD systems in the world are 

wet scrubbers using calcium-based sorbents (IEA, 2000). Initially, these systems produced 

nonusable residues; however, systems producing a salable byproduct are now preferred. Wet 

FGD systems are currently installed on about 25% of the coal-fired utility generating capacity in 

the United States, representing about 15% of the number of coal-fired units (McDonald, 2000). 

Spray dry scrubbers and sorbent injection installations are growing in use in the United States 

and Europe, especially on small units. Despite their potentially high-value byproducts, these 

processes have achieved only limited use. Figure 1 illustrates the number of wet and dry systems 

in the United States and worldwide. 

 Other types of SO2 removal technologies, such as FBC systems, can be effective. FBC is a 

dry process that is primarily installed on smaller-scale industrial systems because FBC units are 

effectively installed as a separate system. The system mixes the coal with a sorbent such as 

limestone or other bed material. The coal and bed material mixture is fluidized during the 

combustion process to allow complete combustion and removal of sulfur gases. The ash is 

collected in the flue gas using a baghouse or ESP, and the bed residue is removed from the 

bottom of the boiler. 

COMPARISION OF FGD SYSTEMS 

 FGD technologies use an alkaline slurry to absorb SO2 in the flue gas, producing sodium 

or calcium–sulfur compounds. According to Srivastava (2001), commercially available FGD 

technologies can conventionally be classified as once-through and regenerable, depending on 

how the sorbent is treated after it has sorbed SO2. In one-through technologies, the SO2 is 

permanently bound by the sorbent. In regenerable technologies, the SO2 is released from the 

sorbent during the regeneration step and may be further processed to create sulfuric acid, 

elemental sulfur, or liquid SO2. Both the once-through and regenerable technologies can be 

further classified as wet or dry, depending on if the reagent is wet or dry when it leaves the 

absorber. New FGD processes, especially those combining SO2 and NOx removal, are 

continually being developed and are discussed further, later in this report.
4 

Figure 1. Comparison of wet–dry and regenerable FGD systems. 

Wet FGD Systems 

 Wet FGD systems are the most widely used FGD technology. The use of a widely 

available and inexpensive sorbent (limestone), production of a usable byproduct (gypsum, 

calcium sulfate dehydrate, CaSO4 2H2O), reliability, availability, and most importantly, the 

efficiency achievements that can be as high as 99% are the incentives behind the popularity of 

this technology especially at large-scale utilities. In 2000, 87% of FGD systems in the world 

were wet systems; this number is expected to increase even more as emission regulations are 

adopted. Although capital costs are higher with this technology, operating costs are lower, 

making this system very cost effective. Also, the production of a valuable gypsum byproduct 

contributes toward reducing operating costs. Wet limestone scrubbers, which produce a mixture 

of calcium sulfate/sulfite and fly ash, have a smaller share of the market compared to the 

gypsum-producing processes. The disposal costs of the byproducts are discouraging the use of 

this technology in countries where disposal sites are unavailable or regulation prohibits it. In the 

United States, several plants have converted their wet lime/limestone waste plants to gypsumproducing facilities, and this trend is expected to continue (Soud, 2000). 

Limestone-Forced Oxidation 

The limestone-forced oxidation process, which minimizes scaling problems in the 

absorber, is the preferred FGD technology worldwide. This technology involves recirculating a 

slurry of limestone and water through absorbers where it absorbs SO2 in the flue gas. Air is 

bubbled through the calcium sulfate–sulfite slurry to form gypsum. The byproduct dewaters 

easily and results in less wet waste volume. This process is a proven technology that has been 

used extensively in the United States and can achieve nearly complete oxidation. There are more 

than 10 active suppliers available for this process. The process performs best with medium- to 
5 

high-sulfur coals and does not respond quickly to load change. Economically, this process uses a 

low-cost reagent and consumes between 1.6%–1.8% of gross power (Miller, 2002). 

Limestone-Forced Oxidation/Organic Acid 

This process is the same as the limestone-forced oxidation process described above except 

that it adds an organic acid to the slurry to increase the limestone dissolution rate which results in 

a higher SO2 removal (Miller, 2002). 

Lime Dual Alkali Process 

 This process uses sodium sulfate solution as an absorbing agent that is recirculated through 

the spray tower to remove SO2. The spent solution is mixed with lime in a separate process loop 

simultaneously forming a calcium sulfite sludge while regenerating the spent sodium sulfite 

solution. Advantages of this process are lower corrosion and erosion and less scaling and 

plugging. Disadvantages include the high cost of lime and soda ash reagents. Currently, there is 

no supplier for this technology in the United States (Miller, 2002). 

Magnesium-Promoted Lime 

Either a magnesium-enhanced lime (typically 5%–8% magnesium oxide) or dolomitic lime 

(typically 20% magnesium oxide) is used in this process. This slurry is more reactive than 

limestone slurry but is also more expensive (Srivastava, 2000). The lime slurry is fed to the spray 

tower to form a calcium sulfite sludge, which also contains a small amount of magnesium sulfite. 

If forced oxidation external to the absorber is used, the quality of the gypsum will be improved. 

Commercial-grade gypsum produced from this process is brighter than that from conventional 

wet systems, resulting in a higher commercial value (Srivastava, 2000). Advantages to this 

system include a lower liquid-to-gas ratio and reduction in scaling and plugging. It is estimated 

that there are from three to five suppliers for this process (Miller, 2002). 

Seawater Processes 

The seawater processes use the natural alkalinity of seawater to neutralize SO2. The 

chemistry of the process is similar to the limestone-forced oxidation chemistry except the 

limestone comes completely dissolved with seawater and the chemistry does not involve any 

dissolution or precipitation of solids. The sulfate is completely dissolved in seawater so as a 

result, there is no waste product to dispose of (Srivastava, 2000). This process has achieved 

limited use. 

Sodium Scrubbing Process 

The primary absorbing material for this wet system is a sodium sulfite solution that is 

recirculated through the spray tower to remove SO2 in the flue gas stream. Sodium carbonate is 

used as the reagent. Like the lime dual alkali process, the advantages of this process are lower 

corrosion and erosion and less scaling and plugging. A disadvantage is the high cost of soda ash 
6 

reagents. This system has been proven at several locations in the United States; however, there 

currently are no suppliers of this technology (Miller, 2002). 

Ammonia Scrubbing 

This process is similar to other wet technologies except it uses highly reactive ammonia as 

a reagent. Ammonium hydroxide reacts with SO2 to form ammonium sulfite, which is oxidized 

to ammonium sulfate. This technology can provide SO2 removal greater than 95%. This process 

is also capable of removing other acid gases such as sulfur trioxide and hydrogen chloride 

(Srivastava, 2000). 

 Marsulex Environmental Technologies (MET) is the major promoter of this technology. 

Alstom and Lurgi also have a version of this technology (Miller, 2002). According to MET 

(Walsh, 1999), this technology works best with power plants that match the following profile: 

 • High fuel cost 

 • Low load factor 

 • Proximity to navigable water or good rail access for pet coke, ammonia, and ammonium 

sulfate transportation 

 • Preferably in location with high ammonium sulfate prices 

MET’s patented technology claims it enables the use of low cost, 5%–7% sulfur fuels without 

the associated sulfur penalty. 

 

 The greatest benefit of this technology is that its high-value byproduct, ammonium sulfate, 

can be sold as fertilizer. It is important to note that the value of this product will depend largely 

on the market and product quality has been an issue of concern in the past. MET suggests that for 

every ton of ammonia utilized, approximately four tons of ammonium sulfate is generated 

(Walsh, 1999). MET’s technology is currently installed on the Dakota Gasification Plant in 

Beulah, North Dakota. Two additional installations are planned for the Santee Cooper Facility in 

South Carolina and the Mildred Lake Oil Sands Facility in Alberta, Canada (Marsulex, 2001) 

Dry FGD Systems 

 Dry FGD systems are the second-most widely used FGD technology. This technology is 

considered efficient and reliable and has lower capital costs than wet scrubbers. However, its 

operating costs are higher because of the use of a more expensive sorbents. In addition, most 

byproducts from this technology cannot be utilized and need to be disposed of because they are 

usually made of a mixture of calcium sulfite, calcium sulfate, and fly ash (Soud, 2000). 
7 

Lime Spray Drying 

The process consists of mixing hot flue gas in a spray dryer vessel with a mist of finely 

atomized fresh lime. The SO2 in the hot flue gas reacts with the sorbent as the water in the slurry 

evaporates. The dried solids are collected in the bottom of the vessel in a particulate control 

device. This technology is most often used for power plants that are 550 MW or larger that burn 

low-to-medium-sulfur coal, between 0.4% and 2%. An average of 90% SO2 removal can be 

achieved (EPA, 2002b). The resulting FGD material is frequently referred to as spray dry ash or 

material and is a calcium sulfite-rich material. 

Duct Sorbent Injection (DSI) 

DSI is intended to enable SO2 control directly in the flue gas duct between the air preheater 

and the particulate control device. Hydrated lime is typically used as a sorbent, and occasionally 

sodium bicarbonate is used (Srivastava, 2000). 

Furnace Sorbent Injection (FSI) 

In the FSI system, a dry sorbent is injected directly into the furnace in the optimum 

temperature region above the flame. Because of the high temperature (approximately 1000°C), 

sorbent particles decompose and become porous solids with high surface areas (Srivastava, 

2000). 

Circulating Fluidized Bed 

 In this system, a dry sorbent, most often Ca(OH)2, is contacted with humidified flue gas in 

a fluidized bed. The combustion fluidized bed provides a long contact time between the sorbent 

and flue gas has because the sorbent passes through the bed several times (Srivastava, 2000). The 

solids are collected in an ESP or baghouse. A larger particulate collector may be needed to 

maintain the required particulate emission levels compared with a non-circulating sorbent. 

 This process is not widely used in the United States, and is primarily used in Germany for 

units ranging from 50 to 250 MW (Srivastava, 2000). 

FGD MATERIAL CHARACTERISTICS 

According to an IEA Coal Research (Clarke, 1993) study, differences between 

mineralogical, chemical, and physical characteristics of FGD material, from both similar and 

different technologies, can be attributed to a combination of the following factors: 

• Composition of the coal feedstock and sorbents 

• Combustion conditions 

• Composition and mineralogy of the fly ash 

• Relative amounts of fly ash, unreacted sorbent, and desulfurization products 

• Reagent ratios 
8 

Chemical and Mineralogical Composition 

FGD Material from Wet FGD Systems 

Wet FGD systems frequently use calcium-based sorbents and produce either wet FGD 

material (unoxidized wet FGD material or sulfite-rich wet FGD material) or FGD gypsum (from 

forced-oxidation systems). These materials have similar bulk chemical compositions but have 

different mineralogical compositions. The chemical composition of wet FGD material depends 

largely on the sorbent used for desulfurization and the proportion of fly ash collected with the 

FGD residues. In most wet FGD systems, FGD residues are collected as a separate byproduct 

stream (Clarke, 1993). Since flue gas contains sulfur primarily as SO2, the initial material formed 

is calcium sulfite (CaSO3). To generate calcium sulfate, the material must be oxidized. This can 

be done in the scrubber system with a process called in situ forced oxidation. In this process, 

excess air is added to the system to oxidize the calcium sulfite to calcium sulfate as shown 

below: 

 CaCO3 + SO2 → CaSO3 +CO2 → CaSO3 + 1⁄2O2 CaSO4 [Eq. 1] 

 If it is desired or advantageous to oxidize the FGD material as a slurry outside of the 

scrubber, this can be easily done by passing either oxygen or air through a slurry acidified to 

around pH 4.5. The pH adjustment is necessary as the oxidation proceeds through the bisulfite 

(Ca[HSO3 ]2). It is necessary to form the bisulfite through acidification because of the extremely 

low solubility of the calcium sulfite. Calcium bisulfite is much more soluble, and because the ex 

situ oxidation occurs in solution, the much higher solubility of the bisulfite increases the reaction 

rate. 

 Both wet FGD material and FGD gypsum are primarily crystalline in their morphology. 

FGD gypsum is composed of finely divided cube- or rod-shaped crystals ranging from 1–250 μm 

(Coal Research Establishment [CRE], 1992). The purity of FGD gypsum typically ranges from 

96%–99% (Coclough and Carr, 1991). Wet sulfite-rich FGD material is composed primarily of 

calcium sulfite hemihydrate (hannebachite). 

 Table 1 lists the typical bulk chemical composition for wet FGD material from systems in 

which fly ash is removed before the scrubber. The chemical compositions of bituminous, 

subbituminous, and lignite fly ash are included for comparison purposes. 

 In some systems, fly ash is used as part of the sorbent. High-calcium fly ash can be used 

but has been reported to be more abrasive than limestone. When fly ash is used as part of the 

sorbent, the bulk chemistry and mineralogy of the FGD material will reflect the chemistry and 

mineralogy of the fly ash based on the percentage of fly ash used. 

 The major and trace element compositions of several samples of FGD gypsum from 

Germany, Japan, the United Kingdom, and the United States are listed in Table 2. Most of the 

major and trace elements leave the FGD system in the gypsum or wet sulfite-rich FGD material. 

Al, As, Ca, Fe, Pb, Sb, Si, and Ti are the elements mainly left in the gypsum. Between 10% and 

40% of Al, As, Cr, Cu, F, Fe, Ni, Sb, Sc, Si, Sm, Ti, U, V, and W leave the plant in the wet 
9 

Table 1. Typical Chemical Composition of FGD Residues 

Wet 

Sulfite-rich

FGD 

Material FGD Gypsum

Fly Ash 

(bituminous)

Fly Ash 

(subbituminous) 

Fly Ash

(lignite)

SiO2 0.1–7.4 0.1–6.3 43–64 30–45 12–49 

Al2O3 0.1–6.0 0.1–5.1 11–32 17–21 6.3–16 

Fe2O3 0.1–6.0 0.1–5.7 3.5–25 3.9–6.5 3.7–14 

CaO 38–52 27–32 0.7–20 17–30 16–34 

MgO 1.3–6.1 1.0–4.9 0.6–1.6 3.4–6.4 3.8–11 

Na2O 0.1–0.9 0–0.6 0.2–4.0 0.2–8.4 0.6–6.1

K2O 0–0.6 0–0.6 0.5–3.0 0.3–1.0 0.4–2.1

SO3

2- 54–63 44–46 0.1–11 1.1–5.0 0.4–30 

Typical Solids Content 5–10 5–10 

Sources: Smith, 1992; CARRC Database. 

Table 2. Chemical Analysis of FGD Gypsum*

 A B C D E F G H I J K L M Nat.

Trace Elements, ppm 

As <1 1 1 1 1 1 1 1 1 2 1 1 1 <1 

B <5 <5 11 10 100 10 11 4 29 <5 21 11 24 9 

Ba 12 9 7 6 6 <1 <1 <1 <100 13 <1 6400 200 4 

Cd <1 <1 <1 <1 <1 <1 <1 <1 <1 2 <1 <1 1 <1 

Cr 4 5 10 3 4 4 4 6 4 5 9 24 3 1 

Cu 64 9 12 3 5 3 <1 <1 5 7 <3 3 3 7 

Hg <3 <3 1 1 <1 <1 <1 <1 <1 <3 <1 <1 <1 <3 

Mn 10 11 28 49 32 15 3 17 8 94 10 35 15 4 

Mo <1 <1 <1 <2 <1 <3 <3 <3 <2 <1 <3 <3 <2 <1 

Ni 19 4 6 4 7 <3 <3 <3 5 17 <3 <3 3 2 

Pb 1 2 7 3 <2 4 1 12 2 3 1 47 28 <1 

Se 3 2 15 10 11 8 9 12 3 <1 4 6 <1 <1 

V 8 16 12 12 12 10 10 10 10 21 12 10 10 27 

Zn 10 8 3 <1 7 5 3 5 8 16 5 20 8 5 

* A–I: Germany, J: Japan, K–L: USA, M: UK, Nat.: natural mineral gypsum sample. 

Source: CRE, 1992. 

sulfite-rich FGD material. The amounts of major, minor, and trace elements included with the 

FGD material are highly dependent on the amount of ash also included. If ash is excluded, the 

contribution of trace elements in the FGD material is limited to those that are air toxic 

constituents and are present in the flue gas either as extremely fine particulates or vapors. Some 

elements, especially the more volatile ones, are removed mainly in the wastewater (Meij, 1989). 

It is recognized that the mercury content of FGD materials is primarily determined by the species 

produced in the combustion system. Oxidized mercury, likely present as mercuric chloride, is 

highly retained in FGD systems, while elemental mercury mostly passes through the FGD 
10 

system. The Energy & Environmental Research Center (EERC) (Hassett and others, 1997) noted 

that some trace elements were present in measurable quantities in FGD gypsum produced in 

pilot-scale ex situ oxidation of wet FGD material. These elements were mercury, chromium, and 

chlorine (present as chloride), and although they were present in measurable amounts, it is 

important to note that the mercury and chromium were present at very low levels, with leachate 

concentrations less than the primary drinking water standard levels. Chloride was present at 110 

ppm. Although it was known from previous analyses that trace elements were present in the wet 

FGD material, it was anticipated that the oxidation process used would facilitate the removal of 

contaminants. In follow-up work, solid materials, reaction waters, and leachate were all analyzed 

in an effort to determine the fate of these trace constituents relative to the FGD gypsum produced 

using the air oxidation process. During the oxidation of the wet FGD material, many of the trace 

elements partitioned to the liquid phase because of recrystallization purification as well as 

lowering of solution pH. Certain trace elements were present in measurable concentrations in the 

produced FGD gypsum, but in leaching experiments, only a small percentage of the total was 

released to the leachate. Mercury behaved differently than other trace elements in that it retained 

its association with the FGD throughout the oxidation process. It is not known what the 

mechanism of mercury association is, but despite the dissolution–oxidation–recrystallization 

process that the material undergoes, mercury is associated with both the pre- and post-oxidation 

material. The concentrations remaining are, for the most part, immobile under water leaching. 

Findings of trace element partitioning and fate in the ex situ oxidation of wet FGD material are 

summarized below. 

• Potentially problematic trace elements, including heavy metals and chloride appear to 

partition into the liquid phase during the oxidation process, likely from recrystallization 

purification of the product as well as pH adjustment to the 4.5 necessary for air 

oxidation. 

• Concentrations of many of the potentially problematic trace elements are not especially 

high. 

• Mercury sorbed or otherwise captured in wet FGD systems may tend to remain 

associated with the solids if ex situ oxidation is used for the production of gypsum. 

• Trace elements remaining in the scrubber sludge at measurable or potentially 

problematic levels have been found to be leached at concentrations at or below primary 

drinking water standards. 

• The degree of dewatering that can be accomplished will account for concentrations of 

trace elements in the produced gypsum that are inversely proportional to the efficiency 

of dewatering. This is because of the partitioning of the trace elements into the liquid 

phase during the oxidation process. 

 Although the use of in situ forced oxidation appears to be a superior alternative for the 

production of gypsum without the bother of the additional solution chemistry required by an air 

oxidation system, the material produced in a forced-oxidation system will likely be of a lower 

overall purity with respect to total calcium sulfate content since unreacted calcium hydroxide 
11 

will be present in its original form and trace elements trapped in the scrubber material will 

remain there in original concentrations. These are favorably partitioned into the liquid phase 

during air oxidation, especially heavy metals. 

FGD Material from Dry FGD Systems 

 Like wet FGD materials, the chemical composition of spray dryer material residues 

depends on the sorbent used for desulfurization and the proportion of fly ash collected with the 

FGD residues. Table 3 lists the major and trace element compositions of some spray dryer 

materials. Spray dryer FGD materials consist of fly ash entrained with reacted and unreacted 

Table 3. Chemical Analysis of Spray Dry Scrubber Material 

 A B C D E

Major Elements,wt% 

SiO2 7.9 10.6 8.7 47.1 32 

Al2O3 4.7 4.5 4.1 24.8 15.3 

Fe2O3 2.2 4.4 1.9 10.1 3.8 

CaO 1.9 1.5 1.0 1.6 24.1 

MgO 37.8 35.6 33.6 4.8 2.9 

Na2O 0.3 0.3 0.2 0.9 1.67 

K2O 0.4 0.6 0.3 2.6 0.52 

CO2 17.0 20.1 10.6 – 

SO3

2- 30.0 17.4 18.8 – 

SO4

2- 10.5 7.0 24.6 1.2 

Cl- 2.2 0.9 3.0 <0.1 

C (org.) 0.2 0.2 0.1 1.0 

Trace Elements, ppm 

As 5 11 10 110 

B 100 115 150 200 

Ba 465 270 4000 1500 

Cd 1 3 7 <3 

Cr 40 50 34 145 

Cu 47 43 46 230 

Hg <1 <1 <1 1 

Mn 270 420 170 780 

Mo 3 5 <3 22 

Ni 32 36 35 170 

Pb 28 110 57 205 

Se 4 5 7 7 

V 60 65 70 280 

Zn 94 380 130 370 

A–C: spray dry scrubber residues, D: bituminous fly ash, E: MN FGD. 

A–D Source: CRE, 1992; E Source: Solem-Tishmack, 1993. 
12 

sorbent. The average particle size ranges from 20–40 μm. The fly ash in dry FGD materials has 

similar particle size, density, and morphology to those of conventional fly ashes, but FGD 

materials have lower bulk densities (Thompson and others, 1988). The difference in bulk density 

is due to variations in the chemical and mineralogical characteristics of the reacted and unreacted 

sorbent. Dry FGD materials contain higher concentrations of calcium and sulfur and lower 

concentrations of silicon, aluminum, and iron than fly ash. The principal reaction product of 

FGD is hannebachite (calcium sulfite hemihydrate) (Solem-Tishmack, 1993): 

 CaO (lime) + SO2 (g) + 1⁄2 H2O → CaSO3 · 0.5H2O [Eq. 2] 

Under more oxidizing conditions, gypsum may also form: 

 CaO (lime) + SO2 (g) + 1⁄2 O2 + 2H2O → CaSO4 · 2H2O [Eq. 3] 

Unused sorbent remains as portlandite (calcium hydroxide) in the residuals (Solem-Tishmack, 

1993). 

Dry FGD materials can vary widely in their properties depending on their source. 

Thompson and others (1988) collected dry FGD materials from different plants that used 

different types of boilers and burned different types of coal. They found the residuals had a 

moderate to wide range of variability in their chemical, physical, and mineralogical properties. 

The amount of unused sorbent (portlandite) varied the most by a factor of 14. This variation 

depended on whether or not the plant recycled its residuals. 

Physical and Engineering Properties of FGD Material 

FGD Material from Wet FGD Systems 

The physical properties of wet FGD materials vary significantly depending on the relative 

proportions of sulfate and sulfite from each system (Clarke, 1993). The average bulk density of 

gypsum depends on the particle shape with approximately 1200 kg/m3

 for blocky crystals and 

roughly 600 kg/m3

 for needlelike crystals. Wet sulfite-rich FGD material historically was termed 

“scrubbing or FGD sludge” because of its thixotropic properties. The term “sludge” is less 

commonly used by the coal ash industry. Thixotropic properties enable it to stiffen in a relatively 

short time on standing but, upon agitation or manipulation, to change to a very soft consistency 

or to a fluid of high viscosity; the hardening process is completely reversible. Wet sulfite-rich 

FGD material is difficult to dewater; however, its physical properties can be modified by 

“fixation” or “stabilization” with fly ash, portland cement, or other additives. 

FGD Material from Dry FGD Systems 

The overall physical and handling properties of the residues from most spray dryer 

materials are similar to fly ash. The bulk density of spray dry system residues, with only a small 

proportion of ash, is about 600 kg/m3

 compared to 1000 kg/m3 for fly ash (Jons, 1987; CRE, 
13 

1992). Particle-size distributions of these materials indicate that most materials can be classified 

as silt-size range. The bulk density of residues from spray dryer FGD systems varies from 780 to 

1250 kg/m3

 (Perri and others, 1988). An example of an x-ray diffraction of spray dryer material 

can be found in Figure 2 (Weber and others, 1993). The hannebachite is the sulfite. 

FGD AS A MULTIPOLLUTANT CONTROL TECHNOLOGY 

Background on Mercury Emission 

 The operation of coal-fired power plants results in the generation of CCBs that already 

contain mercury; however, that mercury is presumably bound mercury that is relatively insoluble 

and nonleachable (EPA, 2002). The type of mercury that is of greatest concern is mercury 

emitted into the air. Although mercury is emitted from coal-fired power plants in very low 

concentrations, as a group, coal-fired boilers represent the largest unregulated source of mercury 

emissions to the environment, accounting for about one-third of the total anthropogenic 

emissions (EPA, 1997). Further assessment based on EPA’s 1999 Information Collection 

Request (ICR) indicates that approximately 40% of the 75 tons of mercury contained in the coal 

burned in the United States is captured in ash and scrubber residues and 60% is emitted to the 

atmosphere (Kilgroe, 2000; Chu and others, 2000). In 1999, EPA estimated that the electric 

utility industry emitted 43 tons of mercury from 1149 units at 464 coal-fired power plants 

through both air and solid emissions. Projections for 2010 without regulations include 

approximately 60 tons of emission from 1026 units at 426 coal-fired plants (Duclos, 2001). 

Figure 2. Diffraction of spray dryer material. 
14 

 Increased control of mercury emissions from coal-fired power plants may change the 

amount and composition of CCBs. Such changes may increase the potential for release of 

mercury to the environment from either landfilling or utilization. Mercury volatilization from 

CCBs in landfills and/or surface impoundments is expected to be low because of the low 

temperatures and relatively small surface area involved. For mercury control technologies using 

dry or wet FGD scrubbers, the byproducts are typically alkaline and the acid leaching potential 

of mercury from these byproducts is expected to be minimal (EPA, 2002a). EPA (2002b) 

predicts that future policy for mercury control will designate activated carbon injection 

downstream of the combustion process. 

Background on Regulations 

 As previously mentioned, there are no specific regulations for mercury for electric utilities. 

The CAAA of 1990 did require EPA to regulate hazardous air pollutants (HAPs) using a 

maximum achievable control technology approach, commonly referred to as a MACT approach. 

MACT standards were put in place for any sources that emitted 10 tons or more of a particular 

pollutant. Utilities, on the other hand, were a source category to be treated separately. EPA was 

required under the CAAA to perform further studies on HAPS for electric utilities. The two 

reports that came out of this directive were the Mercury Report to Congress and the Utility 

Report to Congress. Based on the conclusions of these reports, EPA determined it necessary to 

regulate mercury emitted from electric utilities. Thus, there were no immediate or direct 

regulations for mercury and utilities, but the process indirectly led to mercury regulations for this 

particular source category. The form of regulation is still being debated (Pavlish, 2002). 

However, EPA has developed a five-pronged approach to controlling mercury emissions from 

power plants (EPA, 1998): 

• Increasing public access to information concerning mercury emissions from power 

plants 

• Seeking to reduce risk to highly exposed populations through public information 

• Making maximum use of the reductions in mercury emissions that can be achieved 

from controlling other pollutants 

• Encouraging the development of mercury emissions monitoring and control 

technologies 

• Further research to increase understanding of the nature and fate of mercury emissions 

from power plants so as to form a basis for future controls 

 Most recently, on February 14, 2002, President Bush announced his administration’s 

initiative to address concerns about power plant emissions. The Clear Skies Initiative (CSI) cuts 

(by 70%) power plant emissions of the three major air pollutants: nitrogen oxides, sulfur dioxide, 

and mercury. NOx emissions will be cut by 67%, from current emissions of 5 million tons to a 

cap of 2.1 million tons in 2008 and 1.7 million tons in 2018. SO2 emissions will be cut by 73%, 

from current emission of 11 million tons to a cap of 4.5 million tons in 2010 and 3 million tons 
15 

in 2018. The Bush administration anticipates that the national cap on mercury emissions will cut 

emissions by 69% from current emissions of 48 tons to a cap of 26 tons in 2010 and 15 tons in 

2018. To accomplish these cuts, the CSI uses a market-based approach which will “... cut 

pollution further, faster, cheaper, and with more certainty, using a ‘cap-and trade’ program, 

replacing a cycle of endless litigation with rapid and certain improvements in air quality... Saves 

as much as $1 billion annually in compliance costs that are passed along to American consumers, 

improves air quality, and protect the reliability and affordability of electricity. Use the model of 

our most successful clean air law—the 1990 Clean Air Act’s acid rain program—and encourage 

the use of new and cleaner pollution control technologies” (Palmisano and Burnett, 2002). It 

should be noted that this plan has been fiercely scrutinized because it does not, in many people’s 

view, reduce emissions enough, starts too late and, therefore, has a lower monetized benefit. 

 Further regulations are scheduled to be proposed in late 2003 and should be final by late 

2004, with a compliance date of late 2007. These regulations will affect all new and existing 

units. EPA has not yet determined the level of control that will be required. However, there are at 

least five bills pending in the 107th Congress that would require regulation of mercury emissions 

from coal- and oil-fired utility boilers. Based on EPA’s extensive ICR test program, it is 

expected that dry FGD systems on boilers firing bituminous coal and wet FGD systems preceded 

by fabric filters on boilers firing bituminous coal are likely to be able to meet the predicted 90% 

control requirement by the end of the decade (Weilert and others, 2002). 

 In addition to federal regulations, states have begun developing their own emission control 

regulations and, in some cases, identified specific control efficiency requirements. These states 

are as follows: 

 • Connecticut 

 • Maine 

 • Massachusetts 

 • Minnesota 

 • New Hampshire 

 • New Jersey 

 • Wisconsin

 The Connecticut Department of Environmental Protection (2002) anticipates a reduction of 

8900 tons of SO2 emissions after 2003 in addition to a reduction of baseline NOx emission by 

30%, or 3483 tons, per year. Massachusetts has adopted regulations that reject the use of 

“averaging,” meaning companies owning more than one plant cannot have a high-polluting 

facility just because they operate a clean plant in another part of the state. Massachusetts 

regulations apply to NOx, SO2, and CO2 emissions, and a mercury standard is expected to be 

proposed in 2006 (Commonwealth of Massachutts, 2001). According to Weilert and others 

(2002), New Hampshire has proposed a 50% reduction in emissions from electric utility boilers 

by 2003 and 75% by 2005. Wisconsin has proposed a phase-in of mercury reductions over the 

next 15 years, beginning with 30% reduction by 2006 and extending to 50% reduction by 2011 

and 90% by 2016 for utility boilers only (Weilert and others, 2002). 
16 

Control Technologies 

 Currently, U.S. utilities make use of various technologies to reduce mercury emissions; 

however, these technologies are not specifically designed to reduce mercury emissions (EPA, 

2002). Technologies that are used to reduce particulate matter, SO2, and NOx also reduce 

mercury emissions with varying levels of effectiveness (EPA, 2002). Some of these 

technologies involve the installation of specialized equipment, while others rely on modification 

of operating procedures or the use of specific fuels. Because of the large number of U.S. fossilfueled facilities and the various regulatory requirements, there is a tremendous variety of 

emission control equipment provided and installed by many different suppliers and vendors 

(EEI, 1993). 

 Because the chemical species of mercury emitted from coal-fired power plants vary from 

plant to plant, no single control technology removes all forms of mercury. There remains a wide 

variation in the end costs of control measures for utilities and the possible impact of such costs 

on utilities. Preliminary estimates of national control costs for utility boilers (based on pilot-scale 

data) are in the billions of dollars per year (EPA, 1997). 

 As new mercury control regulations are adopted, more innovative technologies are being 

studied to address mercury extraction and removal from coal-fired flue gas. With more than 200 

of the largest coal-fired power plants in the United States utilizing FGD systems, these systems 

still remain the most popular method of mercury removal. Although these systems were designed 

primarily to remove SO2, wet scrubbers also entrain oxidized mercury in the scrubber water that 

can reach 600 ppb (Duclos, 2001). FGD systems have not been shown to remove reduced 

mercury, and since the mercury species emitted varies by coal, FGD systems will not provide 

mercury reductions for some coals. 

 To optimize mercury removal using FGD, investigations have been initiated to oxidize 

mercury from the elemental form (Hg0) to the oxidation form (Hg+2) so it can be removed in 

existing FGD systems. One example of this research was reported by Babcock & Wilcox and 

McDermott Technology, Inc., at the March 19, 2002, National Energy Technology Laboratory 

(NETL) Mercury Workshop and is noted on the DOE NETL Web site (DOE NETL, 2002). 

 New fine particulate control technologies, such as the EERC’s ADVANCED HYBRIDTM

technology (Miller and others, 2002), may also offer enhanced mercury control. The EERC is 

currently evaluating the ADVANCED HYBRIDTM technology for mercury capture under funding 

from DOE NETL. 

Human Risk 

Much is still unknown about the relationship of power plant emissions and mercury 

concentrations in humans. Concentrations of mercury in air are usually low and of little direct 

concern; however, atmospheric mercury contributes to the mercury loading in surface waters 

where it can bioaccumulate in fish and animal tissue in the form of, methylmercury (EPA, 1998). 
17 

 The most direct threat of mercury exposure to humans occurs by eating contaminated fish. 

Exposure to high levels of mercury has been associated with serious neurological and 

developmental effects in humans. The effects can include subtle losses of sensory or cognitive 

ability, tremors, inability to walk, convulsions, and death. Because a developing fetus may be the 

most sensitive to the effects from methylmercury, women of child-bearing age are regarded as 

the population of greatest interest (EPA, 1998). 

HANDLING OF FGD MATERIAL 

 Because many utilities in the United States dispose of wet sulfite-rich FGD material in 

ponds or lagoons, pipeline transportation is most effective (Moore, 1992). A moisture content of 

<10% is desired for transport because moisture contents of 12%–15% can make the material 

sticky and clog up systems, and a moisture content of <5% can create dust (Clarke, 1993).Wet 

sulfite-rich FGD material is sometimes stabilized or fixated by addition of fly ash, cement, or 

other additives. The stabilized material is easier to handle and transport because the stabilization 

result reduces or eliminates the thixotropic properties of the materials. Stabilized wet sulfite-rich 

FGD material has been used for liners and feedlot surfaces (Butalia and others, 1999). 

 Wet sulfite-rich FGD material may be dewatered through filtering. This filtered material 

may be referred to as filter cake. After disposal in wet conditions, such as lagoons or ponds, FGD 

material may be dewatered by “dry-stacking” which allows excess water to naturally migrate 

from the FGD material. 

 Handling FGD gypsum can be difficult because the material is abrasive, sticky, 

compressible, and considerably finer (<0.2 mm) than natural gypsum (CRE, 1992). Because of 

the difference in mixed natural gypsum and FGD gypsum, only limited quantities of FGD 

gypsum could be used to replace or supplement natural gypsum in older gypsum wallboard 

factories. New gypsum wallboard plants have been designed to accommodate the finer FGD 

gypsum. 

 The bulk physical properties of dry FGD materials are similar to fly ash; therefore, they 

must be handled similarly. While the bulk appearance and properties may be similar to fly ash, 

dry FGD material is primarily crystalline in its morphology, and fly ash is primarily glassy or 

amorphous. As a result, flow characteristics of dry FGD material may vary significantly from fly 

ash. Some powders may require conditioning to transport. The typical moisture content of the 

conditioned residues is about 10%. The majority of dry FGD materials can be transported by rail, 

road, water, or pipeline (Clarke, 1993); however, it is suggested that residues discharged directly 

from the spray dryer FGD unit are best transferred using mechanical conveyors (Klimek and 

others, 1987). 

 Materials discharged directly from the spray dryer FGD system are best transferred using 

mechanical conveyors and may be transferred using a pneumatic system. These materials may 

require conditioning prior to transport to minimize dusting. The typical moisture content of these 

materials is 10%. Conditioning with water aids compaction of residues and may display 

thixotropic properties (CRE, 1992). 
18 

FGD MATERIAL UTILIZATION 

 Record levels of construction activity in North America and the recovery of most Asian 

economies triggered significant expansion in the gypsum industry during 1999 (The Roskill 

Consulting Group, 2000); however, the U.S. gypsum industry experienced a decline in both 

production and consumption in 2000 (Olson, 2000). Bruce (2002a) suggests the U.S. decline 

could be attributed in part to the globalization of the industry. It is important to note that 

although the overall gypsum industry experienced a downturn in 2000, the production and 

consumption of synthetic gypsum increased largely because of the construction of wallboard 

plants specifically designed to use the material as a feedstock. 

 The primary source of synthetic gypsum is from forced oxidized FGD systems. Synthetic 

gypsum is becoming a very viable material and has gained widespread acceptance as a raw 

material in the production of gypsum wallboard and cement. These two markets account for in 

excess of 80% of all natural gypsum and virtually all synthetic gypsum consumption in North 

America. 

 During the next several years, the use of mined gypsum may decline significantly in the 

United States as greater quantities of synthetic gypsum are produced. The U.S. FGD market is 

expected to grow by 5000 MW annually over the next 7–8 years as a consequence of the newly 

introduced legislation (Global Gypsum, 2002). This large increase in production has made it 

possible for other companies to move into the market and for existing companies to expand into 

regions that were previously untapped. It is important to note that although more power plants 

are producing FGD gypsum, there are also increasingly frequent reports of shortages. Today, 

synthetic gypsum represents about 18% of the gypsum used in the United States (Bruce, 2002a), 

and some forecasts predict this percentage will increase to 30% by 2005 (Global Gypsum, 2001). 

 FGD gypsum is primarily produced in North America, Europe, and Japan; however, output 

is spreading to less developed countries where it will become an increasingly important source of 

material in the future (The Roskill Consulting Group, 2000). Based on the ACAA Coal 

Combustion Product Production and Use Statement, 25,652,994 tons of FGD material was 

produced in the United States in 2000, and 4,824,727 tons (nearly 19%) was utilized. As 

illustrated in Table 4, synthetic gypsum accounted for more than 15% of the total domestic 

gypsum supply in 2001. Synthetic gypsum includes FGD gypsum from coal-fired power plants 

and by-product gypsum from other sources. 

Table 4. Gypsum in the United States, million tons 

1997 1998 1999 2000 2001 

Crude 18.6 19.0 22.4 19.5 18.8 

Synthetica 2.7 3.0 5.2 5.2 6.1 

Calcinedb 17.2 19.4 23.3 2.1 17.7 a

 Data refer to amount sold or used, not produced. 

b

 From domestic crude. 

Source: U.S. Geological Survey (USGS) (2002).
19 

 FGD materials have been successfully utilized in a wide variety of applications. According 

to the USGS (2002), 95% of the gypsum consumed in the United States is used for wallboard 

products, building plasters, and the manufacture of portland cement. The USGS overall 

utilization rate (2002) is comparable to ACAA (2001) statistics illustrated in Figure 3. It is 

important to note that ACAA’s data do not indicate if the FGD materials used are wet FGD 

material, FGD gypsum, or dry FGD materials; however, it is reasonable to assume that wet FGD 

material is generally stabilized prior to use. The thixotropy of wet FGD material limits its 

usefulness. 

 FGD materials have the potential to be beneficially reused in numerous applications if the 

economics are in place. It is reasonable to assume that FGD gypsum is the primary FGD material 

represented by the use figures. Only gypsum can be used in wallboard and cement. FGD gypsum 

and sulfite-rich FGD materials would likely be used preferentially in agricultural applications. 

 Although FGD materials have the potential to be used in a variety of applications, many of 

those applications never reach the commercial phase for a number of reasons, including 

economics and government regulations. The following nonexhaustive list of current commercial 

utilization practices for FGD materials was derived from a variety of sources, including 

symposium proceedings, Internet searches, and conversations with experts in the industry: 

• Wallboard (regular, Type X, sheathing, soffit board, water-resistant gypsum, backing 

board, lath, veneer base, coreboard, gypsum liner board, predecorated, foil 

backed,board for manufactured housing, wood chip boards) 

Figure 3. FGD material utilization applications. 
20 

• Structural fills 

• Mining applications

– Neutralization or encapsulation of acid-producing materials 

– Barrier to acid mine drainage formation/transport 

– Alkaline amendment to neutralize acid-producing rock 

– Subsidence control in underground mines 

– Filling underground mine voids to control acid drainage 

– Pit filling to reach approximate original contour in surface mines 

– Soil amendment 

– Synthetic soil component 

• Portland cement (Primarily used as a grinding aid and set retarder) 

• Plaster 

• Agriculture 

– Acid soil neutralization clay breakdown and as a calcium and sulfur source 

– Sodic soil reclamation 

– Carbon sinks in forestry 

– Feedlot surface stabilization 

– Crop storage pads 

• Floor underlayment 

• Glass making 

• Pigments and/or fillers in paper, plastic, food, pharmaceutical, fertilizer, pesticide, and 

herbicide 

 Products developed and based mainly on a-hemihydrate including the following: 

• Self-leveling floor screeds of varying strengths (very common in Europe, particularly 

Germany, for heat and sound insulation) 

• Double floor systems as cavity floor and raised access floor (“computer floor”) 

• Mining mortars (consolidation, embankment, rock stabilizers) 

• Tunnel mortars 

• Construction products (adhesives, thin-layer systems, toppings) 

• Molding plasters 
21 

 Magnesium hydroxide markets include the following: 

• Acid neutralization 

• Fuel additives 

• Feedstock for refactories, magnesium metal, and the chemical industry 

 Pyrite coal spoil and gypsum sludge can result in valuable products, namely, sponge iron 

and lime. 

 Table 5 lists the potential uses of FGD gypsum and dry FGD material. It is important to 

note that some applications listed are not commercially available at this time.

Table 5. Potential Uses of Dry FGD Material 

High Potential Moderate Potential Low Potential 

Structural Fill Cement production Gypsum/wallboard 

Grout/Mine Backfill Cement replacement Metals extraction 

Stabilized Road Base Soil stabilization 

Synthetic Aggregate Sludge stabilization 

Lightweight Aggregate Mineral filler 

Mineral Wool Agricultural use 

Brick Production Ceramic products 

 Liner material 

 ECONOMIC ISSUES ASSOCIATED WITH FGD UTILIZATION 

 

 According to the Combustion 2000 Project (2001), the technical challenges of producing 

commercially usable by-product gypsum have mostly been solved, and the operating changes 

required to use these materials in commercial applications are becoming relatively well 

established. The area that remains a significant challenge is structuring successful relationships 

between producers and consumers. Ultimately, economic issues are the driving force that will 

determine the level of utilization. However, a by-product that is less expensive than a raw 

material will not automatically be sought after for industrial use. The factors which govern its 

desirability as a product are much more diverse. 

 Product constancy and reliably are the primary factors associated with the use of synthetic 

gypsum. Synthetic gypsum must consistently meet stringent quality parameters to be utilized in 

wallboard and other manufacturing. Two main areas that have received attention as process 

improvements are additives and forced oxidation. Additives are employed to improve SO2

removal by increasing the liquid-phase alkalinity. Forced oxidation of sulfite to sulfate 

(eliminating major dewatering problems) is an important major improvement in wet FGD 

systems. This has led to the development of the production of commercial-grade FGD gypsum 

(Combustion 2000 Project, 2001). Parameters that are most important to product quality include 

free moisture, purity, soluble salts, pH, particle size, and surface area. The free or surface 

moisture of synthetic gypsum usually ranges from 6% to 25%. Assuming the synthetic gypsum 
22 

meets particle-size requirements and does not contain any harmful impurities, a higher-purity 

synthetic gypsum will allow a lower-weight board to be produced without sacrificing strength 

(Henkels and Gaynor, 1997). Soluble salt impurities are common in natural and synthetic 

gypsums. The four soluble salt ions typically tested for are magnesium, potassium, sodium, and 

chloride. Chloride is the most common contaminant in FGD gypsum. Soluble salts found in FGD 

gypsum can often be washed away. 

Because the gypsum industry tends to have a much more exaggerated cycle than other 

industries within the construction industry, the commitment of the gypsum supplier is critically 

important to encourage a partnership with consumers. Commitment is seen in numerous forms, 

including supply reliability because building materials production plants operate very 

consistently, thus making supply interruptions difficult to manage; product quality to ensure 

impurities are controlled to acceptable levels; desirability of the local market region; and 

competitive advantage over competing materials. 

 Supply trends are essential to gypsum economics. Bruce (2002b), suggests that the biggest 

reason for the recent drop in the price for regular gypsum board has been the huge increase in 

capacity that has been put in place over the last four years. Bruce also suggests in a more recent 

article (2002a) that the industry has experienced shortages of synthetic gypsum. These shortages 

could be a result of the industries’ peak periods, where an excess capacity is needed to keep up 

with surges in demand. Despite the increase in wallboard production, some regions in the United 

States still remain in short supply and other regions have a severe surplus. 

 A critical element in the economic consideration of gypsum markets, natural or synthetic, 

is transportation costs. Gypsum wallboard, which is made from gypsum, and cement of which 

gypsum is a component, are bulk items sensitive to handling and transportation costs. For this 

reason, location of the gypsum source and manufacturing plant, distance between the two 

facilities, and mode of transport are critical. Two separate sources of information have been 

quoted as identifying completely different methods of transportation as most practical. One 

source stated that rail is by far the most economical alternative for transporting high volumes of a 

coal by-product from the plant site to an industrial location. A second source stated that any 

transportation distance under 100 miles is commonly and most ideally performed by truck. This 

would allude to the fact that each method of transportation is site-specific and entirely dependent 

upon the type of by-product produced and the form of utilization intended for that by-product. 

Cement plants have traditionally been located on or adjacent to limestone or dolomite deposits 

and are usually located within 100 to 150 miles of their markets. Wallboard plants located in the 

United States are generally within the vicinity of major urban areas. For the most part, the natural 

gypsum for these industries comes from those mined closest to their plants. For several gypsum 

operations, the economics have been such that wallboard plants are located on or adjacent to the 

mine (Combustion 2000 Project, 2001); however this scenario has changed with the new megaplants that are located near the synthetic gypsum suppliers (Miller, 2002). 
23 

DISPOSAL PRACTICES AND REQUIREMENTS 

 Currently, EPA classifies FGD material as a solid waste under RCRA Subtitle D. This 

classification places the responsibility to regulate disposal of FGD material on individual states. 

In the United States, regulations concerning selecting a disposal site and construction and 

operation of containment areas vary significantly between states. Collins (1992) lists the 

following parameters that generally play a role in development of state regulations: 

• Sufficient distance above local groundwater table 

• Soil conditions not prone to settling 

• Siting away from limestone quarries, waterways, floodplains, wellheads, aquifers, or 

underground mines 

• Suitable topography 

 For the utility, it is also important to consider the proximity of the disposal site to the 

power plant. Transportation costs can be significant, and utilities generally desire to minimize 

disposal costs. 

 The following disposal options have been used for wet FGD material (Smith, 1992): 

• Hydraulically conveyed and ponded 

• Dewatered and stacked 

• Interbedded with fly ash 

• Stabilized with lime, cement, and/or fly ash 

Most U.S. utilities dispose of FGD material using ponding or lagooning techniques. 

Appendix B provides an illustration of FGD disposal practices by state. Wet FGD material is 

frequently thixotropic, which is the property of a material that enables it to stiffen in a relatively 

short time on standing, but upon agitation or manipulation, to change to a very soft consistency 

or to a fluid of high viscosity, the process being completely reversible. 

FGD material disposal is likely to be impacted by rules for utility landfills/surface 

impoundments that are currently being developed by the EPA Office of Solid Waste. The final 

rule is scheduled for completion in March 2004. Discussions with industry representatives 

indicate some concern that the EPA rule for utility landfills/surface impoundments will require 

the phasing out of wet disposal sites. Wet FGD material would then need to be dewatered or 

stabilized prior to final disposal. 

FUTURE FGD SYSTEM INSTALLATIONS AND FGD MATERIAL MANAGEMENT 

 The evolution of the electric power industry toward more competition has led utilities to 

delay capital expenditures for pollution control equipment as long as possible. Phase I of the 
24 

CAAA affected only 10% of the coal-burning electric utilities (Kalyoncu, 1997). Although FGD 

installations have not been as popular as originally planned, FGD technology has made 

considerable progress in SO2 removal efficiency, reliability, and capital and operating costs 

during the past decade. Still, to meet stronger emission limits under Phase II of the CAAA, many 

utilities are expected to continue the cost-effective strategy of fuel switching. In a 1997 

document discussing the impacts of the CAAA on electric utilities, DOE estimated that only 12 

to 20 gigawatts of capacity would be scrubbed to comply with Phase II of the CAAA. The 

estimate was based, in part, on the fact that a number of utilities that had originally planned to 

install FGD systems had either deferred installation or canceled them in favor of fuel switching 

or purchasing allowances. The Bush Administration’s CSI, announced early in 2002, provides a 

basis for an alternate prediction. The CSI requires significant additional reduction of NOx and 

SO2 emissions and the first-ever national cap on mercury emissions. It has been predicted that 

the number of FGD systems is expected to double in the next 7 years in response to emission 

regulations (Government Panel, 2001). Wet FGD control of SO2 has the added advantage of 

removing oxidized mercury from the flue gas, so for some power plants, installation of wet FGD 

will provide multipollutant control to meet CSI SO2 and mercury emission caps. The use of wet 

FGD for this type of multipollutant emission control will depend on the mercury species 

currently produced at a given power plant and future coal sources because the mercury species in 

the emissions are coal-specific. The extent of applicability of mercury removal technologies 

appropriated with FGD systems will depend on the nature and level of control dictated by 

mercury emissions regulations. Based on current information on mercury emission control 

technologies, FGD systems are attractive for several reasons: 1) control of both SO2 and 

mercury, 2) demonstrated reliability, and 3) relative cost-effectiveness. The disadvantages 

include 1) the generation of high volumes of FGD material for management, possibly requiring 

disposal; 2) concern for mercury release from the FGD material under management scenarios; 

and 3) the specificity for control of oxidized mercury. These issues will need to be evaluated by 

individual companies considering the use of FGD for either SO2 emission control or 

SO2/mercury emission control. 

 Installation of FGD systems on currently nonscrubbed units will result in a large volume of 

FGD material for management. If predictions noted above are correct, the volume of FGD 

material could increase to 50+ million tons annually. If all new FGD systems were wet systems 

designed to produce FGD gypsum, the 25+ million tons of FGD gypsum produced would likely 

meet or exceed U.S. demand for gypsum, based on current gypsum production figures (USGS, 

2002). U.S. gypsum wallboard manufacturers, cement manufacturers, and other industry/uses 

currently use nearly 20% of the FGD material produced in the United States (Figure 3). While 

these use applications have the potential to utilize much greater volumes of FGD gypsum, 

barriers to these uses will need to be addressed. These barriers include the competition with 

mined gypsum, quality issues, potential transportation issues, and others reported to the barriers 

to utilization of coal combustion/desulfurization by-products (Pflughoeft-Hassett and others, 

1999). One area of potential increased use of FGD gypsum is in agricultural applications. FGD 

gypsum is currently used as an agricultural soil amendment (Figure 3), but before FGD gypsum 

from SO2/mercury emission control will be readily accepted in agricultural applications, the 

issue of potential for mercury release from this FGD gypsum needs to be investigated. In the 

assessment of management options for multipollutant control FGD material/gypsum, the fate of 

the mercury needs to be considered. 
25 

 As utilities consider options for SO2 emission control for future installations, it will be 

important to follow the current EPA activities related to guidelines for CCB disposal and mine 

placement. These guidelines will impact the cost of new CCB disposal facilities which will be 

required if the predicted volumes of FGD material are produced and may impact the potential for 

FGD material to be placed in mine settings, a potential high-volume application for FGD 

material and other CCBs. 

SUMMARY 

 FGD technology is well established and can be used to achieve the SO2 emission 

reductions required in the CSI. Additionally, much work has been and continues to be done on 

the utilization of FGD materials. The use of FGD gypsum in place of natural gypsum in 

wallboard manufacture, cement production, and other existing products has been demonstrated 

and commercialized. This has been accomplished because most of the technical challenges of 

producing commercially viable FGD gypsum have been solved, and the operating changes 

required to use these materials in commercial applications are becoming relatively well 

established. An area that remains a significant challenge in increasing the utilization of FGD 

gypsum is structuring successful relationships between producers and consumers. Other FGD 

materials are still in the process of being investigated for use in various applications, and 

technical challenges may require further investigation and demonstration in order to lead to 

commercialization. The issue of mercury associated with FGD material and its potential release 

to the environment is part of investigations funded by EPA, DOE, and industry; results of these 

studies may impact management of FGD material in the future. 

 Federal regulations are currently driving future emission control for coal-fired power 

plants, but based on the information currently available, it seems apparent that additional FGD 

systems will be installed on existing power plants. The increased production of FGD material 

will make it increasingly important to optimize utilization. As was recommended in the 1993 

EERC Report to DOE on the Barriers to Utilization of Coal Combustion/Desulfurization ByProducts by Government and Commercial Sectors (Sondreal and others, 1993), procurement 

guidelines should be implemented at the federal level to encourage the use of CCBs, including 

FGD material. The CCB industry needs to be vigilant in following government actions in order 

to identify and take advantage of opportunities to effectively maintain or perhaps increase the 

current FGD material utilization rate of 20%. All levels of government and industry need to work 

together in order to achieve optimum utilization of CCBs, including FGD material. 

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APPENDIX A 

FGD BY-PRODUCT GENERATED BY STATE, 1994

APPENDIX B 

STATE TOTAL FGD BY-PRODUCT BY METHOD 

OF DISPOSAL, 1994

APPENDIX C 

FGD SYSTMES AND MATERIALS – DEFINITIONS 
FGD SYSTEMS AND MATERIALS – DEFINITIONS 

 ACAA prepared the following definitions of FGD materials based on American Society 

for Testing and Materials (ASTM) terminology. This list was taken from a draft document dated 

July 10, 2001, and ASTM has not formally adopted all changes to these definitions. 

Dry FGD – an FGD system in which calcium- or sodium-based sorbents, usually hydrated 

lime, are introduced to the flue gas. Dry FGD systems use less water than wet systems, 

usually remove fly ash and sulfur dioxide simultaneously, and generate a dry by-product. 

Spray dryer systems are the most common design. In a spray dryer, slaked lime slurry is 

sprayed into the flue gas, and the resulting by-product, dried by the heat of the flue gas, is 

collected in a particulate control device with the fly ash. Other dry systems inject dry 

sodium sorbent directly into the boiler exhaust duct. The by-product of a dry FGD system 

is referred to by various names that include dry FGD ash, dry FGD material, and dry 

scrubber material. 

Dry FGD material – the product that is produced from dry FGD systems and consists 

primarily of calcium sulfite, fly ash, portlandite (Ca[OH]2), and/or calcite. Lime-based 

sorbent system dry FGD material mainly consists of calcium sulfite and dry fly ash, along 

with minor quantities of calcium sulfate. Sodium-based sorbent systems mainly consist of 

sodium sulfite and dry fly ash along with minor quantities of sodium sulfate. Dry FGD 

material is being used in construction, engineering, and agricultural applications; however, 

most of the material is stored in landfills. 

Dry sodium injection – see dry FGD. 

Ex situ oxidation (wet FGD) – forced oxidation that occurs outside of the scrubber and is 

used to produce FGD gypsum. 

FGD by-products – the term for the by-products from wet and dry FGD systems. See wet

and dry FGD material. 

FGD gypsum – gypsum formed from an oxidizing and calcium-based FGD process. Also, 

a precipitated gypsum formed through the neutralization of sulfurous acid (H2SO3) in FGD 

processes at coal-fired power plants. This gypsum can vary in purity, which is defined as 

the percentage of CaSO4·2H2O, and generally is over 94% for use in wallboard 

manufacturing. The less pure gypsum can be stockpiled (gypsum stacking), placed in 

ponds or captive landfills, or utilized in agriculture or construction. The nearly pure or pure 

FGD gypsum is utilized beneficially. The pure FGD gypsum is manufactured to meet the 

specifications of wallboard-manufacturing companies and is used for wallboard 

manufacturing, for cement production, and as plasters. Large quantities of FGD gypsum 

are produced and utilized. 

FGD material – a product of an FGD process typically using a high-calcium sorbent such 

as lime or limestone. Sodium-based sorbent and high-calcium coal fly ashes are also used 

in some systems. The physical nature of these materials varies from a wet thixotropic 
sludge to a dry powdered material, depending on the process. The wet thixotropic sludge is 

usually from a lime-based reagent wet scrubbing process and is predominantly calcium 

sulfite. It is the end product of dewatering equipment such as vacuum filters or centrifuges, 

although it can be the end product of a sedimentation pond. This dewatered end product is 

usually stabilized by mixing with lime and fly ash or other materials for disposal in 

landfills. There are systems where the end product is not dewatered but is highly 

concentrated in solids as the underflow from a thickener. It is then mixed with fly ash and 

another material and pumped to a surface impoundment for disposal. The wet product from 

limestone-based reagent wet scrubbing processes is predominantly calcium sulfate 

dihydrate, which is gypsum. This material readily dewaters, and there are systems in use 

where the slurry is transported to a pond and construction equipment is used to excavate 

and stockpile the gypsum. The production of commercial-grade FGD gypsum used for 

wallboard manufacturing usually requires forced oxidation in the scrubbers or external to 

the scrubbers and dewatering by filtration equipment such as vacuum filters or centrifuges 

and sedimentation ponds. The dry material from dry scrubbers that is captured in a 

baghouse along with fly ash consists of a mixture of sulfites and sulfates in addition to fly 

ash. This powdered material is referred to as dry FGD ash, dry FGD material, lime spray 

dryer ash, lime spray dryer, or lime spray dryer residue. 

FGD material dry scrubbers – the dry powdered material from dry scrubbers that is 

collected in a baghouse along with fly ash and consists of a mixture of sulfites, sulfates, 

and fly ash. 

FGD products – another term for the by-products from wet and dry FGD systems. 

FGD sludge – another name for scrubber sludge wet FGD material or filter cake. See wet 

FGD material. 

Filter cake – the material produced by filtering equipment such as vacuum filters for 

dewatering wet FGD material. See wet FGD material. 

Fixated FGD material – a designed mixture of dewatered FGD sludge (also known as 

scrubber sludge or filter cake) which is primarily calcium sulfite with either a low-lime 

(Class F) fly ash and lime with a high-lime fly ash (Class C) or with a low-lime fly ash and 

a cementitious material such as cement kiln dust, lime kiln dust, or fluidized-bed 

combustion ash. The designed mixture is produced in a mixing facility sometimes referred 

to as a sludge treatment plant, and transported by belt conveyor to an area where it is 

stockpiled for a number of hours or days to undergo an initial chemical set. The stockpiled 

material is then excavated and loaded onto trucks or other earthmoving equipment for 

placement as a fill in beneficial use applications or for placement in a landfill for storage or 

disposal, where it undergoes a further chemical set. After placement, the fixated material 

forms a stable, monolithic mass of low permeability. 

Fixated scrubber sludge – another name for fixated FGD material. 
Flue gas desulfurization – removal of gaseous sulfur dioxide from boiler exhaust gas. 

Primary types of FGD processes are wet scrubbers, dry scrubbers, and sorbent injection. 

Sorbents include lime, limestone, sodium-based compounds, and high-calcium coal fly 

ash. 

Forced oxidation – a process employed to supply additional air in wet FGD systems, 

resulting in a predominantly calcium sulfate dihydrate (gypsum) by-product with improved 

storage characteristics as well as greater commercial potential. 

In situ oxidation (wet FGD) – a process in which both SO2 absorption and oxidation are 

carried out within the scrubber. 

Lime spray dryer ash – the residue from a spray dryer FGD system. The resulting byproduct is dried by the heat of the flue gas and collected in a particulate control device with 

the fly ash. See dry FGD material. 

Lime spray dryer residue – another name for lime spray dryer ash. 

Scrubber – any of several forms of chemical/physical devices that remove sulfur 

compounds formed during coal combustion and especially from coal-fired power plants. 

See wet FGD. 

Scrubber sludge – another name for wet FGD material. See wet FGD material. 

Spray dryer – a type of dry FGD system. See dry FGD. 

Stabilized FGD material – another name for fixated FGD material. See fixated FGD 

material. 

Wet FGD – an FGD system which uses a wet scrubber to introduce an aqueous solution of 

either slaked lime (calcium hydroxide) or limestone (principally calcium carbonate) into 

the flue gas in a spray tower. The sorbent reacts with or oxidizes the sulfur dioxide in the 

flue gas and converts it to a by-product that is referred to as scrubber sludge, scrubber 

material, or wet FGD material. 

Wet FGD material – the by-product of wet FGD processes or systems. It is composed primarily 

of water, calcium sulfite/sulfate solids, and small quantities of fly ash. It has the consistency of a 

sludge when allowed to settle in a pond or when the water is removed by filtering equipment 

such as vacuum filters. It is commonly referred to as scrubber sludge. Depending on the 

composition of the injected lime or limestone, some by-products will also contain magnesium 

sulfite and/or sulfate and possibly traces of barium sulfite or boron in addition to some trace 

metals.