Flue gas fine treatment system

Abstract

A caustic scrubber for removing SO2 from flue gas for use in a fuel cell assembly, the caustic scrubber comprising: a caustic scrubber tower comprising a packed bed of material; a flue gas inlet configured to direct flue gas into the caustic scrubber column; a scrubber solution pump configured to pump a scrubber solution comprising NaOH and H2O2 into the caustic scrubber column; and a waste scrubber solution outlet configured to discharge a waste scrubber solution, the waste scrubber solution comprising a sulfur salt formed by a reaction between the scrubber solution and SO2 in the flue gas.

Description

Cross-references to related applications

[0001] This application claims the benefit and priority of U.S. Provisional Patent Application No. 63 / 585,018, filed on September 25, 2023, which is incorporated herein by reference in its entirety. Background Technology

[0002] This application relates to a fuel cell power generation system, and more specifically to the purification of flue gas from a conventional power plant so that such flue gas can be used in a fuel cell.

[0003] A fuel cell is a device that directly converts the chemical energy stored in hydrocarbon fuel into electrical energy through an electrochemical reaction. Generally, a fuel cell includes an anode and a cathode separated by an electrolyte matrix that conducts charged ions. To generate a usable power level, a number of individual fuel cells are stacked in series, with conductive separators between each cell.

[0004] Molten carbonate fuel cells can be used to separate and capture carbon dioxide from flue gas emitted from coal-fired and natural gas power plants. The flue gas can be fed to the cathode of the fuel cell, where carbon dioxide and oxygen react to form carbonate ions. The carbonate ions travel through the electrolyte matrix to the anode, where they react with hydrogen to form water and carbon dioxide. The carbon dioxide can then be sequestered or used in other industrial processes to reduce the carbon footprint of the power plant.

[0005] However, molten carbonate fuel cells are sensitive to pollutants such as SO2, SO3, and particulate matter, which can reduce cell efficiency and lifespan. These pollutants are typically present in relatively high concentrations in power plant flue gas. Therefore, it would be advantageous to provide a system that reduces pollutant levels before the flue gas is directed to the fuel cell. Attached Figure Description

[0006] Figure 1 A schematic diagram of a flue gas fine treatment system according to an exemplary embodiment is shown.

[0007] Figure 2 An exemplary embodiment is shown. Figure 1 A schematic diagram of the harshness scrubber system.

[0008] Figure 3 Control according to an exemplary embodiment is shown Figure 1 A method for determining the H2O2 level in the scrubber solution of the system.

[0009] Figure 4 An exemplary embodiment is shown. Figure 1 A schematic diagram of the bag filter chamber of the system.

[0010] Figure 5 An exemplary embodiment is shown. Figure 1 A schematic diagram of the system's demister.

[0011] Figure 6 A diagram of a pilot-scale caustic washer used during testing.

[0012] It should be understood that the accompanying drawings are schematic representations for illustrative purposes. The drawings are provided to illustrate one or more implementations, and it is clearly understood that the drawings are not intended to limit the scope of the meaning of the claims. Detailed Implementation

[0013] In the following detailed description, reference is made to the accompanying drawings, which form part of the detailed description. In the drawings, similar symbols generally identify similar components unless the context otherwise requires. The illustrative embodiments described in the detailed description, drawings, and claims are not intended to be limiting. Other embodiments may be utilized, and other changes may be made, without departing from the spirit or scope of the subject matter presented herein. It will be readily understood that, as generally described herein and illustrated in the accompanying drawings, aspects of this disclosure can be arranged, substituted, combined, and designed in a variety of different configurations, all of which are expressly contemplated herein and are part of this disclosure.

[0014] As shown in the figure and described below, the present invention provides a refining system for reducing SO2, SO3, particulate matter (PM), and other contaminants in power plant flue gas. Molten carbonate fuel cells can separate carbon dioxide from flue gas streams for storage or other industrial applications, thereby reducing the carbon footprint of power plants. However, SO2, SO3, PM, and other contaminants in flue gas can reduce the efficiency and lifespan of fuel cells. Therefore, it is advantageous to remove these contaminants from the flue gas before it is directed to the fuel cell.

[0015] According to an exemplary embodiment, a flue gas fine treatment system is provided for removing SO2, SO3, PM, and other contaminants from a power plant flue gas stream. The system includes a caustic scrubber that applies a scrubber solution to the flue gas to reduce the SO2 level. After passing through the caustic scrubber, the flue gas is heated and pressurized by a blower and directed to a bag filter chamber, where it passes through a fabric filter sock that captures PM. The flue gas is then directed to a demister, which includes a demister pad configured to capture SO3 and residual PM in the flue gas. Treating the flue gas in the caustic scrubber and bag filter chamber improves the SO3 removal rate in the demister because it reduces the amount of PM that could accumulate on the demister pad, thus reducing the demister's efficiency. The flue gas fine treatment system can reduce SO2 in the flue gas by up to 99.99%, SO3 by up to 99.9%, and PM to approximately 5 to 25 micrograms per cubic meter (typical detection limits).

[0016] Pollutant monitoring Table 1 below shows the typical flue gas concentrations entering the refining system from a coal-fired power plant according to a specific embodiment. It should be noted that the values ​​in Table 1 represent flue gas concentrations from the example coal-fired power plant, and the input concentrations may vary based on the source of the flue gas. For example, the input concentrations may vary significantly over time based on differences in the fuel type (coal, natural gas, etc.) of a particular plant or source (e.g., flue gas from two different coal-fired power plants may have different contaminant concentrations) or the specific operating conditions of a single source. Flue gas can be received from other types of power plants and other industrial sources, including manufacturing plants.

[0017] Table 1: Flue Gas Inlet Concentration in Typical Coal-fired Power Plants

[0018] The inlet values ​​of selenium and arsenic were estimated from literature on emissions from coal-fired power plants. The purging system is most relevant to removing SO2, SO3, and PM to achieve efficient operation of fuel cells using purged flue gas. However, other contaminants can also be removed by this system. The target concentrations used in the fuel cell and the expected concentrations after purging with the system disclosed herein are shown in Table 2 below. It should be noted that these are example target concentrations, and the system may require different concentrations depending on the planned use of the purged flue gas and the initial input concentration.

[0019] Table 2: Concentration in the Fine Treatment System

[0020] As discussed above, the intake values ​​of selenium and arsenic are estimated from the literature on emissions from coal-fired power plants.

[0021] The analyzer system can be used to continuously monitor SO2 and SO3 / H2SO4 concentrations, as well as HCl, CO2, NO, NO2, O2, and H2O. The analyzer's detection limits for SO2, SO3 / H2SO4, and HCl are sufficient for concentrations in the inlet flue gas and for expected low concentrations of SO2 and HCl at the demister outlet. The analyzer can be configured to set alarms to notify the system of increases or decreases in SO2, SO3, and HCl in the flue gas flowing into the flue gas treatment system. This allows control decisions to modify the system's operating mode to prevent operation from exceeding specified limits.

[0022] PM can be measured during baseline acceptance testing via discrete sampling and weight analysis. Once established, it cannot be changed as long as the master plant operation remains at a consistent base load output.

[0023] The concentrations of CO2, NO and NO2 (NOx), O2, and H2O are also important for plant process control. These components are present in the flue gas at sufficient levels to achieve adequate analyzer performance and can also be monitored. The analyzer can notify the system of changes in CO2 or O2 levels in the flue gas and allow controls to adjust operations to compensate for such changes in the flue gas feed.

[0024] Flue gas fine treatment system refer to Figure 1The diagram shows the main components of the purification system 10. First, the flue gas stream 105 is fed to a caustic scrubber 100, which removes SO2 from the flue gas 105 and outputs a scrubbed flue gas stream 106 containing less than 0.01 ppm SO2. The scrubbed flue gas stream 106 is then directed to a primary flue gas blower 150, which heats the scrubbed flue gas stream 106 to approximately 180°F using compression heat, above the dew point of the scrubbed flue gas stream 106. The heated scrubbed flue gas stream 106 is then fed to a bag filter chamber 200 comprising several fabric filter socks. As the scrubbed flue gas stream 106 passes through, PM in the scrubbed flue gas stream 106 accumulates on the socks. Bag filter 200 then outputs a filtered flue gas stream 14 with particulate levels below approximately 85 micrograms per cubic meter. Finally, the filtered flue gas stream 14 output from bag filter 200 is directed to demister 300, which captures and removes aerosolized SO3 and remaining fine PM from the filtered flue gas stream 14. Demister 300 outputs a finely treated flue gas stream 16. System 99 can reduce SO3 levels in flue gas stream 105 by up to 99.9% to approximately 0.002 ppm, and PM levels can be reduced to approximately 5 to 25 micrograms per cubic meter (typical detection limits). Waste scrubber solution 104 from caustic scrubber 100 and flush water from the demister are conveyed to effluent holding tank 115 for disposal. Each major system component is discussed in detail below. It should be understood that the detection limits disclosed herein relate to example analytical tools, and other tools with higher or lower detection limits may be included.

[0025] In some embodiments, when the flue gas 105 is above its dew point and / or at a higher temperature, the bag filter 200 may be located before the caustic scrubber 100 because the bag filter 200 may be able to operate at a higher temperature than the caustic scrubber 100. In this case, the primary blower 150 may not need to use compression heat to heat the flue gas. If the caustic scrubber 100 is located before the bag filter 200, the primary blower 150 may need to heat the scrubbed flue gas stream 106 above its dew point to prevent clogging of the bag filter stock. The caustic scrubber 100 and bag filter 200 are preferred before the demister 300 to prevent additional PM and SO2 from reaching the demister 300, which could affect its performance and lifespan. The demister may include a relatively fine filter that could quickly become clogged if the flue gas 105 is not first treated in the caustic scrubber 100 and bag filter 200. The primary blower 150 can be located after the demister; however, this may affect the performance and service life of the demister 300, and the washed flue gas stream 106 will not be heated by compression heat before entering the bag filter chamber 200.

[0026] caustic washer Flue gas from coal and biomass power plants has an SO2 concentration of approximately 10 ppm. This level may sometimes rise to 20 ppm for extended periods and may reach as high as 78 ppm for shorter periods. For ideal fuel cell operation, this concentration should preferably be reduced to approximately 0.01 ppm or lower. Caustic scrubbers traditionally use a caustic solution of NaOH that can reduce SO2 levels by approximately 99.63%. The caustic scrubber of this application uses a scrubber solution that may contain both NaOH and H2O2. Tests have shown that a solution containing both NaOH and H2O2 and maintained at a pH above approximately 5.0 and below approximately 5.5 results in a 99.99% reduction in SO2 in flue gas containing approximately 20 ppm SO2. Flow rate, temperature, pressure, and SO2 removal rate are performance targets for the caustic scrubber according to the example embodiment are shown in Table 3 below. In some embodiments, different target concentrations may be desired.

[0027] Table 3: Performance Requirements for Harsh Washers

[0028] Figure 2A caustic scrubber system 99 according to an exemplary embodiment is shown. A caustic solution 101 can be pumped to the bottom of a caustic scrubber tower 102 (e.g., a sump of the caustic scrubber tower 102). The caustic solution may contain NaOH. The caustic solution can be combined with hydrogen peroxide (H2O2) from a hydrogen peroxide supply source 114 (e.g., a storage tank) and / or water from a water supply source 110 (e.g., a storage tank) to form a scrubber solution. The caustic scrubber tower 102 may contain a packed bed of material through which the flue gas feed stream 105 passes. A scrubber solution pump 103 can pump the scrubber solution to the top of the caustic scrubber tower 102, where the scrubber solution can be sprayed onto the packed bed. The scrubber solution can drip down through the packed bed back to the bottom of the caustic scrubber tower 102, where it can be recirculated back to the top of the tower 102 by the pump 103. A portion of the scrubber solution can be discharged as waste scrubber solution 104 from the waste scrubber solution outlet at the bottom of column 102. This cycle can be operated continuously, with fresh scrubber solution components introduced into column 102 while approximately an equal amount of waste scrubber solution 104 is discharged from column 102. Waste scrubber solution 104 can be discharged at a rate of approximately 0.5 to 1.0 gallons per minute.

[0029] As the scrubber solution 107 circulates through column 102, flue gas stream 105 can be introduced into the column near the bottom of column 102. Flue gas stream 105 can travel upwards through the packed bed of material in column 102 and react with the scrubber solution 107. Flue gas stream 105 may contain SO2. The average concentration of SO2 in flue gas stream 105 may be approximately 10 ppm or higher, or approximately 20 ppm or higher. The concentration of SO2 in flue gas stream 105 can reach levels as high as 78 ppm.

[0030] SO2 in flue gas stream 105 can react with NaOH and H2O2 in scrubber solution 107 to form sulfides that can be retained in scrubber solution 107, while the scrubbed flue gas stream 106 is discharged from tower 102 near the top. The scrubbed flue gas stream 106 discharged from tower 102 can have a substantially lower SO2 concentration than the flue gas stream 105 after reacting with scrubber solution 107 in tower 102. The packed bed material can increase the contact area between scrubber solution 107 and flue gas stream 105, thereby increasing the amount of SO2 reacting with scrubber solution 107.

[0031] Experimental data show that a scrubber solution containing NaOH can remove approximately 99.63% of SO2 from flue gas stream 105. On the other hand, a scrubber solution containing both NaOH and H2O2 can remove approximately 99.99% of SO2 from flue gas stream 105. H2O2 can convert SO2 into sulfate ions (SO42-). 2- The sulfate ions can then react with NaOH in the scrubber solution 107 to form sulfate. When the scrubber solution 107 is maintained at a pH of approximately 5, the estimated concentrations of the ions in the waste scrubber solution 104 at the time of discharge from the example caustic scrubber 100 are shown in Table 4 below. It should be noted that the values ​​in Table 4 are related to experimental test settings. In some embodiments, these concentrations may vary.

[0032] Table 4: Estimated purge concentration for caustic scrubbers

[0033] The scrubber solution may have a pH higher than about 4.5 and lower than about 5.5 (or higher than about 5.0 and lower than about 5.5) to maximize the removal of SO2 from the flue gas stream 105. The scrubber solution may become more acidic as NaOH reacts with SO2 to form salts, causing a pH drop. The caustic scrubber system 99 may include a pH sensor 117 for measuring the pH of the scrubber solution 107 and a controller 119 configured to adjust the flow rate of the caustic solution 101 input to the column 102. When the pH of the scrubber solution 107 drops below a predetermined level (such as 5.0), the controller 119 may, for example, increase the amount of caustic solution 101 input to the column 102 by controlling a valve or pump associated with the caustic solution supply source. Demineralized water from main supply source 120 can be added to scrubber solution 107 to replace water discharged from waste scrubber solution 104 in tower 102, thereby maintaining a substantially constant volume of scrubber solution 107 in tower 102. Controller 119 may include at least one processor and at least one memory device. The at least one memory device may store instructions that, when executed by one or more processors, cause controller 119 to perform the functions described herein. Controller 119 may be communicatively coupled to various valve controllers, actuators, processors, and other components of system 10 and configured to transmit control instructions to these components. Controller 119 may also be communicatively coupled to various sensors and other components of system 10 (including a pH sensor, an ORP sensor 112 (discussed below), and / or a temperature sensor 113 (discussed below)) and configured to receive information from these sensors and other components.

[0034] The amount of H2O2 to be mixed into scrubber solution 107 can be determined by the amount of SO2 in flue gas stream 105. When the SO2 level in flue gas stream 105 is high, a higher volume of H2O2 can be added to solution 107. Additionally, extra H2O2 can be introduced into scrubber solution 107 to replace any H2O2 that has already reacted with SO2. Therefore, a sensor can be used to determine whether the level of H2O2 in solution 107 is sufficient to remove the desired amount of SO2. In some embodiments, the redox potential (ORP) of waste scrubber solution 104 can be used to determine whether the level of H2O2 in scrubber solution 107 is sufficient to remove the desired amount of SO2 from flue gas stream 105. However, tests have shown that above a certain saturation point, the ORP of waste scrubber solution 104 may not increase, even with the addition of more H2O2 to solution 107, thus limiting the ability to use ORP to determine whether the desired amount of SO2 has been removed. Under the test settings, the ORP of the solution did not increase above approximately 300 mV upon the addition of additional H2O2. Since the SO2 concentration in the flue gas stream 105 may vary over time, a sensor that responds to these changes may be desirable.

[0035] Further reference Figure 2According to an exemplary embodiment, the caustic scrubber system 99 may include an ORP measurement system 111 for measuring the level of unreacted H2O2 in the waste scrubber solution 104. The waste scrubber solution 104 discharged from tower 102 may be directed to an ORP mixing container 108. A reducing agent 109 may also be directed to the mixing container 108. The waste scrubber solution 104 and the reducing agent 109 may be added to the container 108 in a continuous stream to maintain a uniform ratio. The reducing agent 109 may be sodium metabisulfite, sodium sulfite, and / or sodium bisulfite, or any other reducing agent capable of neutralizing H2O2. In the ORP mixing container 108, the reducing agent 109 may be mixed with the waste scrubber solution 104 and may react with and neutralize a portion of the H2O2 in the waste scrubber solution 104. In some embodiments, the flow rate of the reducing agent 109 may be approximately equal to the flow rate of the waste scrubber solution 104 entering the ORP mixing container 108. Container 108 may include an ORP sensor 112 to measure the ORP of the mixed solution. The ORP sensor 112 may be communicatively coupled to a controller 119. If the ORP in the mixing container 108 remains high, the level of H2O2 in the scrubber solution 107 in tower 102 may be sufficient to remove SO2 from the flue gas feed stream 105, even after some of the H2O2 has been neutralized by the reducing agent. If the reducing agent causes the ORP in the mixing container 108 to drop below a predetermined minimum level, the controller 119 may, for example, introduce additional H2O2 into the scrubber solution 107 by controlling a valve or pump associated with the hydrogen peroxide supply source 114. The ORP mixing container 108 may be a sealed container to prevent the reducing agent 109 from reacting with atmospheric oxygen. For example, instructions stored in a memory device of the controller 119 may include an upper ORP limit and a lower ORP limit. The controller 119 may periodically or continuously receive ORP readings from the ORP sensor 112. When the ORP reading indicates that the ORP in the mixing container 108 exceeds the upper limit of ORP, the controller can cause the system 99 to reduce the rate at which H2O2 is added to the scrubber solution 107. When the ORP reading indicates that the ORP in the mixing container 108 is below the lower limit of ORP, the controller 119 can cause the system 99 to increase the rate at which H2O2 is added to the scrubber solution 107.

[0036] Tower 102 may include a temperature sensor 113 to measure the temperature of the scrubber solution 107. The temperature sensor 113 may be communicatively coupled to a controller 119. If the temperature rises above a predetermined limit, the controller 119 may, for example, introduce additional demineralized water into the solution 107 by opening a valve between the water supply source 110 and tower 102. The flow rate of the waste scrubber solution 104 may be increased to accommodate the additional volume of scrubber solution 107 in tower 102.

[0037] The inputs of caustic solution 101, H2O2 and water are not limited to... Figure 2 The arrangement is shown. The scrubber solution components can be added to the tower or to the pump recirculation stream after any discharge point (e.g., as shown). Figure 2 (shown by dashed lines) to form a scrubber solution 107, which is applied to the top of column 102 and subsequently collected in a collection tank (e.g., the bottom of column 102). For example, caustic solution 101, H2O2, and water may all be introduced near the bottom of column 102 or may be mixed before being introduced into column 102. Waste scrubber solution 104 may be drawn from the collection tank or discharged after the recirculation pump before any input streams 101, 120, 114 (e.g., as shown by dashed lines). Figure 2 (As shown by the dashed line in the diagram). The scrubbed flue gas stream 106 discharged from the top of the caustic scrubber tower 102 can be directed to the primary blower 150 and the bag filter chamber 200 to achieve particulate removal.

[0038] Figure 3 A method 400 is shown to control the amount of H2O2 added to a scrubber solution (e.g., scrubber solution 107 in caustic scrubber 100). In operation 401 of method 400, a scrubber solution containing a caustic solution and H2O2 is applied to a flue gas stream containing SO2. The caustic solution, which may contain NaOH, can form a salt with SO2 to remove SO2 from the flue gas stream. In operation 402 of method 400, a sample of the waste scrubber solution is combined with a reducing agent to form a test sample. The waste scrubber solution and the reducing agent can be combined and mixed in a mixing container. The waste scrubber solution may contain a scrubber solution and a salt produced by the reaction of the scrubber solution with SO2 in the flue gas stream. The reducing agent may be sodium metabisulfite, sodium sulfite, and / or sodium bisulfite, or any other reducing agent capable of neutralizing H2O2. In operation 403 of method 400, the ORP of the test sample is measured (e.g., using an ORP sensor 112). A decrease in ORP can indicate an increase in SO2 in flue gas.

[0039] In operation 404 of method 400, additional H2O2 is added to the scrubber solution in response to determining that the ORP of the test sample has decreased to a predetermined minimum level. In some embodiments, the flow rate of H2O2 into the scrubber solution may be increased in response to determining that the ORP of the test sample has decreased below a predetermined level. The method steps can be repeated continuously to allow for continuous monitoring of the redox potential. This allows for the rapid addition of H2O2 when the redox potential measurement has decreased below a predetermined level, indicating an increase in the SO2 level in the flue gas entering the caustic scrubber. The predetermined minimum level of the redox potential can be between approximately 200 mV and approximately 300 mV. Within this range, detection accuracy can be maximized to ensure that the ORP reading accurately reflects the SO2 level in the flue gas entering the caustic scrubber.

[0040] CO in caustic scrubbers 2 absorb The embodiments disclosed herein can reduce or prevent CO2 absorption in caustic scrubbers, thereby allowing downstream CO2 capture. Flue gas from fossil fuel sources may contain approximately 8% CO2 in typical natural gas-based sources and up to 14% CO2 in typical coal-based sources. Maintaining a total acidic pH in the solution when the amount of CO2 in the gas stream is relatively high can prevent or reduce significant CO2 absorption in the scrubber solution. Any CO2 absorbed in the caustic scrubber solution may be lost due to downstream recovery and increase the consumption of scrubber feed chemicals. However, acidic solutions may also inhibit complete SO2 absorption. By employing H2O2, SO2 can be converted to sulfate ions (SO42-). 2- This maximizes SO2 capture in acidic environments while minimizing CO2 absorption.

[0041] Tests show that significant carbon dioxide removal does not occur if the caustic scrubber has a minimum liquid purging rate at a slightly acidic (5 to 6) pH relative to the mass flow rate of CO2 in the flue gas. The purging rate from the caustic scrubber is typically driven by one of several factors: the water balance in the scrubber solution 107, which is affected by condensation of moisture from the inlet flue gas due to temperature changes; the chloride concentration in the scrubber solution 107, a high concentration of which may lead to corrosion of the caustic scrubber's construction materials; and the concentration of soluble ions (such as magnesium and sulfate ions) in the scrubber solution 107.

[0042] Since the relatively minimum mass of SO2 is converted to sulfate in scrubber 100, accompanied by minimal chloride accumulation, the necessary purge flow rate can be relatively low. Peroxides do not alter the oxidation state of carbon. Therefore, CO2 forms an equilibrium distribution based on gas concentration and scrubber solution pH. Ionic equilibrium includes carbonate, bicarbonate, and carbonate ions. At a slightly acidic pH, the carbonate fraction in scrubber solution 107 is in equilibrium with the gas phase concentration. In the absence of other removal mechanisms (i.e., calcium carbonate sedimentation), CO2 removal stagnates. According to various exemplary embodiments, the mass removal rate of CO2 can be equal to the purge flow rate multiplied by the carbonate concentration, and can be relatively low in caustic scrubber system 99.

[0043] Cruel Washer Test Breakthrough testing was conducted on a small-scale caustic washer using inlet SO2 concentrations in the range of approximately 20 ppm to 100 ppm and peroxide concentrations in the range of approximately 0.02 wt% to 0.07 wt%. Figure 6 This is a graph of a small-scale caustic scrubber used for testing. A breakthrough is defined as using only NaOH to consume excess peroxide and returning to baseline SO2 removal. Returning to baseline SO2 removal indicates that additional H2O2 is required to increase SO2 absorption. The results indicate a 1:1 molar correlation between SO2 removal and H2O2 consumption.

[0044] Typically, SO2 removal is driven by liquid-phase alkalinity, with higher pH enhancing SO2 removal efficiency. During testing, it was observed that, in the presence of peroxides, SO2 removal efficiency was driven by pH concentration, and the SO2 removal efficiency was no longer correlated with changes in pH (i.e., liquid-phase alkalinity). This is a significant process advantage, as operating at lower pH virtually eliminates CO2 uptake.

[0045] The potential impact of NOx in flue gas on SO2 removal efficiency was also investigated. Data from one site indicated that the inlet flue gas might contain 150 ppm NOx. Small-scale tests were conducted on a caustic scrubber using excess peroxide, 20 ppm inlet SO2, and 150 ppm inlet NOx to determine whether the presence of NOx would interfere with SO2 removal kinetics. It was found that 150 ppm NOx did indeed interfere with fluorescence SO2 analyzer measurements. Using an alternative measurement technique (tube pulling), it was determined that SO2 removal performance was not impeded by the presence of NOx.

[0046] The impact of NOx on peroxide consumption was not assessed. However, it should be noted that when peroxides are used to oxidize NO, this is done at much higher temperatures to evaporate and dissociate the peroxides into hydroxyl radicals, which oxidize NO and NO2 to NO2, HNO2, and HNO3, which are more soluble in wet FGD processes. Therefore, the consumption of peroxides due to the presence of NOx in the target-design scrubber is expected to be insignificant. Furthermore, if the refined flue gas is used in a fuel cell, the fuel cell can convert approximately 70% of the NOx emitted from the scrubber into N2, so NOx will not have an adverse effect on the fuel cell.

[0047] To determine the effectiveness of the scrubber chemicals against other acidic gases, HCl removal was also evaluated using a pilot-scale caustic scrubber with an inlet HCl concentration of 40 ppm. Outlet concentrations were measured using a pull tube. Under these load conditions, no HCl was detected at the outlet (i.e., concentration <50 ppb HCl). Since HCl readily dissociates into chloride ions in water, maintaining the solution pH above strongly acidic levels (i.e., >0.5) can be expected to eliminate any vapor pressure that might inhibit the complete absorption of acidic gases.

[0048] For use in fuel cells, a selenium level below 10 ppb can be targeted. The median selenium concentration in flue gas from biomass power plants was found to be approximately 0.6 ppb, well below the acceptable limit where no selenium removal is necessary. Nevertheless, the amount of selenium removed by a caustic scrubber was also tested. Experiments showed that at least 90% of the selenium in the flue gas was removed using varying levels of NaOH and H₂O₂ in the scrubber solution, including tests using only demineralized water. In most cases, most of the selenium accumulated on the glass tube that fed the gas into the scrubber solution and was removed by rinsing the tube. This indicates that most of the selenium condenses from the flue gas feed stream even before reaching the caustic scrubber. Any selenium remaining after the flue gas passes through the caustic scrubber can be significantly removed from the flue gas in the demister 300.

[0049] bag filter chamber Figure 4 A primary blower and bag filter chamber for PM removal are shown. Flue gas discharged from a power plant may contain more than 85,000 micrograms per cubic meter of PM, which may be too high for effective removal by a caustic scrubber. To address this issue, a bag filter chamber can be used. After the scrubbed flue gas stream 106 is discharged from the caustic scrubber, it can be directed to a primary blower 150, which pressurizes the flue gas 106 and directs it into the inlet 201 of the bag filter chamber 200. The temperature of the flue gas increases due to the heat of compression.

[0050] Flue gas in bag filter chamber 200 can be directed upwards into one or more fabric filter socks 202. Filter socks 202 can collect PM from flue gas 106, thereby reducing the amount of PM in flue gas 106 by up to 99.9% (e.g., to approximately 85 micrograms per cubic meter). Because the washed flue gas 106 leaving the caustic scrubber 100 is saturated with scrubber solution 107, wet agglomerates of particles are formed, which can be more easily trapped on the socks 202 and inside the duct and bag filter chamber walls. Preheating the flue gas 106 to above its saturation temperature (dew point) before it enters bag filter chamber 200 reduces or eliminates the possibility of filter fabric adhesion and clogging. Compressed air can be used to periodically flush the filter socks 202 with air pulses to agitate and bend the socks 202, causing accumulated PM to be removed from the fabric and fall off. PM solids can fall to the base of the bag filter chamber 200, where they can accumulate in the container 203 for final disposal (e.g., to an off-site facility). The scrubbed flue gas 106 can pass through the filter stock 202 and exit the bag filter chamber 200 as filtered flue gas 206 through the bag filter chamber outlet 205. The filtered flue gas 206 exiting the bag filter chamber may be significantly free of SO2 and PM. The filtered flue gas 206 can then be directed to the demister 300. In some embodiments, the bag filter chamber can receive the flue gas stream 105 from the flue gas source before the flue gas stream is directed to the caustic scrubber system 99. For example, if the received flue gas stream 105 is sufficiently hot (e.g., above saturation temperature), the heat of compression from the blower 150 may not be required. If the flue gas is above the saturation temperature when it is received by the bag filter chamber 200, so that the compression heat of the blower 150 is not required, the blower 150 can be moved to another location in the system 10, such as in the filtered flue gas stream 14 before the demister 300 or in the fined flue gas stream 16 after the demister 300.

[0051] When the system is started, the flue gas 106 can be repeatedly recirculated through the bag filter chamber 200 and the blower 150 until the flue gas 106 reaches the desired process operating temperature due to the heat of compression from the blower 150. In the absence of the heat of compression from the blower, a heat source or heat exchanger must be added to the system. Adding heating equipment reduces process efficiency, increases pressure drop, increases costs, and expands the system's footprint.

[0052] The performance requirements and specifications for the bag filter chamber according to the example embodiments are shown in Tables 5 and 6 below. In other embodiments, these target concentrations may vary.

[0053] Table 5: Performance Requirements of Bag Filter Chambers

[0054] Table 6: Bag Filter Chamber Specifications

[0055] Demister Figure 5 A demister 300 for reducing SO3 aerosols and residual PM is shown. Filtered flue gas 206 exiting the bag filter chamber outlet 205 can be directed to the demister inlet 301 of the demister 300. The filtered flue gas 206 can travel upward through the demister 300, which may include filter elements 302 (e.g., helically wound fine filter elements, demister pads, etc.). The filter elements 302 contain fine collecting fibers 303 that can accumulate SO3 and residual PM as the flue gas flows through them. Liquid collected in the pad can be drawn out to the bottom of the demister by suction and re-entrainment control fibers 304.

[0056] Filter element 302 can be periodically sprayed with air and water to remove any collected SO3 and PM. For example, the surface of filter element 302 can be periodically (e.g., once a day) sprayed for a short period of time (e.g., about 20 minutes) at a specific washing rate (e.g., 20 gallons per hour). SO3 can mix with water in the spray and react to form liquid sulfuric acid. The liquid can accumulate at the bottom of demister 300 until it can be pumped out. In some embodiments, collected SO3 and PM are removed by methods other than spraying water, such as by spraying pulsed air. The filtered flue gas 206 can then exit demister 300 as refined flue gas 306 via demister outlet 305, at which the filtered flue gas can be directed to a fuel cell stack or used for other purposes. In some embodiments, CO2 can be captured from the refined flue gas 306 for storage or for other industrial uses. For example, a molten carbonate fuel cell can be used to separate CO2 from the oxygen, nitrogen, and other components of the refined flue gas 306. The refined flue gas 306 can be supplied to the cathode of a molten carbonate fuel cell. The cathode converts carbon dioxide in the refined flue gas 306 into carbonate ions, which cross the electrolyte to reach the anode, where they are converted back into carbon dioxide. Carbon dioxide on the anode side can be captured, while other gases in the refined flue gas 306 can pass through the cathode without crossing the electrolyte.

[0057] According to an exemplary embodiment, the demister 300 can remove 99.9% of SO3 from the filtered flue gas 206, thereby reducing the concentration in the refined flue gas 306 to approximately 0.002 ppm. Removing SO2 and PM through the caustic scrubber 100 and bag filter chamber 200 improves the efficiency of SO3 removal by the demister 300 because less additional contaminants may accumulate on the filter element 302.

[0058] The demister 300 can also remove most of the remaining PM from the filtered flue gas 206. The finely treated flue gas 306 can, for example, have a PM concentration of about 5 to 25 micrograms per cubic meter, which is more than 99.9% lower than the flue gas stream 105 output from the power plant.

[0059] The liquid pumped from the demister 300 can then be directed via the extractor 307 to the effluent holding tank 115. The pumped acidic liquid can be combined in the effluent holding tank 115 with higher pH liquid waste from elsewhere in the finishing system 10. The contents of the effluent holding tank 115 can be neutralized with a high pH liquid (such as a NaOH solution). The contents of the effluent holding tank 115 can then be disposed of.

[0060] The performance requirements and specifications of the demister according to the example embodiments are shown in Tables 7 and 8 below. In other embodiments, these specifications and target concentrations may vary.

[0061] Table 7: Demister Performance Requirements

[0062] Table 8: Demister Specifications

[0063] Water usage The combined water consumption of the finishing system 10, including the caustic scrubber 100, bag filter 200, and demister 300, can be in the range of approximately 0.5 to 0.6 gallons per minute to treat 12,000 scfm of flue gas 105 from a power plant. This water consumption is significantly lower than that of conventional flue gas finishing solutions. For example, a wet electrostatic precipitator used in place of a bag filter may require a flow rate exceeding 30 gpm. A Venturi scrubber used in place of a caustic scrubber system 99 to achieve a comparable flue gas flow rate can use a flow rate of approximately 4 to 5 gpm.

[0064] This document discloses various embodiments of systems and methods for refining power plant flue gas for use in fuel cells. The various embodiments described herein can reduce the amount of PM, SO2, and SO3 contaminants reaching the fuel cell, thereby resulting in higher fuel cell efficiency and lifespan.

[0065] As used herein, the terms “about,” “approximately,” “substantially,” and similar terms are intended to have a broad meaning consistent with common and accepted usage by one of ordinary skill in the art to which the subject matter of this disclosure pertains. Those skilled in the art who have examined this disclosure will understand that these terms are intended to allow for description of certain features described and claimed, without limiting the scope of those features to the precise numerical ranges provided. Therefore, these terms should be interpreted as indicating that non-substantial or insignificant modifications or alterations to the described and claimed subject matter are considered to fall within the scope of the invention as set forth in the appended claims.

[0066] As used herein, the terms “coupled,” “connected,” etc., mean that two components are joined together directly or indirectly. Such a connection can be fixed (e.g., permanent) or movable (e.g., removable or releasable). This connection can be achieved by the integral formation of two components or two components and any additional intermediate components into a single whole, or by the attachment of two components or two components and any additional intermediate components to each other.

[0067] References to the position of elements (e.g., "top", "bottom", "above", "below", etc.) herein are used only to describe the orientation of the various elements in the accompanying drawings. It should be noted that the orientation of the various elements may differ according to other exemplary embodiments, and such variations are intended to be covered by this disclosure.

[0068] It is important to note that the construction and arrangement of the various exemplary embodiments are merely illustrative. While only a few embodiments have been described in detail in this disclosure, those skilled in the art to which this disclosure pertains will readily understand that many modifications (e.g., variations in the size, dimensions, structure, shape, and proportions of various elements, parameter values, installation arrangements, material use, color, orientation, etc.) can be made without substantially departing from the novel teachings and advantages of the subject matter described herein. For example, an element shown as integrally formed may be composed of multiple parts or elements, the positions of elements may be reversed or otherwise varied, and the nature or number of discrete elements or positions may be altered or changed. The order or sequence of any process or method steps may be varied or reordered according to alternative embodiments. Other substitutions, modifications, alterations, and omissions may also be made in terms of the design, operating conditions, and arrangement of the various exemplary embodiments without departing from the scope of the invention. For example, the heat recovery heat exchanger may be further optimized.

[0069] Hardware and data processing components (e.g., controllers) for implementing the various processes, operations, illustrative logic, logic blocks, modules, and circuits described in conjunction with the embodiments disclosed herein may be implemented or performed using a general-purpose single-chip or multi-chip processor, digital signal processor (DSP), application-specific integrated circuit (ASIC), field-programmable gate array (FPGA), or other programmable logic device, discrete gate or transistor logic, discrete hardware components, or any combination thereof. A general-purpose processor may be a microprocessor or any conventional processor or state machine. Processors may also be implemented as a combination of computing devices, such as a combination of a DSP and a microprocessor, multiple microprocessors, one or more microprocessors combined with a DSP core, or any other such configuration. In some embodiments, one or more processors may be shared by multiple circuits (e.g., a controller may include or otherwise share the same processor, which in some example embodiments may execute instructions stored or otherwise accessed via different memory regions). Alternatively or additionally, one or more processors may be configured to perform or otherwise execute certain operations independently of one or more coprocessors. In other exemplary embodiments, two or more processors may be coupled via a bus to enable independent, parallel, pipelined, or multithreaded instruction execution. All such variations are intended to fall within the scope of this disclosure.

[0070] Memory devices (e.g., memory, memory cells, storage devices) may include one or more means (e.g., RAM, ROM, flash memory, hard disk storage devices) for storing data and / or computer code to perform or facilitate the various processes, layers, and modules described herein. Memory devices may be communicatively connected to a processor to provide the processor with computer code or instructions to perform at least some of the processes described herein. Furthermore, memory devices may be or include tangible non-transitory volatile memory or non-volatile memory. Therefore, memory devices may include database components, object code components, script components, or any other type of information structure to support the various activities and information structures described herein.

Claims

1. A caustic scrubber for removing SO2 from flue gas for use in a fuel cell assembly, the caustic scrubber comprising: A caustic scrubber tower, comprising a material-filled bed; The flue gas inlet is configured to guide the flue gas to the caustic scrubber tower; A scrubber solution pump configured to pump a scrubber solution containing NaOH and H2O2 into the caustic scrubber tower; as well as Waste scrubber solution outlet, configured to discharge waste scrubber solution containing sulfur salts formed by the reaction between the scrubber solution and SO2 in the flue gas.

2. The caustic scrubber of claim 1, further comprising a scrubber solution recirculation line configured to direct a portion of the scrubber solution from the caustic scrubber tower to the scrubber solution pump.

3. The caustic scrubber of claim 1, wherein the waste scrubber solution outlet is configured to discharge the scrubber solution from the caustic scrubber tower at a draw rate of about 0.5 gallons per minute to about 1.0 gallons per minute, the caustic scrubber further comprising a controller configured to control the scrubber solution pump to supply fresh scrubber solution to the caustic scrubber tower at a rate approximately equal to the draw rate.

4. The caustic washer according to claim 1, further comprising a controller configured to control the amount of H2O2 and NaOH added to the washer solution.

5. The caustic washer of claim 4, further comprising a pH sensor configured to monitor the pH of the washer solution, wherein the controller is configured to control the feed rate of NaOH added to the washer solution based on the measured pH of the washer solution to maintain the pH between about 5.0 and about 5.

5.

6. The caustic scrubber of claim 5, further comprising a mixing container configured to mix a sample of the waste scrubber solution with a reducing agent to form a test sample, and an oxidation-reduction potential sensor configured to monitor the oxidation-reduction potential of the test sample.

7. The caustic washer of claim 6, wherein the controller is configured to control the amount of H2O2 added to the washer solution to maintain the redox potential of the test sample above about 200 mV.

8. The caustic scrubber of claim 3, further comprising a mixing container configured to mix a sample of the waste scrubber solution with a reducing agent to form a test sample, and a redox potential sensor configured to monitor the redox potential of the test sample.

9. The caustic washer of claim 8, wherein the controller is configured to control the amount of H2O2 added to the washer solution to maintain the redox potential of the test sample above about 200 mV.

10. The caustic washer of claim 8, wherein the controller is configured to control the amount of H2O2 added to the washer solution to maintain the redox potential of the waste washer solution mixed with the reducing agent above about 300 mV.

11. A method for controlling the amount of H2O2 added to a caustic scrubber solution, the method comprising: A scrubber solution containing caustic solution and H2O2 is applied to flue gas containing SO2; A sample of the waste detergent solution output from the outlet of the caustic scrubber is combined with a reducing agent to form a test sample; Measure the redox potential of the test sample; as well as In response to determining that the redox potential of the test sample has dropped below a predetermined minimum level, additional H2O2 is added to the scrubber solution via the inlet of the caustic scrubber.

12. The method of claim 11, wherein the reducing agent comprises one or more materials selected from the group consisting of sodium metabisulfite, sodium sulfite, and sodium bisulfite.

13. The method of claim 11, wherein the predetermined minimum level of the redox potential is about 200 mV.

14. The method of claim 13, wherein the predetermined minimum level of the redox potential is about 300 mV.

15. A system for finely treating flue gas from a power plant, the system comprising: A caustic scrubber configured to remove SO2 from the flue gas; A bag filter chamber configured to remove particulate matter from the flue gas; as well as A demister is configured to remove SO3 from the flue gas.

16. The system of claim 15, further comprising a primary blower configured to heat the flue gas by compression heat.

17. The system of claim 16, wherein the primary blower is configured to heat the flue gas to a temperature above the dew point of the flue gas before the flue gas is received by the bag filter chamber.

18. The system of claim 15, wherein the caustic scrubber is configured to receive the flue gas from the power plant, the bag filter is configured to receive the flue gas from the caustic scrubber, and the demister is configured to receive the flue gas from the bag filter.

19. The system of claim 15, wherein the caustic scrubber comprises a scrubber solution containing NaOH and H2O2.

20. The system of claim 19, further comprising a controller configured to add additional H2O2 to the scrubber solution via the inlet of the caustic scrubber in response to determining that the redox potential of a sample of the waste scrubber solution mixed with the reducing agent has dropped below a predetermined minimum level.

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