Patent Application
20170354926
This disclosure generally relates to an integrated desulfurization and carbon dioxide capture system. In particular, this disclosure generally relates to an integrated desulfurization and carbon dioxide capture for flue gases.
Power generation systems (e.g., coal-fired and oil fired power plants) generally combust hydrocarbon based fuels in order to generate energy. Such systems generally produce an end product that comprises primarily carbon dioxide and water (e.g., steam) as by-products of the energy generation process. In most cases, the end products will also include varying amounts of nitrogen, oxygen, sulfur dioxide and other compounds.
Environmental pollution stemming from fossil-fueled power plants is of worldwide concern. Power plants emit air pollutants that may be toxic, e.g., toxic metals and polyaromatic hydrocarbons; precursors to acid rain, e.g., sulfur oxides (SOx) such as sulfur dioxide (SO2), and nitrogen oxides (NOx); precursors to ozone such as NO2 and reactive organic gases; particulate matter; and greenhouse gases, notably carbon dioxide (CO2). Power plants also discharge potentially harmful effluents into surface and ground water, and generate considerable amounts of solid wastes, some of which may be hazardous.
Generally, removal of contaminants involves equipment and processes to remove sulfur-type pollutants (e.g., flue gas desulfurization) and then separate equipment and processes are used to remove and capture the carbon dioxide-type pollutants.
Carbon dioxide capture systems include pre-combustion (e.g., oxy-combustion) or post-combustion systems (e.g., chilled ammonia process (CAP) and advanced amines process (AAP)). The post combustion carbon dioxide capture processes are detailed here.
Post-combustion carbon dioxide capture can be applied to various types of power plants such as coal, gas and biomass fired ones, as well as a vast range of industrial processes emitting carbon dioxide. Post combustion carbon dioxide capture technology generally includes a chemical absorption process. The following discussion includes the chilled ammonia process.
Sulfur dioxide (SO2) is an acid gas, and, therefore, the typical sorbent slurries or other materials used to remove the SO2 from the flue gases are alkaline. Sulfur dioxide capture systems include the use of flue gas desulfurization units. Flue gas desulfurization systems include either wet flue gas desulfurization system (Wet FGD) or dry flue gas desulfurization systems (Dry FGD). In wet FGD, flue gas is reacted with a reagent under saturated conditions. In dry FGD the flue gas is reacted with a reagent at a temperature 30-50 degrees F. above adiabatic saturation.
The reaction taking place in wet scrubbing using a CaCO3 (limestone) slurry produces CaSO3 (calcium sulfite) and can be expressed as:
CaCO3 (solid)+SO2 (gas)→CaSO3 (solid)+CO2 (gas)
When wet scrubbing with a Ca(OH)2 (lime) slurry, the reaction also produces CaSO3 (calcium sulfite) and can be expressed as:
Ca(OH)2 (solid)+SO2 (gas)→CaSO3 (solid)+H2O (liquid)
When wet scrubbing with a Mg(OH)2 (magnesium hydroxide) slurry, the reaction produces MgSO3 (magnesium sulfite) and can be expressed as:
Mg(OH)2 (solid)+SO2 (gas)→MgSO3 (solid)+H2O (liquid)
To partially offset the cost of the flue gas desulfurization installation, in some designs, the CaSO3 (calcium sulfite) is further oxidized to produce marketable CaSO4.2H2O (gypsum). This technique is also known as forced oxidation:
CaSO3 (solid)+H2O (liquid)+½O2 (gas)→CaSO4 (solid)+H2O
Other systems used for capturing SOx use sodium carbonate. Sodium based desulfurization systems are more efficient than the lime or limestone based systems. As seen above, lime is a calcium-containing inorganic material in which carbonates, oxides and hydroxides predominate and may be used in lieu of sodium carbonate. Wet lime or limestone based processes also represent a popular way to capture CO2, SOx, and other acidic gases.
The capital cost of a sodium based system is significantly lower than the lime/limestone based system. However, the cost of the sodium based reagents are much higher than the lime or limestone reagents and hence sodium based desulfurization system has found less attention than its counterpart lime/limestone based desulfurization processes.
The use of separate desulfurization systems and carbon dioxide capture systems in a combustion facility is expensive and adds to maintenance costs. It is therefore desirable to reduce costs and improve efficiencies for both the desulfurization process and the carbon capture processes such as chilled ammonia process.
With this integration of the two systems, sodium reagents are used for the utilization for SOx re-capture and recycle of ammonia for CO2 capture and also, sulfuric acid for ammonia capture. This significantly reduces the operating cost of the process.
Disclosed herein is an integrated system for capturing carbon dioxide and sulfur oxides from a flue gas stream comprising a desulfurization chamber comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal; where the metal oxide, the metal hydroxide, the metal carbonate salt and/or the metal bicarbonate salt is used to absorb sulfur oxides from the flue gas stream to form a metal sulfate; and a carbon capture system in fluid communication with the desulfurization chamber; where the carbon capture system is operative to absorb carbon dioxide from the flue gas stream.
Disclosed herein too is a method comprising charging a flue gas stream produced in a combustion process to an integrated system for capturing carbon dioxide and sulfur oxides from the flue gas stream; where the integrated system comprises a desulfurization chamber comprising at least one of a metal oxide, a metal hydroxide, a metal carbonate salt and/or a metal bicarbonate salt; where a metal in the metal salt is either an alkali metal or an alkaline earth metal; and a carbon capture system in fluid communication with the desulfurization chamber;
Disclosed herein is a system and a method for facilitating the integration of a desulfurization process based on a sodium reagent with the chilled ammonia process. The method comprises discharging a flue gas from a combustion process (such as from a coal combustion furnace) to a desulfurization chamber where sulfur oxides (SOx) is removed in the form of a sulfate salt. The flue gases now devoid of the sulfur oxides (or with a reduced sulfur oxide content as compared with the incoming flue gas stream) are then discharged to a carbon capture system where the carbon dioxide present in the flue gas stream is removed in the form of a carbonate salt and/or a bicarbonate salt. The carbonate salt and/or the bicarbonate salt is then decomposed to release carbon dioxide. The carbon dioxide is eventually sequestered while the flue gas now devoid of carbon dioxide and sulfur oxides (SOx) is released to the atmosphere via a stack.
The system 10 comprises a direct contact cooling vessel (DCC) 4, a direct contact heating vessel (DCH) 6, a water wash station 8, an absorber 12 and a regenerator 14. A flue gas stream containing carbon dioxide that emanates from a combustion process (e.g., a boiler) is charged to a direct contact cooling vessel 4 prior to being charged to the absorber 12.
The direct contact cooling vessel 4 reduces temperature of the incoming flue gas stream and removes residual acidic gases such as SOx and particulate matter. The flue gas stream is then charged to the absorber 12 where carbon dioxide is removed using an absorbent solution (also referred to herein as an ammoniated solution or an ammoniated slurry). The absorption of the acidic components such as carbon dioxide present in the flue gas stream is achieved when the absorber 12 is operated at a low temperature, for example, between zero and thirty degrees Celsius (0 to 30° C.). In another example, absorption of the acidic component from flue gas stream is achieved when the absorber is operated at a temperature between zero and ten degrees Celsius (0 to 10° C.). By operating at relatively low temperatures, ammonia loss within the system 10 is minimized.
By way of example in the absorber 12, the ammonia reacts with the carbon dioxide present in the flue gas to form ammonium carbonate, ammonium bicarbonate, ammonium carbamate (also referred to as a carbon dioxide rich ammonia solution). The carbon dioxide rich ammonia solution is charged to the regenerator 14 where it is heated to release the carbon dioxide thereby resulting in a carbon dioxide lean ammonia solution.
The carbon dioxide is subsequently cleaned and sequestered or stored for further utilization. The carbon dioxide lean ammonia solution is recycled back to the absorber 12, where it recaptures additional carbon dioxide in a sequential portion of the flue gas stream.
In one method of functioning of the chilled ammonia process, the flue gas stream from a boiler enters the direct contact cooling vessel 4 to have its temperature reduced and to have residual acidic gases removed from it. The direct contact cooling vessel 4 uses ambient air or cooling water to lower the recirculation liquid temperature. Flue gas enters the direct contact cooling vessel 4 inlet at the bottom and flows upward through the packing (not shown). Cool water is sprayed at the top of the packing and flows downward, counter to the flue gas flow. As the gas flows upward through direct contact cooling vessel 4, it is forced into contact with the water. Direct cooling of the saturated flue gas results in the condensation of most of the water in the flue gas stream. In addition, the residual acidic gases (e.g., SO2, SO3, SOx, hydrogen chloride, and hydrogen fluoride gas) and particulates present in the flue gas are removed in the direct contact cooling vessel 4. In particular, the sulfur dioxide (SO2) is captured by the ammonia to produce ammonium sulfate.
The flue gases leave the direct contact cooling vessel 4 and are charged to the absorber 12.
The absorber 12 employs an absorbent solution (disposed therein) or a slurry that facilitates the absorption and the removal of a gaseous component such as carbon dioxide from the flue gas stream. In the chilled ammonia process, the absorbent solution used in the absorber is a solution or slurry including ammonia (referred to above as an ammoniated solution or slurry). The ammonia can be in the form of an ammonium ion (NH4+), ammonium carbamate, ammonium bicarbonate, or in the form of dissolved molecular ammonia (NH3). By way of example, the absorbent solution or slurry may be comprised of ammonium carbonate, carbamate and bicarbonate ions. As the flue gas flows upwards through the absorber 12, it is contacted with the scrubbing slurry solution containing dissolved ammonium carbonate and ammonium bicarbonate suspended solids that flow in a countercurrent direction to the flue gas, and the CO2 is absorbed.
The flue gas exits the water wash column and enters the direct contact heating vessel 6 for removal of residual ammonia where it is captured by sulfuric acid to form ammonium sulfate before entering the chimney as clean combustion gas. The flue gas exits the carbon dioxide absorber 12 and enters a water wash station 8 to reduce the ammonia vapor from the flue gas. In the water wash station 8, ammonia is removed using chilled water.
The water wash station 8 is a packed column that utilizes water to absorb ammonia from the flue gas. The temperature of the flue gas is maintained using heat exchangers and a mechanical chilling system. The ammoniated water is sent to a stripper column (not shown) (CO2/NH3 stripper) where the ammonia is stripped and returned to the process as reagent. The clean water from the CO2/NH3 stripper is re-used within the water wash column to remove additional ammonia. Energy for the CO2/NH3 stripping column is provided by steam from the power generation facility.
The ammoniated solution or ammoniated slurry (now rich in carbon dioxide in the form of ammonium carbonate or ammonium bicarbonate) is charged to a regenerator 14 where it is heated to decompose it thereby producing carbon dioxide and the absorbent solution. The absorbent solution is returned to the absorber 12 to contact additional flue gas and to absorb carbon dioxide from it. The remainder of the flue gas stream (now substantially devoid of carbon dioxide) is then charged to a water wash station 8 to remove ammonia from it.
The regenerator 14 is a stripper column that contains a mass transfer process. The feed to the regenerator 14 is introduced at several stages. The carbon dioxide rich ammonia solution is flashed by heat introduced in the regenerator reboiler. Flashed carbon dioxide in the feed proceeds up the column to the overhead. As the rich solution falls through the lower regenerator bed, carbon dioxide is separated and rises to the regenerator overhead, and the solution becomes leaner as it reaches the bottom of the column. The lean solution is then returned to the absorber 12 for re-use.
The carbon dioxide exits the top of the regeneration column and flows to a receiver at the top of the regenerator to condense residual moisture and ammonia. At these conditions, there is a significant difference in the vapor pressure between carbon dioxide and ammonia and water. Because of this difference, a very low concentration of water vapor and ammonia are present in the regenerator overhead. The carbon dioxide product stream enters the carbon dioxide compressor, which compresses the stream to a pressure of 1500 psia (103 bar) or as required by the end user.
Disclosed herein too is an integrated system for removing sulfur oxides (SOx) and carbon dioxide from a flue gas stream. The integrated system comprises a desulfurization system that may comprise either a wet flue gas desulfurization (WFGD) system and/or a dry flue gas desulfurization system (DFGD) to remove sulfur oxides (SOx) and a carbon capture system (CCS) that captures carbon dioxide from the flue gas stream. The desulfurization system comprises a desulfurization chamber where a carbonate or bicarbonate salt is used to capture SOx from the flue gas stream and gets converted to a sulfate salt in the process. The flue gas stream now substantially devoid of sulfur oxides is charged to the carbon capture system where the carbon dioxides are captured.
Flue gas from a combustion process is discharged to an air-preheater 102 that is in fluid communication with a desulfurization chamber 116 via a bag-house 104.
The bag-house 104 facilitates the removal of particulate matter (e.g., fly ash particles and the like) prior to the flue gases entering the desulfurization chamber 106.
A spray drier 114 disposed in parallel with the air-preheater 102 is used to dry a small amount of purge material taken out of the desulfurization chamber 106 as a part of zero liquid discharge from the process.
Desulfurization Chamber 106
The desulfurization chamber 106 may be a wet gas desulfurization chamber or a dry gas desulfurization chamber. A variety of different salts may be used in the desulfurization chamber 106 to remove sulfur oxides (SOx) from the flue gas stream. Preferred salts for use in the desulfurization chamber 106 are carbonates, bicarbonates, oxides and/or hydroxides of metals of Group IA and IIA. These include alkali metals and alkaline earth metals. Examples of suitable salts for use in the desulfurization chamber are salts such as sodium bicarbonate, potassium bicarbonate, calcium carbonate, calcium oxide, calcium hydroxide, magnesium carbonate, strontium carbonate, and the like. A preferred bicarbonate salt for use in the desulfurization chamber 106 is sodium bicarbonate.
When calcium oxide and/or calcium hydroxides are used for desulfurization of the flue gases, the desulfurization chamber is preferably a wet gas desulfurization chamber.
The resulting salts produced in the desulfurization chamber 106 as a result of the reaction with the sulfur oxides (SOx from the flue gas stream) are sulfates of alkali metals and alkaline earth metals. Exemplary sulfates are sodium sulfate, potassium sulfate, calcium sulfate, magnesium sulfate, strontium sulfate, and the like
A flue gas stream (from the combustion process) along with a stream of air is introduced into the desulfurization chamber 106. The air provides the oxygen that is used to convert the sulfite salt to a sulfate salt. A bicarbonate salt is also introduced into the chamber 106 from the product reactor and separator 110.
In the desulfurization chamber 106, the bicarbonate salt reacts with the sulfur oxides present in the flue gas stream to form a sulfate salt. For sodium bicarbonate, the reaction (2) is as follows.
2NaHCO3+SO2+½O2→Na2SO4+H2O+2CO2 (2)
The sulfate salt (e.g., sodium sulfate) is then charged to the product reactor and separator 110. An exemplary salt is sodium sulfate.
While the chilled ammonia process comprises a number of different components (such as an absorber, a regenerator, a direct contact cooling vessel, a direct contact heating vessel, a water wash station and a CO2 wash as shown in the
In the chilled ammonia process 108, carbon dioxide is absorbed from the flue gas stream by an absorbent present in an absorber (not shown). The absorbent with the carbon dioxide dissolved therein (termed a carbon dioxide-rich solution) is then discharged from the absorber to a regenerator where the carbon dioxide is separated from the absorbent to form a carbon-dioxide-rich stream and a carbon dioxide-lean stream.
The carbon dioxide-rich stream is then sequestered or utilized.
The absorbent now devoid of carbon dioxide (termed a carbon dioxide lean ammonia solution) is recycled back to the absorber to absorb additional carbon dioxide from the incoming flue gas stream.
Details of the chilled ammonia process are discussed above and as well as detailed in several patents namely U.S. Pat. No. 8,690,992B2 to Dube et al., and U.S. Pat. No. 7,862,788 to Gal et al., the entire contents of which are hereby incorporated by reference.
Product Reactor and Separator 110
The product reactor and separator 110 receives ammonium bicarbonate from the chilled ammonia process 108 and reacts it with the sulfate salt to produce ammonium sulfate and the bicarbonate salt. This reaction for sodium sulfate is detailed as shown in reaction (1) above and is reproduced again below.
Na2SO4+2NH4HCO3→2NaHCO3+(NH4)2SO4 (1)
The reaction between the sulfate salt and the ammonium bicarbonate results in the formation of a sodium bicarbonate salt and ammonium sulfate solution.
The sodium bicarbonate is recycled to the desulfurization chamber 106 while the ammonium sulfate is discharged to the bipolar membrane electrodialysis and then decomposed into ammonia and sulfuric acid both of which are recycled to the chilled ammonia process.
The ammonia is used as a reagent make-up required in the CO2 absorption process and sulfuric acid is used as an absorbent to remove ammonia in the DCH unit to minimize the ammonia slip from the flue gas before it is discharged to the atmosphere.
The bipolar membrane electrodialysis device 112 facilitates the decomposition of ammonium sulfate into sulfuric acid and ammonia. The ammonia is charged to the chilled ammonia device 108 and is recycled to the absorber (see
The bipolar membrane electrodialysis device 112 generally includes an anion exchange membrane and a cation exchange membrane physically or chemically bonded together. Under the driving force of an electrical field, the bipolar membrane dissociates water into hydrogen and hydroxyl ions.
There are substantial advantages to water splitting with the bipolar membrane. Since there are no gases evolved at the surface or within the bipolar membranes, the energy associated with conversion of oxygen and hydrogen is saved. The ions generated in the electro dialysis device pass though anion and cation exchange perm-selective membranes to react with the aqueous alkali and/or alkaline earth metal sulfur salt solution to produce the corresponding acid (e.g., sulfuric acid, sulfurous acid) and a regenerated ammonia feed stream. The acid containing feed stream can then be circulated to the chilled ammonia device along with the ammonia. This method advantageously reduces the operating cost of CAP significantly.
Additionally, the electrodialysis device eliminates the need for the end user to handle the byproduct stream that would typically be generated using an ammonia solution (i.e., the ammonium sulfate), which will further enhance the efficiency of the chilled ammonia process. Details of the functioning of the bipolar membrane electrodialysis device 112 are disclosed in U.S. Patent Publication No. 20130064748 A1 to Dube, the entire contents of which are hereby incorporated by reference.
Direct Contact Cooling Vessel 118
Flue gas containing residual SOx is directed from the desulfurization chamber 106 to the direct contact cooling vessel 118. The direct contact cooling vessel 118 lies downstream of the desulfurization chamber 116. The direct contact cooling vessel 118 lies upstream of the product reactor and separator 110.
In the direct contact cooling vessel 118, sodium hydroxide solution is charged to the top of the vessel while the flu gas containing residual SOx is charged to the bottom of the reactor. The flue gas travels from the bottom upwards counter current to the flow of the sodium hydroxide solution. The SOx present in the flue gas stream is absorbed by the sodium hydroxide to form sodium sulfate which is charged to the product reactor and separator 110. The flue gas (now devoid of SOx) is charged to the carbon capture system 108. Gypsum from the direct contact cooling vessel 118 is fed to the desulfurization chamber 106.
In
As shown in the
As seen in the
Na2SO4+2NH4HCO3→2NaHCO3+(NH4)2SO4 (1)
The reaction between the sulfate salt and the ammonium bicarbonate results in the formation of a sodium bicarbonate salt and ammonium sulfate solution. The sodium bicarbonate is recycled to the desulfurization chamber while the ammonium sulfate is decomposed into ammonia and sulfuric acid both of which are recycled to the chilled ammonia process. The ammonia is used as a reagent make-up required in the CO2 absorption process and sulfuric acid is used as an absorbent to remove ammonia in the DCH unit to minimize the ammonia slip from the flue gas before it is discharged to the atmosphere. This is discussed in detail in the sections directed to the product reactor and separator 110 and the desulfurization chamber 106.
As noted above, the reaction produces a sodium bicarbonate salt and ammonium sulfate solution. A sodium bicarbonate salt is precipitated and separated from the mixture and ammonium sulfate solution is sent to a bipolar membrane electrodialysis unit. A bipolar membrane electrodialysis unit 112 is used to decompose the ammonium sulfate to ammonia & sulfuric acid which is fed back to the chilled ammonia process. Sulfuric acid is removed from the bipolar membrane electrodialysis unit 112 and a portion of it is fed to the chilled ammonia process.
From the
There also exists a recycle loop between the desulfurization chamber 106 and the product reactor and separator 110. The sulfate salt from the desulfurization chamber 106 is charged to the product reactor and separator 110 and the bicarbonate salt from the product reactor and separator 110 is charged to the desulfurization chamber 106.
A number of recycle loops also exist between the product reactor and separator 110, the bipolar membrane electrodialysis unit 112 and the chilled ammonia process 108. In one recycle loop, ammonium sulfate from the product reactor and separator 110 is charged to the bipolar membrane electrodialysis unit 112 while water and unreacted ammonium sulfate are recycled back to the product reactor and separator 110 from the bipolar membrane electrodialysis unit 112.
Another recycle loop exists between the chilled ammonia process 108 and the bipolar membrane electrodialysis unit 112 where ammonium sulfate from the chilled ammonia process 108 is fed to the bipolar membrane electrodialysis unit 112 and where ammonia and sulfuric acid produced in the bipolar membrane electrodialysis unit 112 are recycled to the chilled ammonia process 108.
In one embodiment, in one manner of using the system 100 of the
The bipolar membrane electrodialysis device 112 receives the ammonium sulfate from the product reactor and separator 110 and decomposes it to ammonia and sulfuric acid. The ammonia is charged to the absorber of the chilled ammonia process 108 where it forms ammonium bicarbonate. A portion of sulfuric acid generated in the bipolar membrane electrodialysis device 112 is charged to the chilled ammonia process 108 where it reacts with the ammonia slip in the DCH to produce ammonium sulfate. This ammonium sulfate is charged to the bipolar membrane electrodialysis device 112 from the chilled ammonia process 108 where it is decomposed to form ammonia and sulfuric acid. Any water or unused ammonium sulfate from the bipolar membrane electrodialysis device 112 are discharged to the product reactor and separator 110.
In an embodiment, a portion of sodium bicarbonate may be diverted from being charged to the desulfurization chamber 106 (from the product reactor and separator 110) to points 101 and 103 upstream and downstream of the air preheater 102 where it can be used to absorb a small portion of sulfur oxides (SOx) from the incoming flue gas stream At points 101 and 103, the temperature of the flue gas stream is higher than when it enters the desulfurization chamber 106 and hence the removal of sulfur oxides (especially SO3) from the flue gas stream is more efficient.
In another embodiment, a small purge stream 105 is charged from the desulfurization chamber 106 to the spray dryer 114 where heat from the flue gas stream is used to dry the contents of the purge stream.
The
In the embodiment depicted in the
In this embodiment, the flue gas desulfurization chamber 106 of the
Wet flue gas desulfurization systems are detailed in U.S. Patent Publication No. 2013/0064748, the entire contents of which are hereby incorporated by reference. The flue gas exiting the flue gas desulfurization unit is typically at a temperature of about 50 to 60° C. for wet flue gas desulfurization systems and about 80 to 100° C. for dry flue gas desulfurization systems (see the desulfurization chamber 106 of the
The remaining flue gas from the wet flue gas desulfurization chamber 116 is then charged to the direct contact cooling vessel 118 where any residual sulfur oxides are removed. The direct contact cooling vessel 118 may be a packed tower with liquid recirculation through a cooling tower having multiple stages that uses ambient air to lower the recirculation liquid temperature. An alkali and/or alkaline earth metal hydroxide reagent such as sodium hydroxide is introduced into a first stage of the direct contact cooling vessel 118 and mixed with cooling water at a bottom portion of the direct contact cooling vessel 118. Details of the operation of the direct contact cooling vessel 118 are provided in U.S. Patent Publication No. 2013/0064748, the entire contents of which are hereby incorporated by reference.
In an embodiment, the aqueous alkali and/or alkaline earth metal hydroxide solution is pumped via pump (not shown) through a conduit (not shown) to a top portion of the direct contact cooling vessel 118. Optionally, the aqueous alkali and/or alkaline earth metal hydroxide solution may first be pumped to a chiller (not shown) to further lower the temperature of the aqueous alkali and/or alkaline earth metal hydroxide solution. Flue gas enters the direct contact cooling vessel 118 inlet at the bottom portion and flows upward.
The cool aqueous alkali and/or alkaline earth metal hydroxide solution is sprayed at the top of the packing and flows downwards, counter to the flue gas flow. As the flue gas flows upwards through direct contact cooling vessel 118, the flue gas is forced into contact with the aqueous alkali and/or alkaline earth metal hydroxide solution. Direct cooling of the saturated flue gas in subsequent stages results in the condensation of most of the water in the flue gas stream. In addition to reaction of SOx, the residual gases present in the flue gas are generally rendered water soluble. Moreover, any SOx contaminants entrained in the flue gas react with the aqueous alkali and/or alkaline earth metal hydroxide solution to form a feed-stream of the corresponding aqueous alkali and/or alkaline earth metal sulfur containing salt solution.
In an embodiment, when sodium hydroxide is used as the hydroxide solution in the direct contact cooling vessel 118, it absorbs the sulfur oxides to produce sodium sulfate. The sodium sulfate from the direct contact cooling vessel 118 is then discharged to the product reactor and separator 110 where it reacts with ammonium bicarbonate to produce ammonium sulfate and sodium bicarbonate as detailed in the
The system of the
It will be understood that when an element or layer is referred to as being “on,” “interposed,” “disposed,” or “between” another element or layer, it can be directly on, interposed, disposed, or between the other element or layer or intervening elements or layers may be present.
It will be understood that, although the terms first, second, third, and the like may be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms. These terms are only used to distinguish one element, component, region, layer or section from another element, component, region, layer or section. Thus, first element, component, region, layer or section discussed below could be termed second element, component, region, layer or section without departing from the teachings of the present invention.
As used herein, the singular forms “a,” “an” and “the” are intended to comprise the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.
Unless otherwise defined, all terms (including technical and scientific terms) used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. It will be further understood that terms, such as those defined in commonly used dictionaries, should be interpreted as having a meaning that is consistent with their meaning in the context of the relevant art and will not be interpreted in an idealized or overly formal sense unless expressly so defined herein.
Furthermore, in describing the arrangement of components in embodiments of the present disclosure, the terms “upstream” and “downstream” are used. These terms have their ordinary meaning. For example, an “upstream” device as used herein refers to a device producing a fluid output stream that is fed to a “downstream” device. Moreover, the “downstream” device is the device receiving the output from the “upstream” device. However, it will be apparent to those skilled in the art that a device may be both “upstream” and “downstream” of the same device in certain configurations, e.g., a system comprising a recycle loop.
