11 Control of Sulfur Oxides The control of particulates and VOCs is mostly accomplished by physical processes (cyclones, ESPs, filters, leakage control, vapor capture, condensation) that do not involve changing the chemical nature of the pollutant. Some particles and VOCs are chemically changed into harmless materials by combustion. This chapter and the next concern pollutants--sulfur oxides and nitrogen oxides that cannot be economically collected by physical means nor rendered harmless by combustion. Their control is largely chemical rather than physical. For this reason, these two chapters are more chemically oriented than the rest of the book. Sulfur and nitrogen oxides are ubiquitous pollutants, which have many sources. SO2, SO3, and NO2 are strong respiratory irritants that can cause health damage at high concentrations. We have NAAQS for SO2 and NO2. The states are required to prepare SIPs for the control of NO2 and SO2. These gases also form secondary particles in the atmosphere, contributing to our PM10 and PM2.5 problems and impairing visibility. They are the principal causes of acid rain. The Clean Air Act of 1990, Section 401--Acid Deposition Control, requires substantial reductions in our national emissions of both sulfur and nitrogen oxides over the next few decades. 11.1 The Elementary Oxidation-Reduction Chemistry Of Sulfur And Nitrogen This chapter concerns sulfur oxides; the next, nitrogen oxides. Their sources and control methods are significantly different, but their chemistry is quite similar, as this short section shows. Both sulfur and nitrogen in the elemental state are relatively inert and harmless to humans. Both are needed for life; all animals require some N and S in their bodies. However, the oxides of sulfur and nitrogen are widely recognized air pollutants. The reduced products also are, in some cases, air pollutants. In parallel form, the oxidation and reduction products of nitrogen and sulfur. Reduction means the addition of hydrogen or the removal of oxygen. If we reduce nitrogen, we produce ammonia (which logically should be called hydrogen nitride; but because it had a common name before modem chemical naming systems were devised, it goes by its common name, ammonia). Similarly, if we reduce sulfur, we produce hydrogen sulfide. Both hydrogen sulfide and ammonia are very strong-smelling substances, gaseous at room temperature (-60。C and -33。C boiling points, respectively), and toxic in high concentrations. (High concentrations due to accidental releases often cause fatalities. These occur in the production and use of ammonia as a fertilizer and refrigerant and in the production and processing of "sour" gas and oil, which contain hydrogen sulfide.) Neither ammonia nor hydrogen sulfide has been shown to be toxic in the low concentrations that normally exist in the atmosphere. When nitrogen is oxidized, nitric oxide (NO) and then nitrogen dioxide (NO2) form; likewise, sulfur forms sulfur dioxide (SO2) and then sulfur trioxide (SO3). These are all gases at room temperature or slightly above room temperature(boiling points 21。C, 34。C, -10。C, and 45。C, respectively). The oxides have higher boiling points than the hydrides. Both nitrogen and sulfur can also form other oxides, but these are the ones of principal air pollution interest. In the atmosphere NO2 and SO3 react with water to form nitric and sulfuric acids, which then react with ammonia or any other available cation to form particles of ammonium nitrate or sulfate or some other nitrate or sulfate. These particles, generally in the 0.1 to 1-μ size range, are very efficient light-scatterers; they persist in the atmosphere until coagulation and precipitation remove them. They are significant contributors to urban PMl0 and PM2.5 problems. They are the principal causes of acid deposition and of visibility impairment in our national parks. NO and NO2 also play a significant role in the formation of O3. The estimated concentrations of these materials in unpolluted parts of the world's atmosphere are SO2, 0.2 ppb; NH3, 10 ppb; NO2, 1 ppb. 11.2 An Overview of the Sulfur Problem Figure 11.1 on page 398 shows in part how sulfur moves in the environment as a result of human activities. It does not include the large amounts of sulfur emitted by volcanic eruptions nor the movement of sulfur into growing plants and then back out of decaying plants. Sulfur is the sixteenth-most abundant element in the earth's crust, with an abundance of about 260 ppm. The vast majority of this sulfur exists in the form of sulfates, mostly as gypsum, CaSO4.2H20, the principal ingredient of plaster and wallboards, or anhydrite, CaSO4. Gypsum is a chemically inert, nontoxic, slightly water-soluble mineral, found widely throughout the world. All organic fuels used by humans (oil, coal, natural gas, peat, wood, other organic matter) contain some sulfur. Fuels like wood have very little (0.1 per center less), whereas most coals have 0.5 percent to 3 percent (see Appendix C). Oils generally have more sulfur than wood but less than coal. If we burn the fuels, the contained sulfur will mostly form sulfur dioxide, S +O2 ---> SO2 (11.1) (in fuel) If we put this into the atmosphere, it will eventually fall with precipitation, mostly in the ocean (because most of the world's rain falls on the ocean), and over time become part of the land mass as a result of geologic processes. Again over geologic time, it will enter into fossil fuels and sulfide minerals, which humans extract and use. These uses generally lead to the formation of SO2. If we wish to prevent this SO2 from getting into the atmosphere, we can use any of the methods described in this chapter, all of which have the effect of capturing the sulfur dioxide in the form of CaSO4. 2H20 that will then be returned to the earth, normally in a landfill. Most often the overall reaction will be CaCO3 + SO2 + 0.502 ----> CaSO4 + CO2 (11.2) (limestone) In this reaction one kind of widely available rock (limestone) is mined and used to produce another rock (anhydrite or, with 2H20, gypsum), which we put back into the ground, and to release carbon dioxide to the atmosphere. We are concerned about adding to the CO2 in the atmosphere, but not nearly as much as we are about adding an equivalent amount of SO2. Although Eq. (11.2) appears simple, the details of carrying it out on a large scale are complex, as discussed in this chapter. In natural gas most of the sulfur is in the form of H2 S, which is easily separated from the other constituents of the gas. In oil (liquid petroleum) and also in oil shales and tar sands, the sulfur is chemically combined with the hydrocarbon compounds; normally it cannot be removed without breaking chemical bonds. In oils the sulfur is concentrated in the higher-boiling fraction of the oil, so the same crude oil can yield a low-sulfur gasoline (average 0.03% S) and a high-sulfur heavy fuel oil (e.g., 0.5 percent to 1 percent S). In coal much of the sulfur is also in the form of chemically bound sulfur, but some coals have a large fraction of their sulfur in the form of small (typically 100 μ) crystals of iron pyrite ("fools gold," FeS2). When the fuel is burned, almost all of the sulfur in the fuel, whether chemically bound or pyritic, is converted to sulfur dioxide (SO2) and carried along with stack gas. Some small fraction is captured in the ash, and some is converted to SO3. Mixtures of SO2 and SO3 are sometimes called SOx to remind us that some of the sulfur is in the form of SO3. Usually the SO3 is negligible, and we speak of these streams as if the only sulfur oxide they contained was SO2. The other important source of SO2 attributable to humans is the processing of sulfur-bearing ores. The principal copper ore of the world is chalcopyrite, CuFeS2. The basic scheme for obtaining copper from it is the overall high-temperature smelting reaction, CuFeS2 + 5/2 O2 ( Cu + FeO + 2SO2 (11.3) in which the iron is converted to a molten oxide that will float on the molten copper (with a silica flux) and thus be separated from it. The sulfur is converted to gaseous SO2. The principal ores of lead, zinc, and nickel are also sulfides, whose processing is similar to Eq. (11.3). Because the SO2 liberated in the preceding process has been widely recognized as an air pollutant for many years, considerable effort has been devoted to finding other ways to process these ores that do not produce SO2. There has been some success in developing processes that treat these ores by aqueous chemistry without producing any SO2 at all. Currently such processes are economical for partly oxidized copper oxide ores containing smaller amounts of sulfur. However, for ores like chalcopyrite, the processes have not proven economical and most of these ores are currently smelted with air or oxygen. The sulfur-containing gas streams most often dealt with in industry belong to three categories--reduced sulfur, concentrated SO2 streams, and dilute SO2 streams --each with its own control method, as discussed in this chapter. 11.3 The Removal of Reduced Sulfur Compounds from Petroleum and Natural Gas Streams As discussed, we can convert sulfur in organic compounds to various forms by oxidation or reduction. Here we discuss the technology for removing sulfur from gas streams when the sulfur is present in reduced form. These gas streams occur in many natural gas deposits and in many by-product gases produced in oil refining and in the fuel gases produced by coal gasification. This is a large liquid flow rate. To make the system practical, one must find a solvent that can absorb much more H2S than can the water. Fortunately, for many of the gases of air pollution and industrial interest, we can do that. H2S, SO2, SO3, NO2, HCI, and CO2 are acid gases, which form acids by dissolving in water. For H2S the process is H2S (gas) ? H2S (dissolved in water) ? H+ + HS- (11.4) If we can add something to the scrubbing solution that will consume either the H+ or the HS-, then more H2S can dissolve in the water, and much less water is needed. For acid gases, the obvious choice is some alkali, a source of OH- that can remove the H+ by H+ +OH- ? H20 (11.5) Removing the H+ on the fight side of Eq. (11.4) drives the equilibrium to the fight, greatly increasing the amount of H2S absorbed. The Uses and Limitations of Absorbers and Strippers for Air Pollution Control Absorber-stripper combinations are widely used to remove HCs from exhaust gas streams. This example shows that the removal of H2S from natural gas and similar streams is simple and straightforward. The system also works extremely well for removing ammonia from a gas stream, because NH3 is very soluble in water or in weak acids, forming a weak alkali by the following reaction: NH3 + H20 ( NH4+ + OH- (11.7) It is possible to make practically complete removal of NH3 from gas streams with water or weak acids. The solubility of ammonia is so high that generally the simplest possible forms of this arrangement are satisfactory. To remove SO2 from gas streams by this method is also relatively easy if there are no other acid gases present. For example, SO2 could be easily removed from N2 by the scheme using any weak alkali (for example, ammonium hydroxide), and the solution would be easily regenerated to produce pure SO2. The problem of removing sulfur dioxide from combustion gases is much more complex and difficult, as discussed. NO and NO2 are not readily removed from gas streams by the process. Although NO2 is an acid gas that produces nitric acid by reaction with water, 3NO2 + H20 ( 2HNO3 + NO (11.8) the reaction rate is slow. NO is not an acid gas, so that although we can remove NO2 from a gas stream with an alkaline solvent, we cannot remove NO with the same solvent. For this reason, weak alkali solvents are not successful for the joint removal of NO and NO2 or for the rapid removal of NO2 alone. No other solvent is known that serves well for this task. (My generation has not found a suitable solvent to do this; fame and fortune await the person who finds a suitable solvent to remove NO, NO2, and SO2 economically from combustion gases by the scheme) The scheme is widely used in the chemical and petroleum industries to make separations not directly related to pollution control, e.g., the separation of CO2 from H2. The absorption column can also be used without regenerating the absorbent solution if the amount of material to be collected is small and there is some acceptable way of disposing of the loaded absorbent. Sulfur Removal from Hydrocarbons Once H2S has been separated from the other components of the gas, it is normally reacted with oxygen from the air in controlled amounts to oxidize it only as far as elemental sulfur, H2S+ 1/2 O2 ( S + H2O (11.9) and not as far as SO2, H2S + 3/2 O2 ( SO2+H2O (11.10) The elemental sulfur is either sold for use in the production of sulfuric acid or land-filled if them is no nearby market for it. Although the chemical reaction in Eq. (11.9) for production of sulfur (the Claus process) is simple enough, there are a variety of Ways of carrying it out, and the details can be complex; see Kohl and Nielsen. Hundreds of such plants operate successfully throughout the world; every major petroleum refinery has at least one. Because elemental sulfur is inert and harmless and because reduced sulfur in the form of hydrogen sulfide or related compounds can be easily oxidized to sulfur or sulfur oxides, the entire strategy of the petroleum and natural gas industries in dealing with reduced sulfur in petroleum, natural gas, and other process gases is to keep the sulfur in the form of elemental sulfur or reduced sulfur (for example, H2S). Oxygen from the air is virtually free, so we can always move in the oxidation direction at low cost. In contrast, hydrogen is an expensive raw material, so that moving in the reduction direction is expensive. Sulfur in hydrocarbon fuels (natural gas, propane, gasoline, jet fuel, diesel fuel, furnace oil)is normally converted to SO2 during combustion and then emitted to the atmosphere. Large oil-burning facilities can have equipment to capture that SO2, but autos, trucks, and airplanes do not. The only way to limit the SO2 emissions from these sources is to limit the amount of sulfur in the fuel. For this reason the Clean Air Act of 1990 limits the amount of sulfur in diesel fuel to 0.05 percent by weight. Crude oils vary in their sulfur contents: low-sulfur crudes are called "sweet"; high-sulfur crudes, "sour." If the fraction of the crude oil going to gasoline or diesel fuel has too high a sulfur content (which many do under current regulations), most of that sulfur is removed by catalytic hydrodesulfurization, The mixture leaving the reactor is cooled, condensing most of the hydrocarbons. The remaining gas stream, a mixture of H2 and H2S, is one of the streams treated in a refinery for H2S removal by the process. Some petroleum streams in refineries are treated over these catalysts to remove both sulfur and nitrogen because those elements interfere with the catalysts used for subsequent processing. The resulting gas streams contain both H2S and NH3. Whether the treatment of gases with high concentrations of H2S and NH3 should be considered as air pollution control is an open question. For natural gas fields with H2S, treatment is a market requirement, because the typical purchase specification for natural gas in the United States is H2S ≤ 4 ppm. However, at one time in oil refineries H2S-containing gases were customarily burned for internal heat sources in the refineries if the H2S content was modest. Current U.S. EPA air pollution regulations forbid the burning of such refinery waste gases if they contain more than 230 mg/dscm (dry standard cubic meter) of H2S, so the removal of H2S down to that concentration in oil refinery gases is done by the method to meet air pollution control regulations. 11.4 Removal of SO2 From Lean Waste Gases The major source of SO2, except near uncontrolled copper, lead, zinc, and nickel smelters, which no longer exist in the United States, but do in some developing countries, is the stacks of large coal- or oil-burning facilities. Most of the largest ones are coal-burning electric power plants. For them, the typical SO2 content of the exhaust gas is about 0.1 percent SO2, or 1000 ppm (see Example 7.10), which is much too low for profitable recovery as H2SO4. There are several drawbacks to this procedure for dealing with the SO2 from an electric power plant. First, it requires a large amount of water. The computed water flow is approximately 1 percent of the flow of the Hudson River at New York City. Power plants located on the Hudson, the Mississippi, the Ohio, or the Columbia rivers could obtain such amounts of water, but most of the power plants in the world could not. Second, the waste water stream, which is 80 percent saturated with SO2, would emit this SO2 back into the atmosphere at ground level (river level); causing an SO2 problem that might be more troublesome than the emission of the same amount of SO2 from the power plant's stack. Third, in aqueous solution SO2 undergoes Reaction (11.12), (without the catalyst) which would remove most of the dissolved 02 in the river, making it impossible for fish to live in it. For this reason alone, simple dissolution of large quantities of SO2 in most rivers is prohibited. However, the first large power plant to treat its stack gas for SO2 removal did remove SO2 with river water. The Battersea Plant of the London Power Company is located on the banks of the Thames River, which is large enough to supply the water it needed. Furthermore, the water of the Thames is naturally alkaline because its course passes through many limestone formations, so that it will absorb substantially more SO2 than would pure water. To prevent the dissolved SO2 from consuming O2 in the river, the effluent from the gas washers was held in oxidizing tanks, where air was bubbled through it until the dissolved SO2 was mostly oxidized to sulfate (SO42-), before being discharged to the Thames. In this form the sulfur has a low vapor pressure and does not reenter the air nor kill the fish by consuming the river's dissolved oxygen. Although this pioneering plant had its problems, it was a technical success--removing over 90 percent of the SO2--and operated from 1933 to 1940. (The SO2 removal system was shut down in 1940 because the exhaust plume from this plant was wet due to the scrubber and, hence, very visible. It made a good navigation marker for German aircraft during the Battle of Britain.) As we saw in Example 11.2, the amount of scrubbing water required can be substantially reduced if we add a reagent to the water that increases the solubility of the gas being removed. Comparing this problem to the H2S removal problem in Examples 11.1 and 11.2, we see that: 1. The volumetric flow rate of the gas is about 1700 times that in the H2S removal problem (14 times because of the higher molar flow rate, and 120 times because of the lower gas density At 100 atm, methane has m 1.2 times the density of a perfect gas) 2. The power cost to drive the gas through the scrubber is thus 1700 times as large, for an equal AP. Thus minimizing pressure drop is much more important in this problem than in that. 3. Here there is no regenerator. If we regenerated the solution to produce a stream of practically pure SO2 we would have no economical way of converting it to a harmless solid, as the Claus process does with H2S. In the previous examples we said little about the internal features of the absorbing column. For the high-pressure treatment of H2S, either plate or packed towers are used, with little problem. For the SO2 problem, three plausible arrangements are sketched in Fig. 11.4. The first of these is a simple bubbler, in which the gas is forced under pressure through perforated pipes submerged in the scrubbing liquid. As the bubbles rise through the liquid, they approach chemical equilibrium with it. If the liquid is deep enough and the bubbles are small enough, this kind of device will bring the gas close to chemical equilibrium with the liquid. However, it has a high pressure drop. The gas pressure must at least equal the hydrostatic head of the liquid. If, for example, the liquid is a foot deep, then the hydrostatic head will be 12 inches of liquid, which is large enough to be quite expensive (see Example 7.3). Plate-type distillation and absorption columns are, in effect, a series of such bubblers, stacked one above the other, with the gas flowing up from one to the next and the liquid flowing down from one to the next through pipes called downcomers. At high pressures, where pressure drops are unimportant, they are the most widely used device. The second arrangement is a spray chamber. In it the gas flows up through an open chamber while the scrubbing liquid falls from spray nozzles, much like the heads in bathroom showers, through the gas. In this arrangement the gas pressure drop is small, but it is difficult to approach equilibrium because the gas does not contact the liquid as well as it does in the bubbler. Nonetheless, it is widely used because of its simplicity, low pressure drop, and resistance to scale deposition and plugging. The third arrangement is a packed column, which is similar to the spray chamber except that the open space is filled with some kind of solid material that allows the liquid to coat its surface and run down over it in a thin film. The gas passes between pieces of solid material and comes in good contact with the liquid films, in the most primitive of these, the solid materials were gravel or crushed rocks. More advanced ones use special shapes of ceramic, plastic, or metal that are fabricated to provide the optimum distribution of liquid surface for contact with the gas. This third kind of contactor can be designed to have a better mass transfer per unit of gas pressure drop than either of the other two kinds. All three of these arrangements, plus combinations of them, plus some other arrangements are in current use for removal of SO2 from power plant stack gases. The gas velocities in such devices range from about 1 ft/s in a packed tower to 10 ft/s for a spray chamber. If we assume we are going to treat the gas in Example 11.5 in a spray chamber at a gas velocity of 10 ft/s, the cross-sectional area perpendicular to the gas flow will be A= Q/A=1667ft2=155m2 Such devices are almost always cylindrical, because that shape is easier and cheaper to fabricate than, for example, a rectangular vessel of equal cross-sectional area. For this example the diameter would be (4 .1667 ft2/π)0.5 = 46 ft = 14 m. A typical length in the flow direction would be 50 ft. That is a very large diameter for any piece of chemical plant equipment, but not for a power plant. Often the flow will be divided into several smaller scrubbers in parallel. This choice avoids having to ship or fabricate too large a vessel and ensures that one of the vessels can be taken out of service for maintenance while the rest are in operation. Thus the power plant can continue to operate while one part of the scrubber is out of service. What problems might power plant operators encounter? First, there is the question of what to do with the sodium sulfate produced. Sodium sulfate (also called "salt cake") is used in detergent manufacture and in paper making, as well as in some miscellaneous uses. However, for those uses it must be quite pure. The sodium sulfate produced in this process would be contaminated with fly ash from the coal. (In most such operations the scrubber is downstream of an electrostatic precipitator, but even so some particles pass through the precipitator and are caught in the scrubber.) Thus if we wished to sell the sodium sulfate, we would have to get it out of solution (by evaporation and crystallization) and then purify it. If we did, we would find that the total amount produced in a few power plants would glut the current market, so that although a few power plants might sell their sodium sulfate, most could not. Because of its water solubility, it is not generally acceptable in landfills unless they are well protected from water infiltration. But the real difficulty is with carbon dioxide. Here we assumed that we could treat the exhaust gas with dilute alkaline solutions and remove the SO2, which is an acid gas. However, the exhaust gas from combustion sources contains another acid gas, CO2. Normally its concentration is about 12 percent, or 120 times that of the SO2. We are not generally concerned with the fate of CO2, but if it gets into solution it will use up sodium hydroxide by the reaction 2 NaOH + CO2 ( Na2CO3 + H20 (11.15) Any sodium hydroxide used up this way is not available to participate in Reaction (11.14). The real problem is how to absorb one acid gas while not absorbing another acid gas that is present in much higher concentration! Fortunately, this is possible because SO2 forms a much stronger acid than does CO2. The reactions that occur in the liquid phase are these: CO2(gas) <( CO2(dissolved); +H20 <( H2CO3 <( H+ + HCO3- (11.16) SO2(gas) <( SO2(dissolved); +H20<( H2SO3 <( H++ HSO3- (11.17) These show that each of the gases goes from the gas state to the dissolved state, then reacts with water to form the acid, which then dissociates to form hydrogen ion and the bisulfite or bicarbonate ion. If we find the right concentration of H+ in solution, it may be possible to drive the equilibrium in Eq. (11.16) to the left while driving the equilibrium in Eq. (11.17) to the right. That is indeed possible if the concentration of hydrogen ions is between 10-4 and 10-6 mols per liter (pH= 4 to 6). But this calculation shows that we cannot use an alkaline scrubbing solution at all; alkaline solutions have pH values of 7 or more. To remove SO2 without absorbing CO2, we must use a scrubbing solution that is a weak acid. Furthermore, we must be careful to control the pH of our solution so that it is acid enough m exclude CO2 but not acid enough to exclude SO2. As the solution absorbs SO2 it becomes more acid, and thus less able to absorb SO2. Controlling pH during the SO2 absorption process is of crucial importance to the operation of these devices. If the problem were to use NaOH to remove SO2 from a gas stream that contained no other acid gases, this would be a simple problem for which ordinary chemical engineering techniques would be satisfactory. The real problem is different from this one for the following reasons: 1. There is another acid gas, CO2, present that will use up our alkali unless we keep the solution acid enough to exclude it. 2. The amount of alkali needed is high, and the cost of sodium hydroxide is enough that we would prefer to use a cheaper alkali if possible. 3. We have to do something with the waste product, either sell it or permanently dispose of it. 4. . Because the volume of gas to be handled is very large, we must be very careful to keep the gas pressure drop in the scrubber low. The pressure drops that are normally used in the chemical and petroleum industry in gas absorbers are much too large to be acceptable here. Forced-Oxidation Limestone Wet Scrubbers The most widely used process to deal with these problems is forced-oxidation lime-stone wet scrubbing. There are a variety of flowsheets and of mechanical arrangements for this process; Figs. 11.5 and 11.6, show one of the most commonly used varieties. In it we see that the flue gas, from which the solid fly ash particles have been removed, passes to a scrubber module where it passes countercurrent to a scrubbing slurry containing water and limestone particles (as well as particles of other calcium salts). In principle this is the same as the H2S scrubber in Examples 11.1 and 11.2. Figure 11.6 shows the scrubber module as a vertical spray tower column with a single gas-liquid contacting tray, and with the bottom serving as a liquid storage and oxidation tank. At the top are two levels of entrainment separators. (These are often called Demisters, which is a brand name for one type.) The separators in the figure are chevron type. These devices cause the fine droplets carried with the gas to collect on their surfaces, coalesce, and fall back into the scrubber as drops large enough to fall counter to the upward-flowing gas. Some other designs use a packing with a very high open area in the tower or specialized bubbler designs. In the tower the SO2 dissolves in the slurry and reacts with limestone (and the other dissolved and suspended calcium salts) producing CO2, which enters the gas stream, and solid CaSO3. The latter is almost entirely oxidized to CaSO4, partly by the excess oxygen in the flue gases in the tower, mostly in the bottom of the scrubber module. In earlier designs the oxidation took place in a separate vessel, but most current devices use the bottom of the scrubber as a liquid oxidation reactor. The slurry of water and solid particles (CaCO3, CaSO4.2H2O, and CaSO3.0.5H20) is pumped from the sump at the bottom of the module to the sprays, where it forms drops that fall through the rising flue gas and do the actual SO2 removal. Finely ground limestone is added to the sump. A small stream of slurry is sent by the solid removal pump to a hydroclone (much like a multiclone,) from which the underflow passes to a belt filter, from which a semidry gypsum product leaves the system. The overflow from the first hydroclone is further treated to produce a liquid waste stream with a very low solids content, which goes to water treatment and disposal. The fresh water enters the system almost exclusively as wash water for the entrainment separators. The scrubber operates at or near the adiabatic saturation temperature of the entering flue gas, which is about 125。F In some installations the cleaned flue gas is reheated to about 175。F to restore plume buoyancy and prevent acid corrosion of the ducts and stack downstream of the reheater. Other installations discharge the gas at scrubber temperature and use corrosion-resistant materials to deal with the small amount of acid liquid that is not removed by the entrainment separators.This example shows that the liquid circulation rates ill these scrubbers are very very large. As a consequence, even though they remove most of the SO2 from the gas, the scrubbing slurry passes through them practically unchanged. Most of the chemical reactions take place in the effluent hold tank. (The slurry spends about 3 seconds per pass in the scrubber and about 8 minutes between passes through the scrubber in the hold tank.) Observations suggest that very little of the preceding 1% possible reaction occurs while the drops are falling; there is not enough time. This results in the pH of the drops declining as they fall, reducing their absorptive capacity). The development problems with limestone scrubbers. In the 1970s and early 1980s the electric utility industry suffered through the very painful development period of limestone scrubbers. By now the major problems have largely been solved, and these devices are reasonably reliable and useful if designed and operated properly. The major development problems were these: 1. Corrosion: The exhaust gases from coal combustion contain small amounts of many chemicals, e.g., chlorides. In an acid environment these proved much more corrosive to metals, including stainless steels, than the designers of the first systems had anticipated. 2. Solids deposition, scaling and plugging: Calcium sulfate and its near chemical relatives are slightly soluble in water and can precipitate on solid surfaces to form hard, durable scales that are very difficult to remove. These are the "boiler scales" that collect in teapots and hot water heaters. The scales formed in valves, pumps, control instruments, and generally anywhere that their effect could cause the most trouble. 3. Entrainment separator plugging: The spray nozzles shown in Fig. 11.6 do not produce totally uniform drops; some of the drops are small enough to be carried along with the gas and must be removed from the gas in the entrainment separator. If they are not removed, they will plug and corrode the ductwork downstream of the scrubber. The early entrainment separators were plugged by the solids contained in those small drops. 4. Poor reagent utilization: The product sulfates and sulfites can precipitate on the surface of the limestone particles, thus blocking their access to the scrubbing solution. This caused a high percentage of the limestone to pass unreacted into the solid waste product, raising reagent and waste disposal costs. 5. Poor solid-liquid separation: CaSO3. 0.5H20 tends to form crystals that are small, flat plates. These are very good at trapping and retaining water. If the solid product has too many of these it will have the consistency of toothpaste and not be acceptable for landfills. CaSO4 .2H20 forms larger, rounder crystals that are much easier to settle and filter. Flocculating agents added to the thickener improve this separation. The solution to these problems has been found by careful attention to engineering and chemical detail. The rate of liquid rejection to waste water (Fig. 11.5) is chosen to control the chloride content of the circulating liquid. It is kept low enough to protect the very expensive materials it contacts. (The most widely used metal for lining the surfaces of the modules is alloy C-276, 55% Ni, 17% Mo, 16% Cr, 6% Fe, 4% W. It costs roughly 15 times as much as ordinary steels.). The solids deposition was caused by local supersaturation with gypsum. Enough gypsum is kept in the circulating slurry to prevent that supersaturation, vastly reducing the scale deposition. The original entrainment separators were of the woven wire variety, which plugged easily. The chevron type shown in Fig. 11.6 is much easier to keep clean. All the fresh water entering the system comes in as entrainment separator wash water, which is applied as strong jets for a few minutes of each hour. The liquid holding tanks were made larger, thus allowing more time for the reagent to dissolve. This additional time plus more vigorous application of oxidation air resulted in convening ≈ 95% of the captured sulfur to gypsum, which forms large, easily filtered crystals. Some plants produce a gypsum waste stream clean enough and dry enough that wallboard manufacturers will purchase it, thus converting the plant's waste disposal cost to a by-product sale. In principle these systems are designed by the same methods as in Examples 11.1 and 11.2. In practice the five problems just listed have dominated the design and all efforts have been devoted to overcoming these problems. Most of these problems are now solved or reduced to manageable proportions by careful control of the process chemistry, good mechanical design, and careful operation. The design and operating practices are continuously being improved. But these scrubbers are still expensive and troublesome, and they generate large amounts of solid waste, which are a disposal problem. Detailed descriptions of the design, chemistry, and operating experience of these scrubbers have been published. Other Approaches During the period of development of the limestone scrubber, when its growing pains seemed unendurable (many believed that it would never work satisfactorily), many other approaches to the problem were suggested and tested. As the technical difficulties with the limestone scrubber were worked out, it became the clear economical choice for scrubbing stack gas from the combustion of medium- or high-sulfur coal. The other processes are not being used now for new installations, and some of those installed 20 years ago are being convened to forced oxidation limestone scrubbers to save operating costs. Other wet systems. Ca(OH)2 (hydrated lime, quicklime) is an alternative to limestone in wet throwaway processes. (Throwaway processes are ones in which the reagent is used once and then thrown away.) Its use is similar to that of limestone, shown in Fig. 11.6. Normally, CaO (lime, burned lime) is added to the oxidation tank and hydrates there to Ca(OH)2. It is more chemically reactive than limestone, mostly because it has a much higher surface area. (CaO is prepared by heating limestone and driving off the CO2. The result is a porous structure, as discussed. Typical surface areas are 15 m2/g.) But to use CaO requires an extra process step to prepare it for insertion in the process shown in Fig. 11.6. In the early days of scrubber development this extra reactivity seemed necessary, but as the problems with wet limestone scrubbers have mostly been solved, the additional reactivity of lime has seemed less likely to repay its extra cost. The other reagents shown are all more expensive than limestone and would not be used in a wet, throwaway process where cheap limestone can be made to work. In double alkali processes the scrubbing step is done with a sodium carbonate or sodium bicarbonate solution in the presence of a very low concentration of calcium. The solubility of sodium salts is much higher than that of calcium salts, so that in the scrubber all the salts are in solution and the liquid is practically free of solids. The liquid is taken out of the scrubber, the alkali is regenerated with lime or limestone in a reaction tank. The main reaction in the scrubber is Na2CO3 + SO2 ( Na2SO3 + CO2 (11.18) The overall reaction in the reaction tank is Na2SO3 + CaCO3 + 0.502 + 2H20 ( CaSO4 .2H20 + Na2CO3 (11. ,19) which regenerates the sodium carbonate (or bicarbonate) in solution and precipitates the calcium as CaSO4 .2H20. All the liquid from the reaction tank is sent to a thickener, where the calcium is removed, either as gypsum or as unreacted calcium carbonate (or as calcium hydroxide). Some dissolved sodium carbonate is lost in the solution in the moist solid waste stream, so additional sodium carbonate or bicarbonate is added in the thickener overflow tank, and the clear liquid from it is used as the scrubbing liquid. The ease of operation and reliability of the double alkali systems allowed them to compete with the early limestone scrubbers. As the limestone scrubbers improved, the extra complexity (more chemicals to handle, more vessels, pumps, lines, valves) and higher reagent cost of the double alkali systems made them uncompetitive. 11.5.2.2 Dry systems. The solids handling and wet sludge handling and disposal difficulties that are integral to wet throwaway processes induced engineers to develop dry throwaway processes that would have fewer corrosion and scaling difficulties and would produce a waste product much easier to handle and dispose of. All of these systems inject dry alkaline particles into the gas stream, where they react with the gas to remove SO2. The SO2-containing particles are then captured in the particle collection device that the plant must have to collect fly ash (most often a baghouse, sometimes an ESP). If successful, this approach eliminates the problems with disposal of wet scrubber sludge and all the difficulties involved with the wet limestone process. It increases the volume of dry solids to be disposed of, but that is considered a less difficult problem. The flow diagrams for such systems are sketched in Fig. 11.7. The first two call for the injection of powdered limestone or lime into the boiler. In the high-temperature part of the furnace the limestone would convert to lime, so that either way the active reagent would be CaO. The desired reaction is CaO + SO2 ---> CaSO3 (11.20) CaSO3 would then oxidize to CaSO4. In principle this should work, but most tests have shown that to get high SO2 collection efficiencies one must put a large excess of lime or limestone into the system, thus increasing reagent costs, increasing the load on the particle collector, and increasing the volume of solid wastes to be disposed of. However, if one uses more reactive (and much more expensive) NaHCO3 or Na2CO3, the collection efficiency is much better, mostly because of the much higher chemical reactivity of these sodium salts. The design of such devices is, in principle, done the same way as in Examples 11.1 and 11.2. However, here we have co-flow, which is much less efficient than counterflow. Mass transfer between gases and solids is much less well understood than that between gases and liquids, so that the design of these devices is much more heavily dependent on test and empiricism than is the design of systems like that. Wet-dry systems. Wet-dry systems combine some features of the preceding two kinds of systems. Spray dryers are widely used in the process industries. Masters presents a five-page list of products that are commercially spray dried, e.g., powdered milk, instant coffee, laundry detergents, etc. In all such spray dryers a liquid (almost always water) containing dissolved or suspended solids is dispersed as droplets into a hot gas stream. The dispersion can be done by a high-pressure gas-atomizing nozzle or a rapidly rotating (about 10 000 rpm) atomizing wheel. The hot gas is well above the boiling temperature of water, so that the water in the droplets evaporates rapidly. The particles formed from the evaporating drops are dry before they reach the wall or bottom bin of the dryer, so they form a free-flowing powder that is easily removed. In industry a spray dryer is most often used when the product is heat sensitive. The drying is done very quickly, and the powder can be cooled quickly alter it leaves the dryer. In addition, by controlling the solids concentration in the feed and the size of the droplets, one may control the size of the particles produced, often producing a particle size distribution not easily obtained any other way. With soluble solids one can often produce particles that are hollow spheres. The student should study some powdered coffee (not freeze-dried coffee) or laundry detergent as an example of products made this way. In treating SO2-containing flue gases, the hot gas enters the spray dryer chamber, usually from the side and/or top and flows out most often at the bottom or side or through an outlet tube that dips down into the dryer vessel. The reagent slurry, is dispersed as 10- to 50-μ drops, containing about 30 weight percent solids. The resulting dry particles are small enough that most are carried along with the gas stream; this feature is different from most spray dryers for consumer products, in which the particles are large enough (or the air velocity small enough) that most of the particles settle to the bottom of the dryer. This is called a wet-dry system because part of it is like a wet lime scrubber and part is like dry sorbent injection. The freshly formed drops behave very much like the drops in a wet lime scrubber. The SO2 dissolves in the water and reacts there with the dissolved Ca(OH)2. As the water evaporates from the drops, the individual fine particles in them coalesce to form a single porous panicle from each drop. This particle then behaves like the dry sorbent particles injected as shown in Fig. 11.7. Comparing this device to the wet limestone scrubber, we see that the drops are much smaller (20 μ/3 mm = 1/150). The time the gas spends in the scrubbing environment is roughly twice as large. However, once the particles become dry, their reactive capacity is greatly reduced compared to the drops in wet scrubbers. In addition, the co-flow pattern is much less efficient. The amount of .water one can introduce in these devices is limited by the amount that the hot gas can evaporate. If more water is introduced than is needed to cool the gas to the adiabatic saturation temperature, then not all the drops will evaporate, the resulting particles will be wet and sticky (plugging the filter), and the dryer and downstream equipment will suffer severe corrosion. The legend lists a test condition of"20。F approach temperature," indicating that the amount of water fed in the slurry was limited to keep the gas temperature 20。F above its adiabatic saturation temperature. Test data show that the collection efficiency improves as one approaches saturation, presumably because much of the reaction takes place before the droplet is completely converted to a solid and a close temperature approach keeps the drops wet longer. In addition, at high relative humidities the particles of Ca(OH)2 will adsorb one or two molecular layers of water, thus greatly increasing their reactivity compared with that of totally dry Ca(OH)2 at the same temperature. Water adsorption increases the collection efficiency after the droplets evaporate, both inside the spray dryer and in the baghouse. Operators carefully monitor their approach to the adiabatic saturation temperature: A close approach gives the best removal efficiency; too close an approach produces a sticky cake and corrosion. The high solids recycle rate shown is needed to get good reagent utilization. With once-through solids use the utilization is poor. In some cases the recycle material is first ground to break the particles open and provide better access to the unreacted materials in the centers of the particles. Regenerative systems. In these some kind of absorbent or adsorbent is used to capture SO2 from the flue gas. Then in some separate device or set of devices the adsorbent or absorbent is regenerated to produce a flow of relatively pure SO2 or H2SO4. These systems were under intense study and development when it appeared that the problems with wet limestone scrubbers were insoluble. As those problems were solved, interest in regenerative systems waned. Recently, work has begun on regenerative processes that will simultaneously capture both SO2 and NOx. These systems have not yet advanced to commercial scale, but they may have a major role in future air pollution control. Tomorrow's limestone control devices. The forced-oxidation limestone scrubber is a great technological accomplishment. It does a difficult task with high efficiency and reliability at a high but not impossible cost. However, industry would like a simpler, cheaper system. The manufacturers of forced-oxidation limestone scrubbers have shown in pilot plants that one can operate them at gas velocities up to 18 ft/s, if one can make the entrainment separators work well enough to capture the small drops that are carried along with the gas stream at that velocity. With this higher velocity one can use a much smaller scrubber with a large cost saving. Industry continues to try to develop dry limestone-based processes. As discussed above the low reactivity of limestone makes these difficult. However, if one recycles most of the captured particles through the boiler or through an intermediate gas-solid contact vessel and humidifies the gas almost to adiabatic saturation, then one can get satisfactory SO2 capture and satisfactory reagent utilization with these devices. Whether they will be more economical than the forced-oxidation limestone scrubber remains to be seen. 11.5 Alternatives to "Burn and Then Scrub" When the electric power industry first faced regulations requiring it to reduce the emissions of SO2 from power plants, it decided for the most part to leave the power plant alone and to scrub the gas leaving the power plant. This approach is still the most common, using either wet limestone scrubbers or lime spray dryers. But the industry never entirely abandoned the investigation of alternative approaches. With strong pressure from the Clean Air Amendments of 1990 to reduce emissions of acid rain precursors, the electric power industry has renewed interest in these other possibilities. Change to a Lower Sulfur Content Fuel If the management of a power plant can replace a high-sulfur coal with a low-sulfur coal, it reduces the SO2 emissions quickly, simply, and without having to install expensive SO2 control devices or to deal with their solid effluent. (Switching coals can cause some problems in the plant, which was presumably designed for the coal originally used, but such problems are generally manageable.) Many power plants that burned high-sulfur eastern coals switched to lower-sulfur coals from the Rocky Mountain states. This decision was a boon to the economies of Wyoming and Montana and a blow to the economies of the midwestern and eastern coal-producing states. This approach has been vigorously attacked, mostly on the grounds of job losses, by the midwestern and eastern coal miners and their elected representatives; it is a continuing political struggle. Remove Sulfur from the Fuel Another alternative is to remove the sulfur from the fuel before it is burned. Coal cleaning. Pyritic sulfur can be removed by grinding the coal to a small enough size that the pyrites are mostly present as free pyrite particles. Gravity methods are then used to separate the low-density coal (s.g. = 1.1 to 1.3) from the high-density pyrites (s.g. = 5.0). This approach is particularly suited for coals in which a substantial fraction of the sulfur is present as pyrites. Unfortunately, pyrite particles are generally quite small, so that very fine grinding is needed to separate them from the rest of the coal. Solvent-refined coal. It is also possible to dissolve coal in strong enough solvents and then to treat the solution by the same kind of catalytic hydrogenation processes that are used to remove sulfur from petroleum products. The mineral (ash-forming) materials do not dissolve, so they are rejected by filtration or settling. When the solvent is then removed for reuse, the remaining product is a very clean-burning combustible solid, free of ash and sulfur, called solvent-refined coal. Considerable development work on this process showed that it can be done, but so far not at a price comparable to "burn and then scrub." Modify the Combustion Process The standard way of burning large amounts of coal (pulverized-coal furnace) is to grind the coal to about 50- to 150-μ size and blow it with hot air into a large combustion chamber. There the small coal particles decompose and burn in the one to four seconds that they spend in the furnace, transferring most of the heat generated to the walls of the furnace as radiant heat. The furnace walls are made of steel tubes in which fluid (most often water turning to steam) is heated. The hot gases leaving the furnace then pass over banks of tubes and transfer much of their remaining sensible heat to the fluid being heated. Fluidized bed combustion is an alternative way to burn coal that is currently in the demonstration plant stage. In it, coal is burned in gravel-sized pieces by injecting them into a hot fluidized bed of limestone particles instead of as a finely dispersed powder in air. A fluidized bed is a dense bed of solid particles suspended in air; such beds are widely used in chemical engineering, e.g., in fluidized bed catalytic cracking. The coal spends much longer in the bed than it would in a pulverized coal furnace, because more time is needed to get complete combustion of the much larger particles. In such a fluidized bed combustor SO2 is formed in the presence of a large number of limestone particles and has a high probability of reacting with one of them in the combustion bed. Here the temperatures are much higher than in the dry processes discussed, and most of the limestone has been converted to CaO, so that the reaction of SO2 with CaO is rapid enough to provide adequate SO2 control. The limestone in the bed is steadily replaced, and the material withdrawn has largely been converted to CaSO4. Here again, a dry powder waste is produced instead of a wet scrubber sludge. The fluidized bed has tubes full of water and steam projecting into the bed. The heat transfer between the hot bed in which the coal is burned and the tubes is much better than that between the flames and the walls of an ordinary coal-fired boiler. For this reason fluidized bed combustors are smaller and operate at lower temperatures than ordinary coal-fired boilers. This saves on some costs and greatly reduces the formation of nitrogen oxides. These boilers, however, have other problems, so that they are not yet a clear winner over conventional boilers. A second combustion modification alternative, also in the demonstration plant stage, is to convert the coal to a synthetic fuel gas and then burn that in combination gas-turbine steam-turbine power plants. This seems complex and costly, but it has the advantage that in the synthetic fuel gas the sulfur is present as H2S; since no other acid gas is present, the sulfur can be easily removed from the gas by the methods described. The second, and more important, advantage is that modem gas-turbine steam-turbine plants have a much higher thermal efficiency than typical coal-fired steam plants (perhaps 45 percent vs. 33 percent). If the problems with this technology can be solved, it may offer a more efficient and economical way of converting coal to electricity than the systems currently used even though it is much more complex. Don't Burn at All The majority of the SO2 derived from human activities comes from coal and oil combustion in electric power plants. If we can produce electricity in some other way or reduce our use of electricity, we will consequently reduce our emissions of SO2. For this reason more efficient electric devices (lights, refrigerators, motors) are, in effect, SO2 control devices. So also are nuclear, wind, solar, tidal, geothermal, and hydroelectric power plants. There is currently a serious effort by the U.S. EPA and by the electric utility industry to improve the efficiency of electricity usage, and to encourage production of electricity from alternative energy sources for a variety of reasons, including reduction of SO2 emissions. 11.6 Summary 1. SO2 emissions from human activities are mostly due to the combustion of sulfur- containing fossil fuels and the smelting of metal sulfide ores. 2. The overall control strategy for SO2 emissions is to convert the sulfur to CaSO4.2H2O and return it to the ground in some kind of landfill, or use it to make wallboard. 3. For liquid or gaseous fuels containing reduced sulfur, the most common approach is to use catalytic processes to convert the contained sulfur to H2S, remove that by scrubbing the gas with a weakly alkaline solution, convert the H2S to elemental sulfur by the Claus process, and either sell that sulfur for sulfuric acid production or place it in a landfill. 4. For metal sulfide ore smelting, which produces waste gases with 4 percent or more SO2, the common approach is to convert that SO2 to sulfuric acid. 5. For coal (or high-sulfur oil) used in a large power plant, the most common approach is to burn the coal and then treat the plant's exhaust gas (typically containing about 0.1 percent SO2) with limestone or lime in a forced-oxidation wet scrubber or a spray dryer, to convert SO2 to CaSO4 . 2H20, which will then go to a landfill or a wallboard plant. 6. Other alternatives are being explored, some in large-scale demonstrations. They may replace those just listed in the future.