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Centrifuge Cake

Particulate Removal

Recovered SO2 to Conversion

Lime

^ w Solids Removal "& Disposal

Centrifuge Cake

Calciner

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Calciner

FIGURE 6-5. Regenerative magnesia scrubbing process. (From Elliot, T. C., Ed., Standard Handbook of Powerplant Engineering, McGraw-Hill, New York, 1989. With permission.)

The magnesium oxide process, shown in Figure 6-5, uses a slurry of slaked magnesium oxide (Mg(OH)2) to remove SO2 from the flue gas to form magnesium sulfite and sulfate via the basic reactions:

A bleed stream of scrubber slurry is centrifuged to form a wet cake containing 75 to 90% solids, which is then dried to form a dry, free-flowing mixture of magnesium sulfite and sulfate. This mixture is heated to decompose most of the magnesium sulfite/sulfate to SO2 and MgO. A stream of 10 to 15% SO2 is produced. Coke, or some other reducing agent, is added in the calcination step to reduce any sulfate present. The regenerated MgO is slaked and used in the absorber. The regeneration reactions are:

MgSO4(s) + ±C(s) + heat MgO(s) + SO2(g) + ¿CO2(g) (6-35)

The SO2 product gas is generally washed and quenched and fed to a contact sulfuric acid plant to produce concentrated sulfuric acid by-product. Sulfur production is possible but would be expensive because the SO2 stream is dilute.

Advantages of this process include high SO2 removal efficiencies (up to 99%), minimum impact of fluctuations in inlet SO2 levels on removal efficiency, low chemical scaling potential, the capability to regenerate the sulfate (which simplifies waste management), and more favorable economics compared to other available regenerative processes [8]. The main disadvantages of the process are its complexity and the need for a contact sulfuric acid plant to produce a salable by-product.

Dry Flue Gas Desulfurization Technology Dry FGD technology includes lime or limestone spray drying; dry sorbent injection, including furnace, economizer, duct, and hybrid methods; and circulating fluidized-bed scrubbers. These processes are characterized with dry waste products that are generally easier to dispose of than waste products from wet scrubbers. All dry FGD processes are throwaway types.

Spray Dry Scrubbers Spray dry scrubbers are the second most widely used method for controlling SO2 emissions in utility coal-fired power plants. Prior to 1980, the removal of SO2 by absorption was usually performed using wet scrubbers. Wet scrubbing requires considerable equipment, so alternatives to wet scrubbing have been developed, including spray dry scrubbers. Lime (CaO) is usually the sorbent used in the spray drying process, but hydrated lime (Ca(OH)2) is also used. This technology is also known as semi-dry flue gas desulfurization and is generally used for sources that burn low-to medium-sulfur coal. In the United States, this process has been used in both retrofit applications and new installations on units burning low-sulfur coal [5,6].

In this process, the hot flue gas exits the boiler air heater and enters a reactor vessel. A slurry consisting of lime and recycled solids is atomized/sprayed into the absorber. The slurry is formed by the reaction:

The SO2 in the flue gas is absorbed into the slurry and reacts with the lime and fly ash alkali to form calcium salts:

Ca(OH)2(s) + SOi(g) CaSO3 ■ i^O^) + i^O^) (6-36) Ca(OH)2(s) + SO3(g) + HiO(v) CaSO4 ■ 2HiO(s) (6-37)

Hydrogen chloride (HCl) present in the flue gas is also absorbed into the slurry and reacts with the slaked lime. The water that enters with the slurry is evaporated, which lowers the temperature and raises the moisture content of the scrubbed gas. The scrubbed gas then passes through a particulate control device downstream of the spray drier. Some of the collected reaction product, which contains some unreacted lime, and fly ash is recycled to the slurry feed system while the rest is sent to a landfill for disposal. Factors affecting the absorption chemistry include the flue gas temperature, SO2 concentration in the flue gas, and the size of the atomized slurry droplets. The residence time in the reactor vessel is typically about 10 to 12 seconds.

The lime spray dryer process offers a few advantages over the LSFO process [12]. Only a small alkaline stream of scrubbing slurry must be pumped into the spray dryer. This stream contacts the gas entering the dryer instead of the walls of the system. This prevents corrosion of the walls and pipes in the absorber system. The pH of the slurry and dry solids is high, allowing for the use of mild steel materials rather than expensive alloys. The product from the spray dryer is a dry solid that is handled by conventional dry fly ash particulate removal and handling systems, which eliminates the need for dewatering solids handling equipment and reduces associated maintenance and operating requirements. Overall power requirements are decreased because less pumping power is required. The gas exiting the absorber is not saturated and does not require reheating, thereby reducing capital costs and steam consumption. Chloride concentration increases the SO2 removal efficiencies (whereas, in wet scrubbers, increasing chloride concentration decreases efficiency), which allows the use of cooling tower blowdown for slurry dilution after completing the slaking of the lime reagent. The absorption system is less complex, so operating, laboratory, and maintenance manpower requirements are lower than those required for a wet scrubbing system.

There are some disadvantages of the lime spray dryer compared to the LSFO system, and these, along with the advantages, must be evaluated for specific applications [12]. A major product of the lime spray dryer process is calcium sulfite, as only 25% or less oxidizes to calcium sulfate. The solids handling equipment for the particulate removal device has to have a greater capacity than conventional fly ash removal applications. Fresh water is required in the lime slaking process, which can represent approximately half of the system's water requirement. This differs from wet scrubbers, where cooling tower water can be used for limestone grinding circuits and most other makeup water applications. The lime spray dryer process requires a higher reagent feed ratio than the conventional systems to achieve high removal efficiencies. Approximately 1.5 mol CaO per mol of SO2 removed are needed for 90% removal efficiency. Lime is also more expensive than limestone; therefore, the operating costs are increased. These costs can be reduced if higher coal chloride levels and/or calcium chloride spiking are used because chlorides improve removal efficiency and reduce reagent consumption. A higher inlet flue gas temperature is needed when a higher sulfur coal is used, which in turn reduces the overall boiler efficiency.

Combining spray dry scrubbing with other FGD systems such as furnace or duct sorbent injection and particulate control technology such as a pulse-jet baghouse allows the use of limestone as the sorbent instead of the more costly lime [4]. Sulfur dioxide removal efficiencies can exceed 99% with such a combination.

Sorbent Injection Processes A number of dry injection processes have been developed to provide moderate SO2 removal that are easily retrofitted to existing facilities and feature low capital costs. Of the five basic processes, two are associated with the furnace—furnace sorbent injection and convec-tive pass (economizer) injection—and three are associated with injection into the ductwork downstream of the air heater—in-duct injection, in-duct spray drying, and hybrid systems. Combinations of these processes are also available. Sorbents include calcium- and sodium-based compounds; however, the use of calcium-based sorbents is more prevalent. Furnace injection has been used in some small plants using low-sulfur coals. Hybrid systems may combine furnace and duct sorbent injection or introduce a humidification step to improve removal efficiency. These systems can achieve as high as 70% removal and are commercially available [4]. Process schematics for dry-injection SO2 control technologies are illustrated in Figure 6-6.

Figure 6-7 provides a representation of the level of SO2 removal that the dry calcium-based sorbent injection processes achieve and the temperature regimes in which they operate [13]. The peak at approximately 2200°F represents furnace sorbent injection, the peak at about 1000°F represents convective pass/economizer injection, and the peak at the low temperature represents all of the processes downstream of the air heater.

Another dry limestone injection technique, limestone injection into a multistage burner (LIMB), was developed from the 1960s to the 1980s but has not been adopted on a commercial scale for utility applications and is not discussed in detail here. In this process, which offers low capital costs and which is used in some industrial-scale applications where low SO2 removal is required, limestone is added to the coal stream and fed with the coal directly to the burner. This process gives poor SO2 removal (typically ~15% but in rare cases as much as 50%), experiences dead-burning (i.e., sintering or melting of the sorbent which reduces surface area and lowers sulfur capture), is difficult to introduce in a uniform manner, and can cause operational problems such as tube fouling and impairment of ESP performance because of excessive sorbent addition [8]. Sorbents under development are also not discussed in this section; rather, this section focuses mainly on commercial applications. Calcium organic salts (e.g., calcium acetate, calcium magnesium acetate, and calcium benzoate), pyrolysis liquor, and other sorbents are under development for use in injection processes.

Furnace Sorbent Injection (FSI) With the exception of LIMB, furnace sorbent injection (FSI) is the simplest dry sorbent process. In this process, illustrated in Figure 6-6a, pulverized sorbents, most often calcium hydroxide and sometimes limestone, are injected into the upper part of the furnace to react with the SO2 in the flue gas. The sorbents are distributed over the entire cross section of the upper furnace, where the temperature ranges from 1400 to 2400° F and the residence time for the reactions is 1 to 2 seconds. The sorbents decompose and become porous solids with high

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