Process for regenerating catalysts from high-pressure fluid catalytic processes.

Abstract

A process for regenerating a catalyst from a fluidized catalytic process is disclosed. The process includes providing an oxygen stream and a preheated carbon dioxide recycle stream, and mixing the oxygen stream and the preheated carbon dioxide recycle stream to provide a carbon dioxide-rich oxidation stream. The carbon dioxide-rich oxidation stream is transferred to a regenerator unit to provide a carbon dioxide-rich flue gas stream. One or more of sulfur-containing compounds, nitrogen-containing compounds, or both in the carbon dioxide-rich flue gas stream are reacted with reactants in a scrubbing reactor to form a reactor effluent stream containing reactant salts. The reactor effluent stream is filtered to remove reactant salts and catalyst fines to produce a filtered reactor effluent stream. The carbon dioxide recycle stream is taken from the filtered reactor effluent stream.

Description

Technical Field

[0001] (Priority Claim) This application claims the priority of U.S. Provisional Patent Application No. 63 / 390,891 filed on July 20, 2022, U.S. Provisional Patent Application No. 63 / 407,151 filed on September 15, 2022, U.S. Provisional Patent Application No. 63 / 485,194 filed on February 15, 2023, and U.S. Patent Application No. 18 / 144,790 filed on May 8, 2023, the entire contents of which are incorporated herein by reference.

[0002] (Field of the Invention) This technical field relates to processes and apparatus for regenerating a catalyst from a fluid catalytic process. In particular, this technical field relates to a process for regenerating a catalyst from a fluid catalytic process using a carbon dioxide (CO2) recycle stream.

Background Art

[0003] Catalytic cracking can produce various products from larger hydrocarbons. Feedstocks of heavy hydrocarbons such as vacuum gas oil are often fed to a catalytic cracking reactor such as a fluid catalytic cracking reactor. Various products including gasoline products and / or light products such as propene and / or ethene can be produced from such a system.

[0004] Fluid catalytic cracking (FCC) is a hydrocarbon conversion process achieved by contacting hydrocarbons with a catalyst consisting of finely divided particulate matter in a fluid reaction zone. In catalytic cracking, the reaction proceeds with virtually no added hydrogen or hydrogen consumption, in contrast to hydrocracking. As the cracking reaction progresses, a considerable amount of high-carbon material, called coke, accumulates on the catalyst. High-temperature regeneration operations in the regenerator zone burn off the coke derived from the catalyst. The coke-containing catalyst, referred to herein as the coke catalyst, is continuously removed from the reaction zone and replaced with an essentially coke-free catalyst from the regeneration zone. Fluidization of catalyst particles by various gas flows allows for the transport of the catalyst between the reaction zone and the regeneration zone. The spent catalyst from the reaction zone can be fully or partially regenerated in the regeneration zone.

[0005] The common objective of these configurations is to maximize the product yield from the reactor while minimizing operating and equipment costs. Optimizing the raw material conversion rate usually requires essentially complete removal of coke from the catalyst. This essentially complete removal of coke from the catalyst is often called complete regeneration. Complete regeneration produces a catalyst with less than 0.1% by weight, preferably less than 0.05% by weight, of coke. To obtain complete regeneration, the catalyst must be exposed to oxygen at a high temperature for a residence time sufficient to allow complete combustion.

[0006] Conventional regenerators typically include a container having a coke catalyst inlet, a regenerated catalyst outlet, and a combustion gas distributor for supplying air or other oxygen-containing gas to the catalyst bed present in the container. A cyclone separator removes the catalyst that has been entrained into the flue gas before the flue gas leaves the regenerator.

[0007] Alternative processes are also used in the production of light olefins. In one approach, hydrocarbon oxygenates, more specifically methanol or dimethyl ether, are used as alternative feedstocks for producing light olefin products. Once the oxygenates are formed, this process involves catalytically converting the oxygenates, such as methanol, into the desired light olefin product in a methanol-to-olefin (MTO) process. In the MTO process, carbonaceous material, i.e., coke, is deposited on the catalyst as the catalyst moves through the reaction zone. The carbonaceous material is removed from the catalyst by oxidative regeneration in one or more regeneration zones, and the moving bed of catalyst particles removed from the reaction zone is contacted with an oxygen-containing gas stream at a temperature and oxygen concentration sufficient to allow a desired amount of carbonaceous material to be removed from the catalyst by combustion. In some cases, it is advantageous to regenerate the catalyst only partially, for example, by removing 30-80% by weight of the carbonaceous material.

[0008] Flue gas formed by burning coke in a regenerator is treated to remove particulate matter and convert it to carbon monoxide (CO), and then the flue gas is usually released into the atmosphere. Furthermore, incomplete combustion into carbon monoxide can result from insufficient fluidization or aeration of the coke catalyst in the regenerator, or from insufficient distribution of the coke catalyst within the regenerator. Generally, flue gas exiting a regenerator contains carbon monoxide, carbon dioxide, nitrogen, and water, along with small amounts of other chemical species. Flue gas treatment methods are effective, but they have high capital and operating costs.

[0009] Conventional treatment of flue gas from FCC and MTO units involves the use of wet gas cleaning techniques, such as caustic scrubbers, to remove sulfur compounds from the flue gas. In this process, the flue gas from the FCC regenerator is heat-exchanged with boiler feedwater to produce steam, which cools the flue gas. The flue gas is further cooled from a temperature of 400-500°F to 140-194°F using water quenching. The cooled flue gas comes into contact with sodium hydroxide, which reacts with sulfur compounds to form sodium sulfite (Na2SO3) and / or sodium sulfate (Na2SO4) and water, which are then removed. Alternatively, other suitable reagents or seawater can be used to remove sulfur compounds from the flue gas. The flue gas can optionally be heated and treated to remove nitrogen compounds. The flue gas can also be optionally treated to remove catalyst fines and other particulate matter. The treated flue gas can then be discharged into the atmosphere.

[0010] The capital cost of this system is high, as are the operating costs due to the use of sodium hydroxide or other reagents, water, electricity, coagulants, and slurry handling. Furthermore, this system requires a large area and is maintenance-intensive. The wet scrubber process has high makeup water requirements due to the use of water quenching and aqueous sodium hydroxide solution. This system is also plagued by corrosion problems associated with the use of sulfuric acid (H2SO4) and concerns about spray nozzle fouling due to the presence of salt. A substantial amount of sensible heat energy is not recovered due to acid dew point limitations. Insufficient energy recovery is due to high stack temperatures and an inadequate thermal profile (quenching the boiler flue gas outlet to adiabatic saturation to enable wet sulfur removal, and in some cases, then reheating the flue gas to the selective catalytic reduction (SCR) inlet temperature requirements necessary to enable nitrogen (NOx) removal). This can result in a negative energy balance. In addition, there may be problems with the blue plume caused by sulfuric acid, the formed submicron aerosols, and the white plume caused by water condensation when the flue gas is released into the atmosphere. This can be avoided by heating the flow, but this method increases capital and operating costs. After treatment, the treated flue gas is generally released into the atmosphere or sent to further recover components from the flue gas.

[0011] Due to environmental concerns regarding greenhouse gas emissions, separating greenhouse gases before releasing flue gas into the atmosphere is becoming increasingly important. Carbon dioxide is the most significant and longest-lived greenhouse gas in the Earth's atmosphere. Carbon dioxide capture from flue gas remains expensive in terms of both capital expenditure and operational costs. In fluid catalytic processes, air is used to regenerate spent catalysts. As a result of this operation, the amount of carbon dioxide in FCC flue gas is lower, in contrast to the amount of undesirable components from a carbon dioxide capture standpoint, resulting in high capital expenditures due to the large volume of flue gas, as well as significant operational costs as high solvent circulation rates and solvent regeneration loads. Separately, flue gas requires extensive flue gas treatment before carbon capture to meet stringent specifications to avoid high solvent decomposition rates. This results in high capital expenditures and operational costs, involving various longer impurity removal operations. In addition, wet gas scrubbers are typically used, which presents risks of blue plumes in addition to white plumes resulting from water condensation during release into the atmosphere, as well as insufficient energy recovery from flue gases, large amounts of makeup water, corrosion and fouling-related problems in the plant, difficulties in handling slurries, and water condensation during release into the atmosphere.

[0012] Therefore, improved processes are needed for treating flue gas containing carbon dioxide. Furthermore, processes and equipment are required that reduce the capital expenditures and operating costs of the carbon dioxide capture section as a flue gas treatment section, while improving energy efficiency and energy recovery. [Overview of the project]

[0013] This disclosure provides a process and apparatus for regenerating catalysts from a fluid catalyst process. Generally, air is used in regenerators to burn coke derived from spent catalysts. Because air contains a large amount (79 mol%) of nitrogen (N2), the partial pressure of carbon dioxide is low. As a result, the amount of carbon dioxide in the FCC flue gas is much smaller, such as 15-25 mol%, with the remainder being undesirable components. This process discloses supplying a carbon dioxide-rich oxidation flow to the regenerator instead of air. The flue gas from the regenerator produced by this process has an economically desirable amount of carbon dioxide from the standpoint of carbon dioxide capture, compared to the undesirable components resulting from the use of air in the regenerator.

[0014] This disclosure provides a method for separating a carbon dioxide recirculation flow from a flue gas flow, mixing the carbon dioxide recirculation flow with an oxygen flow, and moving the carbon dioxide-rich oxidation flow to a regenerator for burning coke derived from spent catalyst. The carbon dioxide-rich oxidation flow provides a substantially nitrogen-free atmosphere within the regenerator, reducing the amount of undesirable components in the flue gas from a carbon dioxide capture standpoint. The substantially nitrogen-free regeneration process allows for a significant size reduction of the regenerator, flue gas treatment section, and carbon capture section. The process and apparatus increase the capacity of existing units. The carbon dioxide-rich oxidation flow provides substantially nitrogen-free conditions and, due to the higher molar heat capacity of carbon dioxide compared to nitrogen, improves the need for a high-temperature regenerator when air is moved to the regenerator.

[0015] Furthermore, this process provides a dry cleaning process for the treatment of flue gas. The dry cleaning process avoids corrosion problems compared to the wet cleaning process. The dry cleaning process also eliminates the possibility of blue / white plumes due to water condensation and / or sulfuric acid aerosols in the wet cleaning process. This process also provides thermal integration between the carbon dioxide recirculation flow and the dry cleaning process, resulting in a substantial increase in energy recovery from flue gas made possible through dry cleaning. [Brief explanation of the drawing]

[0016] Various embodiments are described below with reference to the following drawings, where similar numbers indicate similar elements. [Figure 1] This is a schematic diagram of a process and apparatus for regenerating a catalyst from a fluid catalyst process according to an exemplary embodiment. [Figure 2] This is a schematic diagram of a process and apparatus for regenerating a catalyst from a fluid catalyst process according to another exemplary embodiment. [Figure 3] This is a schematic diagram of a process and apparatus for regenerating a catalyst from a fluid catalyst process according to yet another exemplary embodiment. [Figure 4] This is a schematic diagram of a process and apparatus for regenerating a catalyst from a fluid catalyst process according to yet another exemplary embodiment. [Figure 5] This is a schematic diagram of a process and apparatus for regenerating a catalyst from a fluid catalyst process according to yet another exemplary embodiment.

[0017] definition The term "communication" means that the flow of material between the listed components is operablely permitted.

[0018] The term "downstream communication" means that in downstream communication, at least a portion of the material flowing to the object can be operably flowed from the communicating object.

[0019] The term "upstream communication" means that in upstream communication, at least a portion of the material flowing from an object can flow operably into the communicating object.

[0020] The terms "direct connection" or "direct" mean that the flow from the upstream component enters the downstream component without passing through a fractionation or transformation unit and undergoing compositional changes due to physical fractionation or chemical transformation.

[0021] The term "column" means one or more distillation columns (singular or plural) for separating components of different volatilities. Unless otherwise indicated, each column includes a condenser at the top of the column to condense and reflux a portion of the overhead stream returning to the top of the column, and a reboiler at the bottom of the column to vaporize a portion of the bottoms stream and return it to the bottom of the column. The feedstock to the column can be preheated. The top pressure is the pressure of the overhead vapor at the vapor outlet of the column. The bottom temperature is the liquid bottoms outlet temperature. The top line and the bottom line refer to the net line from the column downstream of any reflux or reboiling to the column. A stripper column omits the reboiler at the bottom of the column and instead can provide the required heat and the driving force for separation from a fluidizing inert medium such as steam. A stripper column typically feeds the feedstock to the top tray and withdraws the main product from the bottom.

[0022] As used herein, the term "separator" means a vessel having an inlet, at least an overhead vapor outlet and a bottoms liquid outlet, and may also have an aqueous outlet from the boot. A flash drum is a type of separator that can be in downstream communication with a separator operating at a higher pressure.

[0023] As used herein, the term "component-rich stream" means that the rich stream exiting the vessel has a higher concentration of the component than the feed to the vessel.

[0024] As used herein, the term "rich" means greater than 50%, preferably greater than 75%, more preferably greater than 90%.

DETAILED DESCRIPTION OF THE INVENTION

[0025] A process for regenerating a catalyst from a fluid catalyst process is disclosed. The process includes the use of a dry sorbent injection (DSI) unit to remove sulfur compounds from flue gas produced from the regenerated catalyst from the fluid catalyst process. The fluid catalyst process may be any fluid catalyst process that regenerates a catalyst, including an FCC process or an MTO process. The flue gas from the regenerator of the fluid catalyst process is used to produce superheated steam and saturated steam. The flue gas is then sent to a DSI unit to remove sulfur compounds and then to a heat recovery exchanger, which may be a heat exchanger for heating a carbon dioxide recirculation flow, as described in detail below. Since the flue gas temperature does not drop as much as in a wet scrubber process, additional thermal energy can be recovered from the flue gas in the heat recovery exchanger.

[0026] By utilizing a dry adsorbent injection (DSI) system, unharvested sensible heat energy can be captured, substantially improving the energy efficiency of the process and avoiding a negative energy balance. The increased energy efficiency achieved by using a DSI system instead of a wet gas scrubber system can also be applied to any type of fluid catalytic process where flue gas is generated at SOx concentrations exceeding environmental limits.

[0027] This process results in a substantial increase in energy recovery by adding a heat recovery exchanger downstream of the DSI (or selective catalytic reduction unit, if present). The thermal integration provided by this process recovers additional energy.

[0028] Furthermore, heat can be recovered from the flue gas before or after the DSI to preheat the boiler feedwater used in the heat recovery steam generator (HRSG) and / or catalytic cooler and / or CO combustor, thereby reducing or eliminating the possibility of a negative energy balance. Alternatively, low-pressure (LP) or medium-pressure (MP) steam can be generated and used in the FCC process and other processes.

[0029] Removing sulfur upstream of the heat recovery exchanger reduces the risk of pipe corrosion and significantly improves system reliability. The disclosed process reduces or eliminates concerns related to corrosion caused by sulfuric acid. By avoiding operation under corrosive conditions, stainless steel flue gas scrubbers become unnecessary, and the entire system can be made from carbon steel.

[0030] DSI technology does not require water, and since water is considered a scarce resource, the system's water usage is significantly improved. This process also avoids the need to handle complex slurries, eliminates concerns about spray nozzle fouling in wet gas scrubbers, and avoids white plumes resulting from water condensation and blue plumes resulting from sulfuric acid aerosol release. In addition, when using NaHCO3 as the DSI reactant, a NOx reduction of up to 21% can be achieved, while the system pressure drop can be reduced by up to 50%.

[0031] When air is used as a combustion gas, a large amount of inert substances, particularly nitrogen (N2), enter the regenerator flue gas, resulting in a lower partial pressure of carbon dioxide. Nitrogen occupies unnecessary volume, leading to larger equipment sizes for the regenerator and downstream flue gas treatment equipment. Due to the low partial pressure of carbon dioxide, the cost of carbon dioxide capture is relatively high, which may be the reason for the resistance of refiners to implementing carbon dioxide (CO2) capture technology. This process replaces the air with a carbon dioxide-rich oxidizing flow containing carbon dioxide and up to 30 mol% oxygen. The carbon dioxide-rich oxidizing flow containing carbon dioxide and oxygen significantly increases the partial pressure of carbon dioxide in the flue gas, allowing for lower capital and operational costs for carbon dioxide capture.

[0032] In the wet cleaning process, it is necessary to saturate the flue gas by passing a rapid coolant through it. Therefore, the flue gas after wet cleaning is at a low temperature of 140-200°F. In comparison, dry cleaning can be performed at a higher temperature of 300-600°F. To reduce overall capital expenditure, it is proposed to recover heat / energy from the flue gas flow after dry cleaning. The process of the present invention recovers heat from the flue gas after dry cleaning using a heat recovery exchanger. The heat recovery exchanger may be used for heat exchange with a carbon dioxide recirculation flow, but the recirculation carbon dioxide flow can be heated to a desired temperature level for transfer to a regenerator without requiring external heat equipment. Furthermore, the process extracts the carbon dioxide recirculation flow from the flue gas flow after the dry cleaning process.

[0033] In an FCC process, flue gas from the regenerator is generally moved to a third-stage separator (TSS) to separate catalyst particles from the flue gas. A small amount of flue gas containing most of the catalyst particles is collected as an underflow from the TSS. The remainder of the flue gas is separated in the overflow from the TSS. Catalyst particles from the underflow from the TSS are further separated. The underflow from the TSS is sent to a fourth-stage separator to separate the catalyst particles. In an FCC process, the TSS can be directly integrated with the filter section. Therefore, the fourth-stage separator for the underflow from the TSS can be omitted. Thus, the underflow from the TSS is moved directly to the filter section for the removal of catalyst particles. Energy can also be extracted from the overflow from the TSS. The overflow from the TSS flows to an expansion turbine, where the energy is extracted in the form of work. The expander may be coupled to the main blower to provide power for blower operation, or the blower may be driven by a separate electric motor or steam turbine, and the expander output may be used solely for power generation. When the expander is coupled to the blower, a motor / generator is required in the train to balance the expander output with the blower power requirements, and a steam turbine is included to assist with starting. The steam turbine may be designed for continuous operation as an economical outlet for excess steam, or a less expensive turbine that vents to the atmosphere may be installed for use only during starting. In an exemplary embodiment, the expander is coupled to a generator for blue power generation.

[0034] The flue gas from the regenerator in the FCC process may contain unconverted carbon monoxide. The unconverted carbon monoxide in the flue gas can be burned to carbon dioxide in a CO combustor that generates high-pressure steam. The flue gas is removed from the regenerator and fed into the CO combustor in the heat recovery section, where a combustion air stream is added to burn the flue gas, releasing heat which is then recovered. The use of air in the CO combustor can also result in the accumulation of nitrogen gas in the flue gas stream obtained from the CO combustor. This nitrogen from the CO combustor can be eliminated by replacing the air supplied to the CO combustor, dry air (DA) purge points, and other purges such as the fluffing air in the regenerator with a portion of the oxygen-containing carbon dioxide-rich oxidation stream and a recirculated carbon dioxide stream. Thus, in the FCC process, the carbon dioxide-rich oxidation stream is separated into a first and second portion. The first portion of the carbon dioxide-rich oxidation stream is sent to the regenerator unit, and the second portion of the carbon dioxide-rich oxidation stream is sent to the heat recovery section.

[0035] The regenerator unit may be a partial combustion unit or a complete combustion unit. In a partial combustion regenerator unit, the flue gas typically contains up to 10%, more specifically 2% to 5%, of carbon monoxide, which is used as the primary fuel source in a downstream CO combustor or combustion chamber where the flue gas is burned to release heat, and this heat is recovered. By operating the regenerator in partial combustion mode to maximize the carbon monoxide yield, the unit limits the amount of heat released within the regenerator compared to completely burning coke into carbon dioxide. This lowers the regenerator temperature and allows for a higher catalyst-to-oil ratio in the FCC riser.

[0036] Figure 1 shows a process and apparatus 101 for regenerating a catalyst from a fluid catalyst process, according to an exemplary embodiment. The catalyst regeneration apparatus comprises a regenerator unit 120, a heat recovery section 125, a decontamination reactor 140, a filter section 150, a heat exchanger 190, and a carbon dioxide separation section 111. One aspect of the present disclosure includes a process for regenerating a catalyst from a fluid catalyst process. The method includes supplying an oxygen stream to line 104. Typically, the oxygen stream is supplied from an air separation unit (ASU). However, the applicant has found that the oxygen stream may be taken from an electrolytic cell. Thus, the oxygen stream in line 104 may be supplied from an electrolytic cell. The carbon dioxide recirculation stream in line 186 is preheated in the heat exchanger 190 to provide a preheated carbon dioxide recirculation stream in line 194. The oxygen stream from line 104 and the preheated carbon dioxide recirculation stream from line 194 are sent to a mixing unit or mixer 196 to provide a carbon dioxide-rich oxidation stream in line 197. The carbon dioxide-rich oxidation stream in line 197 is moved to a regenerator unit 120. The spent catalyst stream from the fluid catalyst process in line 102 is also moved to the regenerator unit 120. In one embodiment, the carbon dioxide-rich oxidation stream in line 197 contains an oxygen concentration of 30 mol% or less.

[0037] In a fluidized catalyst process, catalyst particles are repeatedly circulated between the reaction zone and the catalyst regenerator unit 120. During regeneration, coke deposited on the catalyst particles during the reaction in the reaction zone is removed at high temperatures by oxidation in the regenerator unit 120. Removal of the coke deposits restores the activity of the catalyst particles to a point where they can be reused in the reaction zone. This disclosure relates to handling the flue gas flow from the regenerator. The regenerated catalyst is removed from the regenerator unit 120 (not shown in Figure 1) and handled as is known in the art.

[0038] The carbon dioxide-rich flue gas flow of line 122 is taken out from the regenerator unit 120. The carbon dioxide-rich flue gas flow of line 122 is typically hot, and heat can be recovered from the carbon dioxide-rich flue gas flow of line 122 before further processing. The carbon dioxide-rich flue gas flow of line 122 is moved to the heat recovery section 125 to transfer heat from the carbon dioxide-rich flue gas flow of line 122 to the boiler feedwater flow of line 127, forming the partially cooled carbon dioxide-rich flue gas flow of line 132 and the steam flow of line 126. The heat recovery section 125 may include an HRSG or a CO combustor and an HRSG. As described herein, when the regenerator unit 120 is operating under partial combustion, a portion of the carbon dioxide-rich oxidizing flow of line 197 is sent to the CO combustor of line 199 to prevent nitrogen accumulation in the flue gas flow. The carbon dioxide-rich oxidizing flow of line 197 is separated into a first portion of line 198 and a second portion of line 199. The first portion of the carbon dioxide-rich oxidizing flow from line 198 is sent to the regenerator unit 120, and the second portion of the carbon dioxide-rich oxidizing flow from line 199 is sent to the CO combustor in the heat recovery section 125.

[0039] Under partial combustion operation, the carbon dioxide-rich flue gas flow of line 122, along with the fuel gas flow 121 and a second portion of the carbon dioxide-rich oxidized flow of line 199, is sent to the CO combustor 124 of the heat recovery section 125 to oxidize the carbon monoxide present in the carbon dioxide-rich flue gas flow of line 122 to carbon dioxide. The fully combusted flow from the carbon monoxide combustor is then sent to the HRSG unit 129 of the heat recovery section 125. In exemplary embodiments, the flue gas outlet temperature of the FCC regenerator for a partial or full combustion FCC regenerator may be in the range of 670–740°C or 650–700°C. The flue gas temperature exiting the CO combustor may be in the range of 890–1040°C.

[0040] In the case of the complete combustion regenerator unit 120, the heat recovery section 125 includes only the HRSG unit 129, and the CO combustor 124 is absent. Therefore, under the complete combustion regenerator unit 120, the carbon dioxide-rich flue gas flow of line 122 is sent to the HRSG unit 129. The complete combustion or partial combustion MTO regenerator may operate at temperatures in the range of 670°C to 740°C or 650°C to 700°C. In the HRSG, the high-temperature flue gas is indirectly heat-exchanged with water in line 127 to produce steam in line 126 and condensed flow in line 133. The steam flow in line 126 and condensed flow in line 133 are taken out of the HRSG unit 129. The partially cooled carbon dioxide-rich flue gas flow of line 132 is taken out of the heat recovery section 125. The partially cooled carbon dioxide-rich flue gas flow of line 132 is processed to remove impurities. The flue gas outlet temperature from the HRSG for a partially combustion FCC regenerator or a fully combustion FCC or MTO process may be in the range of 200°C to 290°C.

[0041] The partially cooled carbon dioxide-rich flue gas flow of line 132 is moved to the decontamination reactor 140. The reactants of line 131 are also moved to the decontamination reactor 140. In one embodiment, the reactants of line 131 are in a dry form. In one embodiment, the partially cooled carbon dioxide-rich flue gas flow of line 132 from the heat recovery section 125 is mixed with the dry reactants 131 to provide a mixed flow of line 137, which together is sent to the decontamination reactor 140, where the reactants react with sulfur-containing compounds and / or nitrogen-containing compounds in the partially cooled carbon dioxide-rich flue gas flow in line 132 to form a reactor outflow flow containing reactant salts of line 142. Since the reactants 131 are used in a dry form, the decontamination reactor 140 can be operated at a higher temperature compared to a slurry form of reactants. In an exemplary embodiment, the decontamination reactor 140 operates at a temperature of 200°C to 600°C or 300°C to 600°C to react one or more sulfur-containing compounds, nitrogen-containing compounds, or both in a partially cooled carbon dioxide-rich flue gas stream of line 132 with a dry reactant 131. In another exemplary embodiment, the reactant 131 comprises one or more of sodium bicarbonate (NaHCO3), calcium hydroxide (Ca(OH)2), and trona salt (Na2CO3·NaHCO3·2H2O). In yet another exemplary embodiment, the reactant salt comprises one or more of sodium sulfate (Na2SO4), sodium carbonate (Na2CO3), and sodium nitrate (NaNO3). The reactor outflow stream containing the reactant salt from line 142 is moved to a filter section 150 for particle removal.

[0042] The filter section 150 removes particulate matter and fine particles from the reactor outflow flow of line 142. If the filter section 150 includes an electrostatic precipitator, electricity is supplied to the filter section 150. The filter section 150 may also include a bag filter. The filtered material from the filter section 150 may include one or more of the following: sodium sulfate (Na2SO4), sodium nitrate (NaNO3), sodium nitrite (NaNO2), sodium carbonate (Na2CO3), and catalyst fine particles that can be removed in the filter section 150. The filtered material 154 can be removed from the process in line 155. Alternatively or additionally, the filtered material may be recycled to the decontamination reactor 140 as recycled filter material in line 156 to increase the sodium carbonate conversion yield. The recycled filter material in line 156 may be recycled with the mixed flow in line 137 and sent to the decontamination reactor 140 in line 139. Therefore, the reactant salts and catalyst fines are removed from the reactor effluent 142 in the filter section 150 to produce the filtered reactor effluent in line 152. The filtered reactor effluent in line 152 is moved to the carbon dioxide separation section 111 to separate carbon dioxide from the filtered reactor effluent. The separation section 111 may include a heat exchanger 190, coolers 160 and 180, knock-out drums (KODs) 163 and 184 for separation, a heater 167, a compressor 170, and a generator 175.

[0043] Since the reactants are used in a dry form, the filtered reactor effluent in line 152 still has a fairly high temperature. Heat / energy can still be recovered from the filtered reactor effluent in line 152. The filtered reactor effluent in line 152 is heat-exchanged with the carbon dioxide recirculation flow in line 186 in heat exchanger 190 to provide the preheated carbon dioxide recirculation flow in line 194 and the partially cooled and filtered reactor effluent in line 192. In an exemplary embodiment, heat exchanger 190 is a gas-gas heat exchanger. Optionally, the partially cooled and filtered reactor effluent in line 192 may be cooled in a first cooler 160 and moved to a first knockout drum (KOD) 163. Alternatively, the partially cooled and filtered reactor effluent in line 192 may be moved directly to the first knockout drum (KOD) 163 without further cooling. The first cooler 160 may use cooling water and / or chilled water as the cooling medium. Alternatively, the first cooler 160 may be an air cooler. In one aspect of the present disclosure, the first cooler 160 may be optional, and the cooled and filtered reactor outflow logistics of line 192 may be moved directly to the first KOD 163.

[0044] In the first KOD 163, water is separated from the cooled and filtered reactor outflow flow of line 162 to provide a carbon dioxide flow, which is taken out from the top of the KOD in line 164. The water is taken out as flow 165 from the bottom of the first KOD 163. This process recirculates the carbon dioxide flow of line 164 to the regenerator unit 120. Thus, part or all of the carbon dioxide flow of line 164 can be taken and mixed with the oxygen flow 104 to provide a carbon dioxide-rich oxidizing flow 197 for the regenerator unit 120. In one embodiment, the carbon dioxide flow is separated into a carbon dioxide flow for recirculation in line 166 and a separated carbon dioxide flow in line 168. The separated carbon dioxide flow in line 168 may be taken out and sent for storage. The separated carbon dioxide flow in line 168 is SO x NO xFurthermore, for the removal of trace amounts of contaminants such as NH3, O2, and H2O, treatment in a pressure swing adsorption (PSA) unit or a thermal swing adsorption (TSA) unit may be required. The separated carbon dioxide stream from line 168 may be treated as appropriate and sent to storage. According to this process, the carbon dioxide stream for recirculation from line 166 may be further treated before being recirculated to the regenerator unit 120.

[0045] The carbon dioxide flow for recirculation in line 166 may be moved to a carbon dioxide recirculation compressor 170 to provide a compressed carbon dioxide recirculation flow in line 172. The compressed carbon dioxide recirculation flow in line 172 may be moved to a generator 175 to provide a partially cooled carbon dioxide recirculation flow in line 176 and a steam flow in line 177 from the water flow in line 174. The steam flow in line 177 can be used for power generation purposes. In an exemplary embodiment, the generator 175 is a low-pressure steam generator 175 that provides a low-pressure steam flow. The partially cooled carbon dioxide recirculation flow in line 176 is cooled in a second cooler 180 to provide a cooled carbon dioxide recirculation flow in line 182, which is moved to a second knockout drum (KOD) 184. The second cooler 180 may be an air cooler. Alternatively, the second cooler 180 may use cooling water and / or chilled water as a cooling medium. The compressed carbon dioxide recirculation flow in line 172 at the outlet of the carbon dioxide recirculation compressor 170 is at a high temperature. The compressed carbon dioxide recirculation flow in line 172 may have a temperature of 220°C (428°F) to 260°C (471°F). Generally, boiler feed water (BFW) needs to be heated to 121°C (250°F) to 177°C (350°F). According to this process, the compressed carbon dioxide recirculation flow in line 172 may be used to preheat the BFW flow in a BFW preheater (not shown). Thus, the compressed carbon dioxide recirculation flow in line 172 may be moved to the BFW preheater and then to a second cooler 180.

[0046] Cooling and condensation of the cooled and filtered reactor outflow flow in line 192 using the first cooler 160 may result in aqueous phase formation. This may lead to carbon dioxide formation due to the reaction of carbon dioxide with water. Carbon dioxide formation may cause carbonic acid corrosion to the heat exchanger 190, the first cooler 160, the first KOD 163, and other downstream equipment. Therefore, the metallurgy of the first cooler 160 and the first KOD 163 is suitably selected to withstand any carbonic acid corrosion. According to one embodiment of the present disclosure, a heater 167 may be located upstream of the carbon dioxide recirculation compressor 170. According to one embodiment, the heater 167 may be used to raise the temperature of the carbon dioxide flow for recirculation of line 166, providing a heated carbon dioxide flow for recirculation of line 169 which is then moved to the carbon dioxide recirculation compressor 170. According to an exemplary embodiment, the carbon dioxide flow for recirculation of line 166 is moved to a heater 167 to raise the temperature of the carbon dioxide flow by 5°C (9°F) to 50°C (90°F) above the dew point of the carbon dioxide flow to avoid carbonic acid corrosion in any of the downstream equipment. The heated carbon dioxide flow for recirculation of line 169 is moved to a carbon dioxide recirculation compressor 170 to provide a compressed carbon dioxide recirculation flow for line 172, which is then moved to the low-pressure steam generator 175 and the second cooler 180 as described above. The heater 167 is advantageously located downstream of the first KOD 163 to allow for greater water condensation and separation of water in the KOD.

[0047] In the second KOD 184, water is separated from the cooled carbon dioxide recirculation flow in line 182 to provide a dry carbon dioxide recirculation flow, which is taken out from the top of the KOD to line 186. Water is taken out from the bottom of the second KOD 184 as flow 187. The dry carbon dioxide recirculation flow in line 186 is heat-exchanged with the filtered reactor outflow flow in line 152 in heat exchanger 190 to provide a preheated dry carbon dioxide recirculation flow in line 194. The preheated dry carbon dioxide recirculation flow in line 194 is mixed with the oxygen flow in line 104 in mixer 196 and then moved to regenerator unit 120. In some embodiments, a deoxygenation operation may be included in the separation section 111 or decontamination reactor 140 to meet specifications regarding the use of carbon dioxide.

[0048] Referring here to Figure 2, another exemplary embodiment of the process and apparatus for regenerating a catalyst from a fluid catalytic process is discussed with reference to process and apparatus 201. The elements of Figure 2 may have the same configuration as those of Figure 1, each having the same reference numerals and similar operating conditions. The fluid catalytic process shown in Figure 2 is an FCC process operating under complete combustion conditions. Therefore, the heat recovery section 125 does not have a CO combustor. The heat recovery section 125 includes HRSG 129.

[0049] The carbon dioxide-rich oxidizing flow from line 197 is moved to an FCC regenerator unit 120 operating under complete combustion conditions. From the regenerator unit 120, the carbon dioxide-rich flue gas flow from line 122 is taken out. The carbon dioxide-rich flue gas flow from line 122 is moved to a heat recovery section 125 to recover heat from the carbon dioxide-rich flue gas flow of line 122. In an exemplary embodiment, the heat recovery section 125 is HRSG 129'. HRSG 129' includes a superheated steam section 124 and a saturated steam section 130. The carbon dioxide-rich flue gas flow from line 122 is moved to the superheated steam section 124 of HRSG 129' to transfer heat to the partial steam flow of line 138, generating the superheated steam flow of line 126' and the heat-exchanged carbon dioxide-rich flue gas flow of line 128. The heat-exchanged carbon dioxide-rich flue gas flow of line 128 is sent to the saturated steam section 130 of HRSG 129'. In the saturated steam section 130, the boiler feedwater flow 127 is heated by the heat-exchanged carbon dioxide-rich flue gas flow of line 128 to form the saturated steam flow of line 134 and the partially cooled carbon dioxide-rich flue gas flow of line 132'. The condensed flow of line 133 is taken out of the saturated steam section 130. The partial steam flow of line 138 of the saturated steam flow 134 is sent to the HRSG superheated steam section 124 for superheating. The remaining steam of line 136 of the saturated steam flow of line 134 can be sent to other parts of the plant for use as needed. The partially cooled carbon dioxide-rich flue gas flow of line 132' is taken out of the saturated steam section 130 and moved to the decontamination reactor 140. The dried reactant 131 may be mixed with the partially cooled carbon dioxide-rich flue gas flow of line 132' to provide the mixed flow of line 137'. The mixed flow of line 137' is moved to the decontamination reactor 140. The recycled filtration material from line 156 may be recycled along with the mixed flow in line 137' and sent to the decontamination reactor 140 in line 139'. The remainder of the process is the same as described in Figure 1.

[0050] Another exemplary embodiment of the process and apparatus for regenerating a catalyst from a fluid catalytic process is discussed with reference to process and apparatus 301 shown in Figure 3. The elements of Figure 2 may have the same configuration as in Figure 2, each having the same reference numeral and similar operating conditions. The process and apparatus for regenerating a catalyst from a fluid catalytic process shown in Figure 3 comprises, in addition to the elements shown in Figure 2, a third stage separator (TSS) (210) and a flue gas expander (220).

[0051] The carbon dioxide-rich flue gas flow in line 122 is moved to TSS 210 to separate catalyst fine particles from the underflow flow in line 214. The carbon dioxide-rich flue gas flow with reduced catalyst fine particles is separated from TSS 210 into the overflow flow in line 212. The catalyst fine particles from the underflow flow in line 214 from TSS 210 are further concentrated in the underflow flow of line 214. The underflow flow in line 214 from TSS 210 is moved directly to the decontamination reactor 140. In an exemplary embodiment, the underflow flow in line 214 is combined with the partially cooled carbon dioxide-rich flue gas flow in line 132'' to provide a combined partially cooled carbon dioxide-rich flue gas flow in line 137'', which is moved to the decontamination reactor 140. In another exemplary embodiment, the partially cooled carbon dioxide-rich flue gas flow in line 132'' and the underflow flow in line 214 are moved separately to the decontamination reactor 140. The recirculated filter material from line 156 may be recirculated with the combined partially cooled carbon dioxide-rich flue gas flow in line 137'' and sent to the decontamination reactor 140 in line 139''. Catalyst fine particles from the underflow flow in line 214 are separated in filter section 150. The separated catalyst fine particles are removed from filter section 150 in line 155. Thus, this process discloses a direct integration between the TSS of the FCC process and the decontamination reactor 140 and / or filter section 150.

[0052] Returning to TSS210, the carbon dioxide-rich flue gas flow, with catalyst particles reduced in the overflow flow of line 212, is moved to the flue gas expander 220, where energy is extracted in the form of work and / or electricity, as described herein. In an exemplary embodiment, the expander 220 is coupled with a generator for blue power generation. After power generation, the overflow flow of line 222 from the flue gas expander 220 is moved to the heat recovery section 125. The remainder of the process is the same as described in Figure 2.

[0053] Another exemplary embodiment of the process and apparatus for regenerating a catalyst from a fluid catalyst process is discussed with reference to the process and apparatus 401 shown in Figure 4. The elements of Figure 4 may have the same configuration as those of Figure 3, each having the same reference numeral and similar operating conditions. The process and apparatus for regenerating a catalyst from a fluid catalyst process shown in Figure 4 includes, in addition to the elements shown in Figure 3, an oxygen source 90 for providing an oxygen stream 104.

[0054] In one embodiment, the oxygen source 90 for providing the oxygen flow 104 can be selected from an air separation unit (ASU) or an electrolytic cell. In an exemplary embodiment, the oxygen source 90 is an electrolytic cell 90.

[0055] Examples of electrolytic cells 90 include, but are not limited to, polymer electrolyte membranes / proton exchange membranes (PEM / PEMEC), alkaline electrolysis cells (AEC), anion exchange membranes (AEM), and solid oxide electrolysis cells (SOE / SOEC). According to this disclosure, useful materials produced in the fluid catalyst process may be used in the electrolytic section of the electrolytic cell 90. Specifically, electricity generated in the flue gas expander 220, the superheated vapor flow in line 126', and the saturated vapor flow 136 from HRSG 130 can be used in the electrolytic cell 90. In PEM, AEC, AEM, and SOEC electrolytic cells, electricity generated in the power recovery section may be used. In addition, in the SOEC electrolytic cell, heat in the form of vapor may be used in the SOEC to reduce the need for useful materials produced and transported to the process and apparatus 401. In the SOEC electrolytic cell, 25% to 30% of the total energy requirement may be supplied by heat. In exemplary embodiments, heat generated from the FCC regenerator flue gas from the FCC unit may be supplied to the SOEC electrolytic cell. Apart from extracting heat generated from the FCC regenerator flue gas, other heat sources, such as heat extracted from the top of the main column of the FCC unit, are also envisioned for integration. Furthermore, apart from using electricity to decompose water, electricity generated in process units such as those disclosed herein may also be used for compression for electrolytic cells such as AEC, AEM, and PEM electrolytic cells. The electrolytic cell may use electricity generated in an expander turbine installed in the FCC regenerator flue gas section of the FCC unit as described herein, located upstream of the steam boiler and downstream of the TSS210. In exemplary embodiments, the electrolytic cell 90 may use a portion of the electricity generated from the flue gas expander 220. In another exemplary embodiment, the electrolytic cell 90 may use thermal energy or steam generated in the FCC process.

[0056] Referring to Figure 4, the oxygen source 90 is the electrolytic cell 90. The electrolytic cell 90 may be selected from one or more electrolytic cells, including but not limited to high-molecular-weight electrolyte membranes / proton exchange membranes (PEM / PEMEC), alkaline electrolytic cells (AEC), anion exchange membranes (AEM), and solid oxide electrolytic cells (SOE / SOEC), as described above. The airflow from line 92 and the waterflow from line 94 are supplied to the electrolytic cell 90. Heat 96 is also supplied to the electrolytic cell 90 from any suitable heat source. In an exemplary embodiment, the heat 96 to the electrolytic cell 90 is supplied from any suitable process unit of the FCC unit. However, the heat to the electrolytic cell 90 can be supplied from any other heat source. Various useful materials produced in the FCC unit can be used in the electrolytic cell 90. In this embodiment, the electricity from line 224 from the flue gas expander 220, the superheated steam flow from line 126' from the superheated steam section 124 of HRSG129', and the saturated steam flow from line 136 from the saturated steam section 130 of HRSG129' are transferred to the electrolytic cell 90. The hydrogen produced in the electrolytic cell 90 can be taken out in line 98. The oxygen flow is taken out from the electrolytic cell 90 in line 104 and transferred to the mixer 196. The remainder of the process is the same as described in Figure 3.

[0057] To maintain the same volumetric flow rate as in the basic case, the temperature inside the regenerator unit 120 may decrease as a result of introducing more mass of inert gas into the regenerator unit 120 due to the increased molecular weight of carbon dioxide compared to air, which is mostly nitrogen. To keep the regenerator temperature constant, the following means may be used: a) installing an electric heating coil inside the regenerator and using electricity generated in the process or from any source; b) installing an electric heater to further heat the preheated carbon dioxide recirculation flow of line 194 and using electricity generated in the process or from any source; c) directly burning fuel gas and / or natural gas inside the regenerator; d) continuously burning a direct combustion air heater; or e) burning torch oil and / or FCC slurry oil inside the FCC regenerator. Using electricity to heat the coils inside the regenerator unit is a more sustainable and environmentally friendly means. The process includes using electricity generated from the FCC process disclosed above as a heat source for the heating coils inside the regenerator unit 120. According to an exemplary embodiment, a portion of the electricity (not shown) from line 224 of the flue gas expander 220 can be used to heat the coils in the regenerator unit 120. Alternatively, heat and / or electricity from any suitable renewable energy source or fuel gas stream may also be used in the regenerator unit 120.

[0058] Another exemplary embodiment of a process and apparatus for regenerating a catalyst from a fluid catalyst process is discussed with reference to a process and apparatus 501 as shown in Figure 5. The elements of Figure 5 may have the same configuration as those of Figure 4, each having the same reference numeral and similar operating conditions. The process and apparatus for regenerating a catalyst from a fluid catalyst process as shown in Figure 5 includes, in addition to the elements shown in Figure 4, a methanol synthesis unit 80 for providing a methanol flow 86.

[0059] According to the process and apparatus 501 shown in Figure 5, the separated carbon dioxide stream from line 168 may be moved to a methanol synthesis unit 340 to provide a methanol stream 342. In the process and apparatus 501 having a methanol synthesis unit 340 as shown in Figure 5, the regenerator unit 120 may be a partial combustion unit or a complete combustion unit. When the regenerator unit 120 operates in partial combustion, the CO present in the flue gas is oxidized to CO2 before heat recovery, contaminant removal, etc. In the regenerator unit 120 under partial combustion mode as described herein, the flue gas stream from line 122 is sent to the CO combustor 124 to oxidize carbon monoxide to CO2.

[0060] Methanol may be produced from methanol synthesis unit 80 by hydrogenating carbon dioxide on a methanol synthesis catalyst. Suitable methanol synthesis catalysts may be zinc oxide and copper on an alumina support. Synthesis conditions include a temperature of 200–300°C and a pressure of 3.5–10 MPa. Reaction equilibrium typically requires the separation of methanol and the recycling of unreacted reagents into the synthesis reaction. The methanol stream is provided on line 86. The methanol stream on line 86 may contain methanol, dimethyl ether, ethanol, or a combination thereof.

[0061] The carbon dioxide stream for methanol synthesis on line 168 may require preparation for use in methanol synthesis. The methanol synthesis carbon dioxide stream should be compressed to the methanol synthesis pressure. However, the methanol synthesis carbon dioxide stream on line 168 is SO x NO x For the removal of trace amounts of contaminants such as NH3, O2, and H2O, treatment in a pressure swing adsorption (PSA) unit or a thermal swing adsorption (TSA) unit may be required. Other particulate matter may be removed in the contaminant removal unit 190. Trace amounts may be removed from the separated carbon dioxide stream 168 to isolate CO2, which may then be transferred to the methanol synthesis unit 80.

[0062] According to the exemplary embodiment shown in Figure 5, the methanol synthesis carbon dioxide stream in line 168 may be compressed in the processing compressor 310 to an intermediate pressure suitable for contaminant removal. The compressed synthesis carbon dioxide stream in line 312 may be supplied to the contaminant removal unit 320 for contaminant removal. The decontaminated carbon dioxide stream in line 322 exits the contaminant removal unit 320. The storage carbon dioxide stream in line 324 may be collected for storage from the decontaminated carbon dioxide stream in line 322. The decontaminated synthesis carbon dioxide stream may be collected in line 326 to the methanol synthesis unit 340.

[0063] Prior to methanol synthesis, the contaminant-free synthetic carbon dioxide stream from line 326 may be further compressed to the synthesis pressure in the synthesis compressor 330. The methanol stream is supplied to line 342 by supplying the synthetic carbon dioxide stream to the methanol synthesis unit 340 in line 332. The hydrogen in line 334 is also moved to the methanol synthesis unit 340. According to embodiments of this disclosure, the hydrogen in line 334 may be selected from either blue hydrogen or green hydrogen, or both. According to an exemplary embodiment, the hydrogen in line 334 is blue hydrogen. According to another exemplary embodiment, the hydrogen in line 334 is green hydrogen. The methanol stream in line 342 is withdrawn from the methanol synthesis unit 340.

[0064] Any of the lines, conduits, units, devices, containers, surrounding environments, zones, or similar entities described above may be equipped with one or more monitoring components, including sensors, measuring devices, data acquisition devices, or data transmission devices. Signals, process, or state measurements, as well as data, from the monitoring components can be used to monitor conditions within, around, and on process equipment. Signals, measurements, and / or data generated or recorded by the monitoring components may be collected, processed, and / or transmitted via one or more networks or connections, which may be private or public, general or specific, direct or indirect, wired or wireless, encrypted or unencrypted, and / or a combination thereof. This specification is not intended to limit us in this respect. Furthermore, the figures may include one or more exemplary sensors placed on one or more conduits. Nevertheless, sensors may be present on each flow so that corresponding parameters can be controlled accordingly.

[0065] Signals, measurements, and / or data generated or recorded by monitoring components may be transmitted to one or more computing devices or systems. A computing device or system may include at least one processor and memory for storing computer-readable instructions that, when executed by at least one processor, cause one or more computing devices to perform a process that may include one or more steps. For example, one or more computing devices may be configured to receive data from one or more monitoring components relating to at least one part of equipment associated with a process. One or more computing devices or systems may be configured to analyze the data. Based on the analysis of the data, one or more computing devices or systems may be configured to determine one or more recommended adjustments to one or more parameters of one or more processes described herein. One or more computing devices or systems may be configured to transmit encrypted or unencrypted data containing one or more recommended adjustments to one or more parameters of one or more processes described herein. [Examples]

[0066] A comparative analysis demonstrated that dry cleaning with thermal integration for carbon dioxide recirculation, as disclosed in this process, has lower operating costs compared to wet cleaning without thermal integration for carbon dioxide recirculation. The results are shown in Tables A and B.

[0067] [Table 1]

[0068] [Table 2] * A CO2 credit of $35 / MT was taken into consideration.

[0069] From the table above, it is clear that a process including dry cleaning with thermal integration for carbon dioxide recirculation flows provides a net operating cost reduction of $6.46 - 1.11 = $5.35 million per year, which is almost the same capital expenditure as wet cleaning without thermal integration for carbon dioxide recirculation flows.

[0070] Specific Embodiments The following will be explained in conjunction with specific embodiments, but it should be understood that this explanation is intended to illustrate the scope of the above-mentioned description and the attached claims, and is not intended to limit them.

[0071] A first embodiment of the present disclosure is a process for regenerating a catalyst from a fluid catalytic process, comprising: providing an oxygen stream and a preheated carbon dioxide recirculation stream; mixing the oxygen stream and the preheated carbon dioxide recirculation stream to provide a carbon dioxide-rich oxidation stream; moving the carbon dioxide-rich oxidation stream to a regenerator unit to provide a carbon dioxide-rich flue gas stream; reacting one or more sulfur-containing compounds, nitrogen-containing compounds, or both in the carbon dioxide-rich flue gas stream with reactants in a decontamination reactor to form a reactor outflow stream containing reactant salts; filtering the reactor outflow stream to remove reactant salts and catalyst fines to produce a filtered reactor outflow stream; and collecting a carbon dioxide recirculation stream from the filtered reactor outflow stream. An embodiment of the present disclosure is one or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, further comprising preheating the carbon dioxide recirculation stream by heat exchange with the filtered reactor outflow stream to provide a preheated carbon dioxide recirculation stream. One embodiment of the present disclosure is any or all of the embodiments from the preceding embodiments of this paragraph to the first embodiments of this paragraph, wherein the reactants are in a dry form. One embodiment of the present disclosure is any or all of the embodiments from the preceding embodiments of this paragraph to the first embodiments of this paragraph, wherein the decontamination reactor operates at a temperature of 200°C to 600°C to react the reactants with one or more sulfur-containing compounds, nitrogen-containing compounds, or both of the carbon dioxide-rich flue gas stream. One embodiment of the present disclosure is any or all of the embodiments from the preceding embodiments of this paragraph to the first embodiments of this paragraph, wherein the carbon dioxide-rich oxidation stream contains an oxygen concentration of 30 mol% or less. One embodiment of the present disclosure is any or all of the embodiments from the preceding embodiments of this paragraph to the first embodiments of this paragraph, wherein the oxygen stream is supplied from an electrolytic cell or an air separation unit. One embodiment of the present disclosure is one or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, further comprising transferring heat from a carbon dioxide-rich flue gas flow to a boiler feedwater flow in a heat recovery section to form a partially cooled carbon dioxide-rich flue gas flow and steam flow.One embodiment of the present disclosure is one or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, wherein the heat recovery section is a waste heat recovery boiler (HRSG), and includes transferring heat from a carbon dioxide-rich flue gas flow to a boiler feedwater flow within the HRSG to form a partially cooled carbon dioxide-rich flue gas flow and steam flow, and moving the partially cooled carbon dioxide-rich flue gas flow to a decontamination reactor. One embodiment of the present disclosure is one or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, further including separating a carbon dioxide-rich oxidation flow into a first part and a second part, moving the first part of the carbon dioxide-rich oxidation flow to a regenerator unit, and moving the second part of the carbon dioxide-rich oxidation flow to a heat recovery section. One embodiment of the present disclosure is one or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, wherein the heat recovery section is a heat recovery section of a carbon monoxide (CO) boiler. One embodiment of the present disclosure is one or all of the preceding embodiments of this paragraph to the first embodiments of this paragraph, wherein the fluid catalyst process is selected from a fluid catalytic cracking (FCC) process, a methanol-to-olefin conversion (MTO) process, or both. One embodiment of the present disclosure is one or all of the preceding embodiments of this paragraph to the first embodiments of this paragraph, further comprising moving a carbon dioxide-rich flue gas flow to a third stage separator (TSS) to separate catalyst particles in the underflow flow and provide a carbon dioxide-rich flue gas flow with reduced catalyst particles in the overflow flow, generating electricity from the overflow flow in an expander, and moving the overflow flow to a heat recovery section. One embodiment of the present disclosure is one or all of the preceding embodiments of this paragraph to the first embodiments of this paragraph, wherein the reactant salt comprises one or more of sodium sulfate (Na2SO4), sodium carbonate (Na2CO3), and sodium nitrate (NaNO3).One embodiment of the present disclosure is one or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, further comprising: exchanging heat with a carbon dioxide recirculation flow in a heat exchanger for filtered reactor effluent to provide a preheated carbon dioxide recirculation flow and a partially cooled and filtered reactor effluent; optionally cooling the partially cooled and filtered reactor effluent to provide a cooled and filtered reactor effluent; separating water from the cooled and filtered reactor effluent to provide a carbon dioxide flow; and separating the carbon dioxide flow into a carbon dioxide recirculation flow and a separated carbon dioxide flow. One embodiment of the present disclosure is any or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, further comprising: compressing a carbon dioxide recirculation flow to provide a compressed carbon dioxide recirculation flow; moving the compressed carbon dioxide recirculation flow to a low-pressure steam generator to provide a low-pressure steam flow and a partially cooled carbon dioxide recirculation flow; cooling the partially cooled carbon dioxide recirculation flow to provide a cooled carbon dioxide recirculation flow; separating water from the cooled carbon dioxide recirculation flow to provide a dry carbon dioxide recirculation flow; preheating the dry carbon dioxide recirculation flow by heat exchange with a filtered reactor effluent flow to provide a preheated dry carbon dioxide recirculation flow; and moving the preheated dry carbon dioxide recirculation flow to a regenerator unit. One embodiment of the present disclosure is any or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, further comprising: heating a recirculation carbon dioxide flow to provide a warm carbon dioxide recirculation flow; and recirculating the warm carbon dioxide recirculation flow to a regenerator unit. One embodiment of the present disclosure is any or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, further comprising transferring the separated carbon dioxide stream to a methanol synthesis unit to provide a methanol stream. One embodiment of the present disclosure is any or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, in which the HRSG includes a superheated steam section and a saturated steam section.One embodiment of the present disclosure is one, any, or all of the first embodiments of this paragraph from the preceding embodiments of this paragraph, further comprising: moving a carbon dioxide-rich flue gas flow to the superheated steam section of an HRSG to generate a superheated steam flow and a heat-exchanged carbon dioxide-rich flue gas flow; moving a boiler feedwater flow and a heat-exchanged carbon dioxide-rich flue gas flow to the saturated steam section of an HRSG to form a partially cooled carbon dioxide-rich flue gas flow and a saturated steam flow; introducing at least a portion of the saturated steam flow into the superheated steam section; and superheating the saturated steam flow with the carbon dioxide-rich flue gas flow to generate a superheated steam flow.

[0072] A second embodiment of the present disclosure is a process for regenerating a catalyst from a fluid catalyst process, comprising: providing an oxygen stream and a preheated carbon dioxide recirculation stream; mixing the oxygen stream and the preheated carbon dioxide recirculation stream to provide a carbon dioxide-rich oxidation stream; separating the CO2-rich oxidation stream into a first and second portion; moving the first portion of the carbon dioxide-rich oxidation stream to a regenerator unit to provide a carbon dioxide-rich flue gas stream; moving the second portion of the CO2-rich oxidation stream to a heat recovery section to provide a partially cooled carbon dioxide-rich flue gas stream and vapor stream; reacting one or more sulfur-containing compounds, nitrogen-containing compounds, or both in the partially cooled carbon dioxide-rich flue gas stream with reactants in a decontamination reactor to form a reactor outflow stream containing reactant salts; filtering the reactor outflow stream to remove reactant salts and catalyst fines to produce filtered reactor outflow stream; and collecting a carbon dioxide recirculation stream from the filtered reactor outflow stream.

[0073] A third embodiment of the present disclosure is a apparatus for regenerating a catalyst, comprising: a heat recovery section including a superheated steam section and a saturated steam section; a superheated steam section having a flue gas inlet, a flue gas outlet, a saturated steam inlet, and a superheated steam outlet; a saturated steam section having a flue gas inlet, a flue gas outlet, a boiler feedwater inlet, and a saturated steam outlet; a saturated steam section having a flue gas inlet, a flue gas outlet, a boiler feedwater inlet, and a saturated steam outlet; a decontamination reactor having a flue gas inlet, a flue gas outlet, and a reactant inlet; a heat recovery section including a superheated steam section and a saturated steam section; a superheated steam section having a flue gas inlet, a flue gas outlet, a saturated steam outlet, and a reactant inlet; and a saturated steam section having a flue gas inlet, a flue gas outlet, and a reactant inlet. The apparatus for regenerating a catalyst comprises: a decontamination reactor, the flue gas inlet of the decontamination reactor being in fluid communication with the flue gas outlet of a saturated steam section; a filter section having a flue gas inlet, a flue gas outlet, and a filter material outlet, the flue gas inlet of the filter section being in fluid communication with the flue gas outlet of the decontamination reactor inlet; a heat exchanger having a flue gas inlet and a flue gas outlet, the flue gas inlet of the heat exchanger being in fluid communication with the flue gas outlet of the filter section; and a carbon dioxide separation unit being in fluid communication with the flue gas outlet of the heat exchanger, the carbon dioxide separation unit being in thermal communication with the flue gas outlet of the filter section via a carbon dioxide recirculation flow within the heat exchanger.

[0074] Without further detail, it is expected that a person skilled in the art can use the foregoing description to the fullest extent without departing from the spirit and scope of the disclosure, and can easily identify the essential characteristics of the disclosure, and can make various changes and modifications to the disclosure to suit various uses and conditions. Accordingly, the prior preferred specific embodiments should be interpreted as merely illustrative examples and not in any way limiting the remainder of the disclosure, but are intended to cover various modifications and equivalent configurations that fall within the scope of the appended claims.

[0075] In the above, all temperatures are given in degrees Celsius, and all parts and percentages are based on weight unless otherwise indicated.

Claims

1. A process for regenerating catalysts from a fluid catalyst process, To provide an oxygen flow and a preheated carbon dioxide recirculation flow, The oxygen stream and the preheated carbon dioxide recirculation stream are mixed to provide a carbon dioxide-rich oxidation stream. The carbon dioxide-rich oxidation flow is moved to the regenerator unit to provide a carbon dioxide-rich flue gas flow. The process involves reacting one or more of the sulfur-containing compounds, nitrogen-containing compounds, or both of the carbon dioxide-rich flue gas stream with reactants in a decontamination reactor to form a reactor outflow stream containing reactant salts. The reactor effluent is filtered to remove the reactant salts and catalyst fine powders, thereby producing filtered reactor effluent. A process comprising collecting a recirculated carbon dioxide flow from the filtered reactor effluent.

2. A process for regenerating catalysts from a fluid catalyst process, To provide an oxygen flow and a preheated carbon dioxide recirculation flow, The oxygen stream and the preheated carbon dioxide recirculation stream are mixed to provide a carbon dioxide-rich oxidation stream. The carbon dioxide-rich oxidation flow is separated into a first portion and a second portion, The first portion of the carbon dioxide-rich oxidation flow is moved to the regenerator unit to provide a carbon dioxide-rich flue gas flow. The second portion of the carbon dioxide-rich oxidation flow is moved to the heat recovery section to provide a partially cooled carbon dioxide-rich flue gas flow and vapor flow. The process involves reacting one or more sulfur-containing compounds, nitrogen-containing compounds, or both in the partially cooled carbon dioxide-rich flue gas stream with reactants in the decontamination reactor to form a reactor outflow stream containing reactant salts. The reactor effluent is filtered to remove the reactant salts and catalyst fine powders, thereby producing filtered reactor effluent. A process for regenerating a catalyst from a fluid catalyst process, comprising taking a recirculated carbon dioxide flow from the filtered reactor effluent.

3. A device for regenerating catalysts, A regenerator unit having an outlet, A heat recovery section including a superheated steam section and a saturated steam section, A superheated steam section having a flue gas inlet, a flue gas outlet, a saturated steam inlet, and a superheated steam outlet, wherein the flue gas inlet of the superheated steam section is in fluid communication with the outlet of the regenerator unit, A saturated steam section having a flue gas inlet, a flue gas outlet, a boiler feedwater inlet, and a saturated steam outlet, wherein the flue gas inlet of the saturated steam section is in fluid communication with the flue gas outlet of the superheated steam section, and the saturated steam outlet of the saturated steam section is in fluid communication with the saturated steam inlet of the superheated steam section, A decontamination reactor having a flue gas inlet, a flue gas outlet, and a reactant inlet, wherein the flue gas inlet of the decontamination reactor is in fluid communication with the flue gas outlet of the saturated steam section, A filter section having a flue gas inlet, a flue gas outlet, and a filter material outlet, wherein the flue gas inlet of the filter section is in fluid communication with the flue gas outlet of the decontamination reactor inlet, A heat exchanger having a flue gas inlet and a flue gas outlet, wherein the flue gas inlet of the heat exchanger is in fluid communication with the flue gas outlet of the filter section, A device for regenerating a catalyst, comprising: a carbon dioxide separation unit that fluidly communicates with the flue gas outlet of the heat exchanger, wherein the carbon dioxide separation unit is in thermal communication with the flue gas outlet of the filter section via a carbon dioxide recirculation flow within the heat exchanger.

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