Flue-Gas Desulphurization

Abstract

Flue-gas desulfurization (FGD) materials are solids generated when the SO₂ in exhaust gases from coal-fired power plants is removed before the gases are released to the atmosphere. Over 60 million tons of FGD materials are generated annually in the United States, about half of which is used beneficially. Mine reclamation accounts for about half of beneficially used FGD, and the FGD gypsum used in the production of wallboard utilizes the next largest volume of FGD. Cement manufacture, construction of structural fills, and agricultural applications each utilizes significant volumes of FGD products. The current utilization of FGD material, which is about 50%, is expected to increase incrementally over the next decade, with the greatest volumes being in wallboard manufacture and the greatest gains in percentage use being in agricultural applications.

2.5 Flue-Gas Desulfurization Material

Flue-gas desulfurization (FGD) material is a product of a process typically used for reducing SO₂ emissions from the exhaust gas system of a coal-fired boiler. The physical nature of these materials varies from a wet sludge to a dry, powdered material depending on the process. The wet sludge from a lime-based reagent wet scrubbing process is predominantly calcium sulfite. The wet product from limestone-based reagent wet scrubbing processes is predominantly calcium sulfate. The dry material from dry scrubbers that is captured in a baghouse consists of a mixture of sulfites and sulfates. This powdered material is referred to as dry FGD ash, dry FGD material, or lime spray dryer ash. FGD gypsum consists of small, fine particles.

Calcium sulfite FGD material can be used as an embankment and road base material. Calcium sulfate FGD material, once it has been dewatered, can be used in wallboard manufacturing and in place of gypsum for the production of cement. The largest single market for FGD material is in wallboard manufacturing.

3.1 Introduction

Flue-gas desulfurization (FGD) systems have been used to limit the release of sulfur dioxide (SO₂) from coal-fired power plants since the late 1960s. The solids produced by FGD systems represent the second-largest coal combustion product (CCP) stream by volume, exceeded only by fly ash. In this chapter the various types of FGD systems in use and the solids they produce are described.

More recently, additional air emission controls have been employed at power plants that can also impact the characteristics of the high-volume CCPs. These include controls for sulfur trioxide (SO₃), hydrochloric acid (HCl), nitrous oxides (NO_X), and mercury. This chapter will also provide an introduction to these technologies and their possible impacts on CCPs.

Note that this chapter is largely updated from an Electric Power Research Institute report prepared by the authors (EPRI, 2008a), and is used with permission from EPRI.

14.4.7 Seawater FGD

Seawater FGD is attractive to plants that are located near coastlines. Seawater is a source of natural alkalinity that can be used economically to arrest SO₂ from flue gas without the use of any other supplemental reagents. Seawater contains significant concentrations of alkaline ions including sodium, magnesium, potassium, calcium, carbonates, and bicarbonates. It also contains significant concentrations of chloride and sulphite ions. Desulfurization is accomplished by seawater scrubbing, and 90% SO₂ removal efficiency could be achieved by adopting this process.

Before entering into the seawater scrubber flue gas is cooled to its adiabatic saturation temperature of typically 365 K. The scrubber is packed with certain material proprietary in nature through which flue gas flows from the bottom and seawater is sprayed counter-current to the flow of flue gas in order to achieve effective SO₂ mass transfer and chemical absorption into the liquid phase. Thus, SO₂ in the flue gas is absorbed and converted to sulphite first. Sulphite is further oxidized to produce sulphate for safe disposal to the sea without jeopardizing the marine environment. For disposal of liquid effluent to sea, it should be ensured that liquid effluent is alkaline with a pH no less than 8.

Sulfur Dioxide Corrosion and Atmospheric Pollution

To minimize the adverse effects of sulfur oxides (SO₂ and SO₃) on the environment, many power plants and industrial facilities use flue-gas desulphurization (FGD) scrubbers to remove SO₂ and SO₃ from combustion gases. The conditions within a scrubber and accompanying installations are very severe, cumulative, and cause corrosion problems for common engineering materials. Failures threaten the environment for lengthy periods.

Sulfur dioxide (SO₂) is a corrosive gas that is created by the oxidation of sulfur-bearing materials such as coals, oil, and natural gas. While it has long been deemed desirable to limit the concentration of SO₂ in combustion gases that are released to the atmosphere, no completely commercially satisfactory, dependable SO₂ removal system has yet been devised. SO₂ emission is a particularly acute problem in the electric power-generating industry where large quantities of coal are burnt.

It is well known that sodium-based scrubbing solutions, such as sodium hydroxide in water, have a great affinity for SO₂. Since such solutions are relatively expensive, attempts have been made to regenerate the sodium-based scrubbing liquors by reacting, or causticizing, the spent scrubbing solutions with an alkaline earth compound, such as lime or limestone. Such a regenerating process is mentioned in US Pat. No. 1,271,899 wherein a dilute solution of sodium sulfite leaving a scrubbing apparatus is reacted with lime to produce calcium sulfite as a precipitate and to regenerate the sodium hydroxide scrubbing liquor [2].

FGD is a set of technologies used to remove SO₂ from exhaust flue gases of fossil-fuel power plants, and from the emissions of other sulfur oxide-emitting processes. In this system, equipment such as absorber towers, demister supports, gas outlets, recycle and process piping, process tanks, and agitators are highly exposed to corrosive and abrasive environments. Rubber linings have fundamental advantages so that neither the physical nor chemical properties of the scrubbing liquid have any major effect upon its service life. The main parameter affecting the life of the design is the diffusion of water vapor through the rubber that attacks the metal surface beneath and affects the process temperature. Chlorobutyl rubber of 60 Shore A durometer is used for the FGD absorber, associated demister internals, and other component piping. For agitators, rake arms, and gypsum dewatering, natural rubber of 60 Shore A is suitable. FGD absorber service life histories confirm that the chlorobutyl linings give trouble-free service when correctly applied and cured. Chlorobutyl linings offer excellent chemical, heat, weather, and ozone resistance compared to natural rubber [3].

However, the 60 durometer natural rubber specifically compounded for the FGD rubber absorption pipe has double the abrasion resistance compared to the chlorobutyl linings. In selecting a rubber lining for a pipe, either for recycled slurry, reagent feed, gypsum dewatering, or filtrate systems, one must take into account the volume flow, percentage of solids, and particle size to make the proper choice of the rubber compound. Laboratory tests comparing various durometer compounds showed vast differences in water absorption. A 40 durometer natural rubber gains five times the amount absorbed by a 60 durometer lining. Where abrasion is considered severe in FGD, 60 durometer natural rubber is the proper selection. When moderate to light abrasion is encountered, 60 durometer chlorobutyl lining may also be utilized.

In many FGD pipe applications, 40 durometer pure gum rubber compounds (i.e., with fewer fillers) give only 3–7 years of service whereas a 60 durometer natural rubber gives 7–10 years of life. Since most FGD scrubber piping encounters very light abrasion, installing chlorobutyl is expected to last in excess of 15 years. Chlorobutyl is better for the absorber and the demister supporters as the performance lining.

Power facilities are the largest generators of SO₂, which may cause acid rain. Sulfur is one common element found in coal. When burned, the sulfur in coal turns into sulfur dioxide. When sulfur dioxide mixes with moisture in clouds, it creates acid rain. The power plants were required to meet the tougher air quality emission standards. Adding sodium-based exhaust gases reduces SO₂ emissions by 98%. In the FGD units, reductions of the emissions by this amount have become the most common type of technology used in bituminous and coal-fired power plants. However, corrosion continues to prevail in the system.

4.2.1 Compaction

MWC ash possesses the potential for pozzolanic behavior due to the presence of high free lime content. Recognizing this potential pozzolanic reaction is critical (1) to implement any contemplated residue testing requirement and (2) to incorporate into the residue disposal site management practices.

Abstract

Coal combustion products (CCP) are fly ash, bottom ash (or boiler slag), and flue-gas desulfurization gypsum. All have three fundamental properties: chemical composition, mineral composition, and particle size distribution. Among these CCP and fundamental properties, fly ash has the largest volume, with an extremely broad range of particle sizes that exhibits large variability from plant to plant, even in different batches from the same plant. Air classification is used to classify fly ash into at least two or more fractions with consistent quality and desired particle size distributions, particularly fine particle size for high value utilization in selected applications. For better efficiency and lower separation cost to obtain the fine particles, fly ash from each electrostatic precipitator at the coal-fired power plant should be collected separately. Air classification can obtain the finest fly ash, maintain its spherical shape, and consume less energy than milling. Air classification is also more efficient than sieving for a large scale production.

Flue Gas Desulfurization (FGD) Processes

In many plants it is necessary to remove sulfur from the flue gases after the combustion process to meet environmental requirements. For this reason FGD is widely used to control emissions of sulfur dioxide (SO₂) and sulfur trioxide (SO₃) from plants burning coals with high sulfur contents. Various FGD technologies have been developed (as summarized in Department of Trade and Industry, 2000b, and Thomas, 2002), with selection made on an economic basis after taking into account technical considerations. Specific issues include the degree of desulfurization that the process can offer as well as its flexibility. Most FGD technologies use an alkali sorbent, such as limestone (calcium carbonate), quicklime (calcium oxide), hydrated lime (calcium hydroxide), or sometimes sodium and magnesium carbonate and ammonia, to capture the acidic sulfur compounds from the flue gas. In all cases the alkalis react with the SO₂ in the presence of water (e.g., a spray of slurry containing the sorbent) to produce a mixture of sulfite and sulfate salts. This reaction may take place in the bulk solution or on the wetted surface of the solid alkali particles. The various types of processes are referred to as wet, dry, and semi-dry flue gas desulfurization techniques (Bigham et al., 2005).

The most common FGD technology uses a limestone/gypsum wet-scrubbing process. Usually the plant is located downstream of the electrostatic precipitator (ESP) so that most of the fly ash generated from combustion is removed before the gas reaches the FGD plant. In the process of desulphurization the gas is scrubbed with a recirculating limestone slurry, which removes almost 95% of the SO₂ from the flue gas. The process also removes almost all the HCl contained in the flue gas. The calcium carbonate in the limestone reacts with the SO₂ and oxygen from the air to produce gypsum, which precipitates from the solution. The HCl is also dissolved in the water and neutralized, producing a solution of calcium chloride. The gypsum slurry is recovered from the absorber sump and stored or treated for further use (e.g., as plaster board), and fresh limestone is pumped into the absorber to maintain the pH conditions. The remaining gas is reheated. Other FGD technologies include seawater washing, ammonia scrubbing, and a method employing aqueous sodium sulphate solution (Wellman-Lord process).

The semi-dry FGD processes employ a circulating fluidized bed, dry spray, or duct dry spray to produce powdered mixtures of calcium compounds. FGD technology using dry processes injects lime or sodium bicarbonate into the furnace of the boiler to absorb the SO₂. The sorbent is then extracted, together with the fly ash, as a mixture of ash and calcium/sodium components.

Wet FGD systems tend to utilize sorbent more efficiently than dry processes and typically can reduce SO₂ emissions by more than 90% (Bigham et al., 2005). Dry FGD systems, however, are more easily retrofitted onto existing combustion facilities. In both cases, the removal of SO₂ from flue gases results in a solid residue that must either be disposed of or utilized in a beneficial manner. Kost et al. (2005) and Bigham et al. (2005) provide detailed chemical and mineralogical data on a range of flue gas desulfurization products, including materials from fluidized-bed combustion systems as well as FGD units fitted to pulverized fuel plants. In addition to the mineralogy as indicated by X-ray diffraction and thermal analysis, the latter study also includes information on the swelling characteristics of the materials, brought about by interaction of anhydrite (CaSO₄) in the materials with water to form gypsum, and data on the mobility of different trace elements when the materials are exposed to weathering conditions.

FGD systems

Although PAC injection has shown the most promise as a near-term mercury control technology, testing is underway to enhance mercury capture for plants equipped with wet FGD systems. These FGD-related technologies include: (i) coal and flue gas chemical additives with fixed-bed catalysts to increase levels of oxidized mercury in the flue gas; and (ii) wet FGD chemical additives to promote mercury capture and prevent re-emission of previously captured mercury from the FGD absorber vessel. There is much interest in these activities as the use of FGD systems at coal-fired power plants is expected to increase significantly over the next 15 years. Wet FGD systems, especially those associated with bituminous coal-fired power plants equipped with SCR systems, appear to be good candidates for capturing mercury. With the projected increase in wet FGD systems for bituminous coal-fired power plants, the co-benefit of capturing mercury with SO₂ can be realized. Research is currently underway to evaluate technologies that facilitate mercury oxidation and to ensure that captured mercury is not re-emitted from FGD systems. Research to date is encouraging.

XV.B Production of Electricity from Existing and Proposed Power Plants

Electric power may be supplied to consumers from a variety of existing and proposed sources.