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Recently, coal-fired power plants in the United States have widely added scrubbers and selective catalytic reduction (SCR) systems, which have significantly reduced the concentration of SO2 and NOx pollutants in the air in the United States. But in some cases, chemical processes in downstream equipment can produce unexpected side effects. One is the increase in SO3 emissions, which leads to an increase in the opacity of chimney emissions (chimney opacity)-this phenomenon is sometimes referred to as "blue feather".
After installing an SCR device at the 2,600 MW General Gavin plant of the American Electric Power Company (AEP) in 2000, one of the blue plumes was first reported (Figure 1). For Gavin, it was only after a series of expensive and lengthy tests on different control technologies that an acceptable solution was found.
1. Unintended consequences. AEP’s General Gavin factory fought "Blue Feather" shortly after installing the SCR device. The injection of trona (the raw material for soda ash) has controlled SO3 emissions. Courtesy: American Electric Company
Any attempt to reduce blue feathers requires an understanding of the relationship between SO3 and the opacity of the chimney. When SO3 is converted to gas phase sulfuric acid (H2SO4), the smoke plume from the chimney of the power plant becomes opaque. When H2SO4 cools, it forms fine particles of sulfuric acid aerosol. At sufficient concentrations, the particles scatter light and produce visible plumes that are usually blue or brownish orange.
The color and opacity of the plume depend on aerosol concentration, aerosol size, sun angle, gas temperature, and atmospheric conditions. In most cases, when the H2SO4 aerosol concentration in the flue gas exceeds 10 to 20 ppm, smoke plumes can be seen. The higher the plume concentration, the greater the degree of discoloration, and the longer the plume stays in the atmosphere. Under severe conditions, plumes containing sulfuric acid may even reach ground level.
Among the factors that affect the opacity of smoke plumes, power plants can only control the SO3 concentration. The formation and concentration of SO3 depend on several variables, which vary from plant to plant, which makes prediction difficult. Because these variables reflect differences in fuel composition, component design, and plant operations, there is no one-size-fits-all solution.
SO3 production in coal-fired power plants is affected by multiple power plant systems, such as furnaces, SCR systems, air preheaters (APH), electrostatic precipitators (ESP) and wet flue gas desulfurization (FGD) devices (scrubbers) . The differences within the plant are the result of different chemical reactions that form SO3 during combustion and flue gas conditioning.
The scientific community has a fairly good understanding of the formation mechanism of SO3 and the performance of this compound in downstream emission control devices. Because there are as many gas path configurations as there are plants, your mileage may vary. Follow the gas path in Figure 2 to understand how each component affects the SO3 level.
2. Crawling regulations. The Gavin plant's supplement to the emission control system has been continuously developed over the past 35 years. Source: American Electric
2a. Gavin was built in the 1970s as a pulverized coal plant. The initial construction cost was US$660 million (US$1975) or US$1.7 billion (US$1999).
2b. Gavin amended to comply with the 1990 Clean Air Act Amendment. The cost of SO2 scrubber installation in 1995 was US$616 million. A low-NOx burner was installed in 1999.
2c. Gavin today-after complying with NOx SIP Call in 2001 and adding chemical injection to control SO3. The cost of SCR NOx control is US$195 million.
SO3 from the furnace. In the furnace, some SO2 (the normal byproduct of the combustion of any sulfur-containing fuel) reacts with atomic oxygen (O), molecular oxygen (O2), and with tube deposits (and local oxygen). The degree of conversion depends on the composition of the fuel, the temperature of the flue gas, the oxygen concentration in the furnace (excess air), and the ash content of the pipeline deposits. The conversion of SO2 to SO3 occurs in the radiant section and recirculation section of the furnace, and the conversion rate is about 1%. In other words, a typical furnace with 2,000 ppm SO2 in the flue gas also contains about 20 ppm SO3 in the flue gas leaving the economizer.
SO3 from SCR. The vanadium-based catalyst used in the SCR system to reduce NOx also oxidizes SO2 to SO3. The degree of conversion depends on the type of catalyst and flue gas temperature. The higher the temperature, the more SO3 will be produced. The conversion rate is usually 0.5% to 1.5%, so our typical furnace contains 2,000 ppm of SO2 in its flue gas, and another 20 ppm of SO3 is added to the flue gas at the SCR outlet (Figure 3).
3. Chemical plant. A chemical reaction that occurs in a selective catalytic reduction system. Source: American Electric
Reduce SO3 by air preheater. Compared with SCR system, air preheater can reduce SO3 level. Although the degree of reduction varies from unit to unit, it generally depends on the flue gas temperature and the type of heater (whether it is regenerative or tubular). The faster the temperature quench, the lower the outlet temperature of the air preheater, and the greater the reduction in SO3. A reduction rate of 10% to 50% is typical. However, the risk of H2SO4 formation increases at lower outlet temperatures (<500F), and this reduction will be suppressed. At lower temperatures, SO3 can also combine with ammonia escape from SCR or selective non-catalytic reduction (SNCR) systems to form ammonium bisulfate, which can deposit on the heater surface and cause blockages and increased pressure drop.
The electrostatic precipitator reduces SO3. ESP can also reduce SO3 levels. The degree of reduction mainly depends on the temperature of the flue gas and the composition of the fly ash. A large amount of SO3 reduction will transfer a large amount of SO3 to the fly ash, which may reduce the capture efficiency of the ESP device. Here, the reduction is usually from 10% to 50%.
Reduce SO3 through wet scrubber. The SO3 level is reduced by the wet FGD system. Since the temperature in the FGD device is lower than the H2SO4 dew point, this compound is usually converted into H2SO4 mist (gas phase sulfuric acid). The degree of reduction depends on the design characteristics of the wet scrubber, especially its temperature profile. The reduction is generally in the range of 30% to 40%. Since scrubbers are not good at removing H2SO4 aerosols, most of the SO3 converted into H2SO4 in the device will leave the chimney. It should be noted that it is difficult to distinguish between SO3 and H2SO4 in stack measurements; in fact, these two quantities are often used interchangeably.
After understanding the basic chemical process of SO3 formation and behavior in coal-fired power plants, owners and operators can use a three-step method to plan appropriate SO3 control strategies.
The first step is to understand SO3 behavior in the context of existing plant design and operating conditions. As mentioned in the previous section, targeted testing may be required to determine how much SO3 is actually added or removed by the downstream system. It is best for planners to check the consistency of these target data based on the content of the factory information history.
The second step is to assess the impact of proposed changes to plant equipment and operations on SO3 levels. This requires at least a "most likely profile" of SO3 behavior based on predicted plant conditions and experience in similarly configured plants. To increase the chances of reaching the best strategy, consider using analysis tools such as process or computational fluid dynamics (CFD) models to develop multiple scenarios and profiles.
The third step is to choose from the available SO3 control technologies. Options include replacing SCR with low conversion SCR catalyst and/or adsorbent injection after SCR. Commonly used adsorbents are slaked lime, magnesium hydroxide slurry, sodium bisulfite (the solution chosen by Cinergy's Gibson Station) or Trona (sodium sesquicarbonate)-the choice of General Gavin Station. CFD modeling (Figure 4) can compare the performance risks of different control options to help make decisions. For example, CFD modeling of lower furnace and upper furnace under different load conditions can simulate slurry injection performance and provide conceptual design considerations for SO3 control technology. It is possible to model and design specific design and operational considerations in advance, such as ejector position and mud flow rate.
4. Forecasting tools. Computational fluid dynamics model of slurry droplet ejection in the furnace. Source: International Response Engineering
If the factory is considering installing or upgrading ESP devices, planners should also try to predict the impact of this change on SO3 levels. The assessment should seek:
Once the technology assessment has identified one or more SO3 control technology options suitable for a given plant, the next step is to determine to what extent these options comply with current regulations (EPA Method 9). After this regulatory assessment, an economic and commercial feasibility assessment can be performed to quantify, compare and contrast the life cycle costs of options under different expected loads and operating conditions.
——Dr. Bradley Adams is the president of Reaction Engineering International (Salt Lake City, Utah); his contact number is 801-364-6925, ext. 18 or adams@reaction-eng.com. Dr. Constance Senior is the R&D manager; her contact number is 801-364-6925, ext. 37 or Senior@reaction-eng.com.
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