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 HS, 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 NH 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 SOz From Lean Waste Gases The major source of So, 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 Soz content of the exhaust gas is about 0. 1 percent SOz, or 1000 ppm(see Example 7.10), which is much too low for profitable recovery as H2SO There are several drawbacks to this procedure for dealing with the sO 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 Hudso 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 SO, would emit this sOz 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 Oz in the river, making it impossible for fish to live in it For this reason alone, simple dissolution of large quantities of so in most rivers is prohibited However, the first large power plant to treat its stack gas for SO2 removal did remove SO 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 SOz--and operated from 1933 to 1940. (The SOz 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. I 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 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 l1-511－5 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 (SO4 2- ), 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