Process for regenerating a catalyst from a fluidized catalyst process

Abstract

A process for regenerating a catalyst from a fluidized catalyst 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. Moving the carbon dioxide-rich oxidation stream to a regenerator unit to provide a carbon dioxide-rich flue gas stream. Reacting one or more of a sulfur-containing compound, a nitrogen-containing compound, or both in the carbon dioxide-rich flue gas stream with reactants in a scrubbing reactor to form a reactor effluent stream containing reactant salts. Filtering the reactor effluent stream to remove reactant salts and catalyst fines to produce a filtered reactor effluent stream. Taking a carbon dioxide recycle stream 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 / 485,193 filed on February 15, 2023, and U.S. Provisional Patent Application No. 18 / 144,785 filed on May 8, 2023, the entire contents of which are incorporated herein by reference.

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

Background Art

[0003] Catalytic cracking can produce various products from larger hydrocarbons. In many cases, a feedstock of heavy hydrocarbons such as vacuum gas oil is provided 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 composed of finely divided particulate matter within a fluidized reaction zone. The reactions in catalytic cracking, in contrast to hydrocracking, are carried out without substantial addition or consumption of hydrogen. As the cracking reactions proceed, a significant amount of high-carbonaceous material called coke deposits on the catalyst. The high-temperature regeneration operation within the regenerator zone burns off the coke from the catalyst. The coke-containing catalyst, herein called the coked catalyst, is continuously removed from the reaction zone and replaced by essentially coke-free catalyst from the regenerator zone. The fluidization of the catalyst particles by various gas flows enables the transport of the catalyst between the reaction zone and the regenerator zone. The spent catalyst from the reaction zone can be completely or partially regenerated in the regenerator zone.

[0005] The common purpose of these configurations is to maximize the product yield from the reactor while minimizing the operating and equipment costs. Optimization of the feedstock conversion typically requires the essentially complete removal of coke from the catalyst. This essentially complete removal of coke from the catalyst is often referred to as complete regeneration. Complete regeneration produces a catalyst having less than 0.1 wt%, preferably less than 0.05 wt% coke. To obtain complete regeneration, the catalyst must be contacted with oxygen at high temperature for a residence time sufficient to allow for complete combustion.

[0006] Conventional regenerators typically include a vessel having a coked catalyst inlet, a regenerated catalyst outlet, and a combustion gas distributor for supplying air or other oxygen-containing gas to a catalyst bed present within the vessel. A cyclone separator removes catalyst entrained in the flue gas before the flue gas exits the regenerator.

[0007] Alternative methods are also used for the production of light olefins. In one approach, hydrocarbon oxides, more specifically methanol or dimethyl ether, are used as alternative feedstocks for producing light olefin products. When the oxides are formed, the process involves catalytically converting an oxide such as methanol to the desired light olefin products in a methanol to olefin (MTO) process. In the MTO process, a carbonaceous material, i.e., coke, deposits 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 where a 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 the desired amount of carbonaceous material to be removed from the catalyst by combustion. In some cases, it is advantageous to only partially regenerate the catalyst, for example, removing 30 to 80 wt% of the carbonaceous material.

[0008] The flue gas formed by burning coke in the regenerator is treated for the removal of fluids and the conversion of carbon monoxide (CO), and then the flue gas is typically released into the atmosphere. Further, incomplete combustion to carbon monoxide can result from insufficient fluidization or aeration of the coked catalyst in the regenerator, or insufficient distribution of the coked catalyst into the regenerator. Generally, the flue gas exiting the regenerator contains carbon monoxide, carbon dioxide, nitrogen, and water, along with minor amounts of other species. Flue gas treatment methods are effective but have high capital and operating costs.

[0009] Conventional treatment of flue gas from the FCC unit and the MTO unit involves the use of wet gas scrubbing 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 feed water to produce steam and cool the flue gas. The flue gas is further cooled from 400 - 500°F to 140 - 194°F using water quench. The cooled flue gas is contacted with sodium hydroxide, which reacts with the sulfur compounds to form sodium sulfite (Na2SO3) and / or sodium sulfate (Na2SO4) and water, which are removed. Alternatively, other suitable reagents or seawater can be used to remove sulfur compounds in the flue gas. The flue gas can also be optionally treated to remove catalyst fines and other particulates. Next, the treated flue gas can be discharged to the atmosphere.

[0010] The capital cost of this system is high, and the operating costs associated with the use of sodium hydroxide or other reagents, water, electricity, flocculants, and slurry handling are also high. Furthermore, this system requires a large area and is maintenance-intensive. The wet scrubber process has high makeup water requirements due to water quenching and the use of an aqueous sodium hydroxide solution. This system is also plagued by corrosion problems associated with the use of sulfuric acid and concerns about spray nozzle fouling due to the presence of salts. A substantial amount of sensible heat energy is not recovered due to acid dew point limitations. Insufficient energy recovery results in high stack temperatures and an inadequate heat profile (quenching the boiler flue gas outlet to adiabatic saturation to enable wet sulfur removal and, in some cases, 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. Furthermore, there can be problems with sulfuric acid blue plumes caused by the formation of submicron aerosols and white plumes caused by water condensation when the flue gas is released into the atmosphere. After treatment, the treated flue gas is generally released into the atmosphere or sent for further element recovery from the flue gas.

[0011] Due to environmental concerns regarding greenhouse gas emissions, it is becoming increasingly important to separate greenhouse gases before releasing flue gas into the atmosphere. Carbon dioxide is the most important long-lived greenhouse gas in the Earth's atmosphere. Capturing carbon dioxide from flue gas is still expensive from both the perspective of capital expenditure and operating utility costs. In fluid catalytic processes, air is used to regenerate the spent catalyst. As a result of this operation, the carbon dioxide in FCC flue gas has a lower amount, in contrast to the amount of undesirable components from the perspective of carbon dioxide capture, and causes not only high capital expenditure due to the large volume of flue gas, but also high solvent circulation rates and large operating utility costs as a solvent regeneration load. Separately from this, flue gas requires large-scale flue gas treatment before carbon capture in order to meet strict specifications to avoid high solvent decomposition rates. This results in high capital expenditure and operating utility costs associated with various longer impurity removal operations. In addition, typically, wet gas scrubbers are used, which, in addition to problems related to insufficient energy recovery from flue gas, high makeup water, corrosion and contamination in the plant, difficulty in slurry handling, and white plumes as a result of water condensation upon release to the atmosphere, also pose a risk of blue plumes.

[0012] Therefore, an improved process for treating flue gas containing carbon dioxide is needed. Also needed are processes and apparatuses that reduce the capital expenditure and operating utility costs of the carbon dioxide capture section as a flue gas treatment section while improving energy efficiency and energy recovery. SUMMARY OF THE INVENTION

[0013] The present disclosure provides a process and apparatus for regenerating a catalyst from a fluid catalytic process. Generally, air is used in a regenerator to burn coke from a spent catalyst. Air has a large amount (79 mol%) of nitrogen, which results in a low carbon dioxide partial pressure. As a result, the amount of carbon dioxide in the FCC flue gas is reduced, such as to 15 - 25 mol%, and the remainder consists of undesirable components. The present process discloses providing a carbon dioxide-rich oxidizing stream to the regenerator instead of air. The flue gas from the regenerator by this process has an economically desirable amount of carbon dioxide from the perspective of carbon dioxide capture, compared to the undesirable components resulting from the use of air in the regenerator.

[0014] The present disclosure provides separating a carbon dioxide recycle stream from a flue gas stream, mixing the carbon dioxide recycle stream and an oxygen stream, and moving the carbon dioxide-rich oxidizing stream to a regenerator for burning coke from a spent catalyst. The carbon dioxide-rich oxidizing stream provides an atmosphere substantially free of nitrogen within the regenerator and reduces the amount of undesirable components in the flue gas from the perspective of carbon dioxide capture. A regeneration process substantially free of nitrogen enables a significant size reduction of the regenerator, flue gas treatment section, and carbon capture section. The present process and apparatus increase the capacity of existing units. The carbon dioxide-rich oxidizing stream provides conditions substantially free of nitrogen and improves the need for a high-temperature regenerator when air moves to the regenerator due to the high molar heat capacity of carbon dioxide compared to nitrogen gas.

[0015] Furthermore, the present process provides a dry scrubbing step for treating the flue gas. The dry scrubbing step avoids corrosion problems compared to a wet scrubbing step. The dry scrubbing step also eliminates the possibility of a blue / white plume resulting from water condensation and / or sulfuric acid aerosol in the wet scrubbing step. The present process also provides a wet scrubbing step for treating the flue gas. Also disclosed is the thermal integration of the flow between units, which provides a substantial increase in energy recovery.

Brief Description of the Drawings

[0016] Various embodiments are described below in conjunction with the following drawings, where like numbers indicate like elements.

Figure 1

Figure 2

Figure 3

Figure 4

Figure 5

[0017] Definitions The term "in communication" means that flow of material is operably permitted between the recited components.

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

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

[0020] The term "in direct communication" or "directly" means that the flow from the upstream component enters the downstream component without undergoing a compositional change by physical fractionation or chemical conversion by passing through a fractionation or conversion unit.

[0021] The term "column" means one or more distillation column(s) for separating one or more 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 fluidized 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 that can operate 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 catalytic process is disclosed. This process involves the use of a dry sorbent injection (DSI) unit to remove sulfur compounds from the flue gas generated from the regenerated catalyst from the fluid catalytic process. The fluid catalytic process can be any fluid catalytic process for regenerating a catalyst, including an FCC process or an MTO process. The flue gas from the regenerator of the fluid catalytic process is used to produce superheated steam and saturated steam. The flue gas is then sent to the DSI unit to remove sulfur compounds and is then cooled and dried as described in detail below. Since the flue gas temperature does not drop as much as in the case of a wet scrubber process, additional thermal energy can be recovered from the flue gas in the heat recovery exchanger.

[0026] By utilizing a dry sorbent injection (DSI) system, the sensible heat energy that could not be collected can be captured, substantially improving the energy efficiency of this process and avoiding a negative energy balance. The increase in energy efficiency achieved by utilizing a DSI system instead of a wet gas scrubber system can also be applied to any type of fluid catalytic process in which the flue gas is produced at an SOx concentration that exceeds environmental limits.

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

[0028] Furthermore, heat can be recovered from the flue gas either before or after the DSI in order to preheat the boiler feed water used in a heat recovery steam generator (HRSG) boiler and / or a catalyst cooler and / or a carbon monoxide (CO) combustor or combustors, thereby reducing or eliminating the potential for 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 exchanger reduces the risk of tube corrosion and significantly improves the reliability of the system. The disclosed process reduces or eliminates concerns due to corrosion from sulfuric acid. By avoiding operation in a corrosive regime, a stainless-steel flue gas scrubber is not required and the complete system can be made from carbon steel.

[0030] Since the DSI technology does not require water, which is considered a scarce resource, water usage by the system is significantly reduced. The process also eliminates concerns about nozzle fouling in wet gas scrubbers by avoiding the need to handle complex slurries, and avoids white plumes as a result of water condensation and blue plumes as a result of sulfuric acid aerosol emissions. Additionally, when using NaHCO3 as a DSI reactant, up to 21% NOx reduction can be achieved, while the pressure drop across the system can be as much as 50% lower.

[0031] When air is used as the combustion gas, a large amount of inert substances, particularly nitrogen in the end, in the regenerator flue gas, and the carbon dioxide partial pressure becomes even lower. This occupies unnecessary volume and increases the equipment size for the regenerator and downstream flue gas treatment equipment. Due to the low carbon dioxide partial pressure, the cost of carbon dioxide capture becomes relatively high, which may be the reason for the resistance of refiners to implementing carbon dioxide capture technology. This process replaces air with a carbon dioxide-rich oxidation stream containing carbon dioxide and up to 30 mol% oxygen. The carbon dioxide-rich oxidation stream containing carbon dioxide and oxygen significantly increases the carbon dioxide partial pressure in the flue gas and enables the reduction of capital expenditure and operating utility costs for carbon dioxide capture.

[0032] In the wet scrubbing process, the flue gas must be saturated by passing through a quench medium. Therefore, the flue gas after wet scrubbing is at a low temperature of 140 - 200°F. In comparison, dry scrubbing can be carried out at a higher temperature of 300 - 600°F. To reduce the total capital expenditure, it is proposed to recover heat / energy from the flue gas stream after dry scrubbing. This process recovers heat from the flue gas after dry scrubbing by a heat recovery exchanger. The heat recovery exchanger may be used for heat exchange with the carbon dioxide recycle stream, but the recycle carbon dioxide stream can be heated to the desired temperature level for transfer to the regenerator without the need for an external heat utility. Further, this process withdraws a carbon dioxide recycle stream from the flue gas stream after dry scrubbing.

[0033] In the FCC process, the flue gas from the regenerator generally moves to a third stage separator (TSS) to separate catalyst fines from the flue gas. A small amount of flue gas containing most of the catalyst fines is collected as the underflow stream from the TSS. The remainder of the flue gas is separated in the overflow stream from the TSS. The catalyst fines from the underflow stream from the TSS are further separated. The underflow stream from the TSS moves to a fourth stage separator to separate the catalyst fines. The TSS in the FCC process can be directly integrated with the filter section. Thus, the fourth stage separator for the underflow stream from the TSS can be omitted. Thus, the underflow stream from the TSS moves directly to the filter section for removal of catalyst fines. Also, energy can be extracted from the overflow stream from the TSS. The overflow stream from the TSS flows to an expander turbine where energy is extracted in the form of work. The expander may be connected to the main blower to provide power for blower operation, or the main blower may be driven by a separate electric motor or steam turbine, and the expander output may be used only for power generation. When the expander is connected 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 in starting. The steam turbine may be designed for continuous operation as an economic outlet for excess steam, or an inexpensive turbine that discharges to the atmosphere may be installed for use only during startup. In an exemplary embodiment, the expander is connected to a generator for blue electricity 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 in a CO combustor that generates high-pressure steam to form carbon dioxide. The flue gas is removed from the regenerator and fed into the CO combustor within the heat recovery section, where a combustion air stream is added to burn the flue gas, releasing heat that is recovered. The use of air in the CO combustor may also cause 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 other purges such as the air supplied to the CO combustor, the dry air (DA) purge point, and the fluffing air within the regenerator with a portion of a carbon dioxide-rich oxidation stream that includes oxygen and a recycled carbon dioxide stream. Thus, in the case of the FCC process, the carbon dioxide-rich oxidation stream is separated into a first portion and a second portion. The first portion of the carbon dioxide-rich oxidation stream is moved to the regenerator unit, and the second portion of the carbon dioxide-rich oxidation stream is moved to the heat recovery section.

[0035] The regenerator unit can 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% - 5% carbon monoxide, which is used as a primary fuel source in a downstream CO combustor or combustion chamber, where the flue gas is burned, releasing heat that is recovered. By operating the regenerator in partial combustion mode to maximize carbon monoxide yield, the unit limits the amount of heat released within the regenerator compared to completely burning the coke to carbon dioxide. This results in a lower regenerator temperature, enabling a higher catalyst-to-oil ratio within the FCC riser.

[0036] In FIG. 1, according to an exemplary embodiment, a process and apparatus 101 for regenerating a catalyst from a fluid catalytic process are shown. The apparatus for regenerating the catalyst comprises a regenerator unit 120, a heat recovery section 125, a decontamination reactor 140, a filter section 150, a heat exchanger 152, and a carbon dioxide separation section 111. One aspect of the present disclosure includes a process for regenerating a catalyst from a fluid catalytic process. This method includes supplying an oxygen stream into line 104. Typically, the oxygen stream is supplied from an air separation unit (ASU). However, the applicant has found that the oxygen stream in line 104 can be withdrawn from an electrolytic cell. The carbon dioxide recycle stream in line 166 is preheated in heater 167 to provide a preheated carbon dioxide recycle stream in line 169. The preheated carbon dioxide recycle stream in line 169 can be compressed in carbon dioxide recycle compressor 190, and the compressed preheated carbon dioxide recycle stream in line 194 may move to regenerator unit 120. The oxygen stream in line 104 and the carbon dioxide recycle stream in line 194 (presumably preheated and compressed) move 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 moves to regenerator unit 120. The spent catalyst stream from the fluid catalytic process in line 102 also moves to regenerator unit 120. In one aspect, the carbon dioxide-rich oxidation stream in line 197 contains an oxygen concentration of 30 mol% or less.

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

[0038] From the regenerator unit 120, a carbon dioxide-rich flue gas stream in line 122 is withdrawn. The carbon dioxide-rich flue gas stream in line 122 is typically at a high temperature, and heat can be recovered from the carbon dioxide-rich flue gas stream in line 122 before further processing. The carbon dioxide-rich flue gas stream in line 122 transfers heat from the carbon dioxide-rich flue gas stream in line 122 to the boiler feed water stream in line 127 and moves to the heat recovery section 125 to form a partially cooled carbon dioxide-rich flue gas stream in line 132 and a steam stream in line 126. The heat recovery section 125 may comprise an HRSG or a CO combustor and an HRSG. As described above herein, when the regenerator unit 120 is operating in a partial combustion state, a portion of the carbon dioxide-rich oxidation stream in line 197 moves to the CO combustor in line 199 to prevent nitrogen accumulation in the flue gas stream. The carbon dioxide-rich oxidation stream in line 197 is separated into a first portion in line 198 and a second portion in line 199. The first portion of the carbon dioxide-rich oxidation stream in line 198 moves to the regenerator unit 120, and the second portion of the carbon dioxide-rich oxidation stream in line 199 moves to the carbon monoxide combustor in the heat recovery section 125.

[0039] In the partial combustion operating state, the carbon dioxide-rich flue gas stream in line 122 is sent to the CO combustor 124 in the heat recovery section 125 together with the fuel gas stream 121 and the second portion of the carbon dioxide-rich oxidation stream in line 199 to oxidize the carbon monoxide present in the carbon dioxide-rich flue gas stream in line 122 to carbon dioxide. Then, the complete combustion stream from the carbon monoxide combustor 124 is sent to the HRSG unit 129 in the heat recovery section 125. In an exemplary embodiment, the flue gas outlet temperature of the FCC regenerator for a partial combustion or complete combustion FCC regenerator may be in the range of 670 °C to 740 °C or 650 °C to 700 °C. The flue gas temperature exiting the CO combustor 124 may be in the range of 890 °C to 1040 °C.

[0040] In the case of the full combustion regenerator unit 120, the heat recovery section 125 comprises only the HRSG unit 129 and there is no CO combustor 124. Thus, in the full combustion regenerator unit 120, the carbon dioxide-rich flue gas stream in line 122 is sent to the HRSG unit 129. The full combustion or partial combustion MTO regenerator can operate at temperatures in the range of 670 - 740 °C or 650 °C - 700 °C. In the HRSG, the hot flue gas is indirectly heat exchanged with the water in line 127 to produce the steam in line 126 and the condensate stream in line 133. The steam stream in line 126 and the condensate stream in line 133 are taken out from the HRSG unit 129. The partially cooled carbon dioxide-rich flue gas stream in line 132 is taken out from the heat recovery section 125. The partially cooled carbon dioxide-rich flue gas stream in line 132 is treated to remove impurities. The flue gas outlet temperature from the HRSG for the partial combustion FCC regenerator, or for the full combustion FCC or MTO process, may be in the range of 200 °C - 290 °C.

[0041] The partially cooled carbon dioxide-rich flue gas stream within line 132 moves to the decontamination reactor 140. The reactants within line 131 also move to the decontamination reactor 140. In certain embodiments, the reactants within line 131 are in a dry form. In some aspects, the partially cooled carbon dioxide-rich flue gas stream within line 132 from the heat recovery section 125 is mixed with the dry reactants 131 to provide a mixed stream within line 137, which is sent to the decontamination reactor 140. In the mixed stream 137, the reactants react with sulfur-containing compounds and / or nitrogen-containing compounds in the partially cooled carbon dioxide-rich flue gas stream within line 132 to form a reactor effluent stream containing reactant salts within line 142. The recirculated filtration material (described in detail later) within line 156 may be recirculated with the mixed stream within line 137 and sent to the decontamination reactor 140 within line 139. 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 of the sulfur-containing compounds, nitrogen-containing compounds, or both in the partially cooled carbon dioxide-rich flue gas stream within line 132 with the dry reactants 131. In another exemplary embodiment, the reactants 131 include 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 salts include one or more of sodium sulfate (Na2SO4), sodium carbonate (Na2CO3), and sodium nitrate (NaNO3). The reactor effluent stream containing reactant salts within line 142 moves to the filter section 150 for particle removal.

[0042] The filter section 150 removes particulate matter and fine powder from the reactor effluent stream within line 142. When the filter section 150 comprises an electrostatic precipitator, electricity is supplied to the filter section 150. The filter section 150 may also comprise a bag filter. The filter material from the filter section 150 may include sodium sulfate (Na2SO4), sodium nitrate (NaNO3), sodium nitrite (NaNO2), sodium carbonate (Na2CO3), and one or more of the catalyst fines that can be removed in the filter section 150. The filter material 154 can be removed from the process within line 155. Alternatively, or in addition thereto, the filter material may be recycled to the decontamination reactor 140 as recycled filter material within line 156 to increase the Na2CO3 conversion yield. The recycled filter material within line 156 may be recycled with the mixed stream within line 137 and sent to the decontamination reactor 140 within line 139. Thus, the reactant salts and catalyst fines are removed from the reactor effluent stream 142 within the filter section 150 to produce a filtered reactor effluent stream within line 151. The filtered reactor effluent stream within line 151 moves to the carbon dioxide separation section 111 to separate carbon dioxide from the filtered reactor effluent stream. The separation section 111 may comprise a heat exchanger 152, a cooler 160, a knock out drum (KOD) 163 for separation, and a compressor 190.

[0043] Since the reactants are used in a dry form, the filtered reactor effluent stream in line 151 still has a fairly high temperature. Heat / energy can still be recovered from the filtered reactor effluent stream in line 151. The filtered reactor effluent stream in line 151 can be moved through heat exchanger 152 to recover heat from the filtered reactor effluent stream and provide a partially cooled filtered reactor effluent stream in line 153. The partially cooled filtered reactor effluent stream in line 153 can be cooled in cooler 160 and move to knockout drum (KOD) 163. Cooler 160 can use cooling water and / or chilled water as a cooling medium. Alternatively, cooler 160 can be an air cooler. In some aspects of the present disclosure, cooler 160 may be optional and the filtered reactor effluent stream in line 151 can move directly to KOD 163 after heat recovery in heat exchanger 152.

[0044] In KOD163, water is separated from the cooled and filtered reactor effluent stream within line 162 to provide a carbon dioxide stream, which is withdrawn from the top of the KOD in line 164. From the bottom of KOD163, water is withdrawn in stream 165. This process recirculates the carbon dioxide stream in line 164 to the regenerator unit 120. Thus, some or all of the carbon dioxide stream in line 164 can be withdrawn and mixed with the oxygen stream 104 to provide a carbon dioxide-rich oxidation stream 197 for the regenerator unit 120. In certain embodiments, the carbon dioxide stream is separated into a carbon dioxide stream for recirculation in line 166 and a separated carbon dioxide stream in line 168. The separated carbon dioxide stream in line 168 may be withdrawn and sent for storage. The separated carbon dioxide stream in line 168 may require treatment in a pressure swing adsorption (PSA) unit or a thermal swing adsorption (TSA) unit to remove trace contaminants such as SOx, NOx, ammonia (NH3), oxygen (O2), and water (H2O). The separated carbon dioxide stream in line 168 may be treated accordingly and sent for storage. According to this process, the carbon dioxide stream for recirculation in line 166 may be further treated prior to recirculation to the regenerator unit 120.

[0045] Cooling and condensing the partially cooled and filtered reactor effluent stream in line 153 using cooler 160 can result in the formation of an aqueous phase. This can cause the formation of carbonic acid due to the reaction of carbon dioxide and water. The formation of carbonic acid can cause carbonic acid corrosion to heat exchanger 152, cooler 160, KOD 163, and other downstream equipment. Therefore, the metallurgy of cooler 160 and KOD 163 is appropriately selected to withstand any carbonic acid corrosion. According to certain embodiments of the present disclosure, heater 167 may be present upstream of carbon dioxide recycle compressor 190. In one aspect, the carbon dioxide stream for recirculation in line 166 can be heated in heater 167 to provide a preheated carbon dioxide recycle stream in line 194 for recirculation to regenerator unit 120. Heater 167 is advantageously located downstream of KOD 163 to allow for greater condensation of water within the KOD.

[0046] The heater 167 is used to raise the temperature of the carbon dioxide stream recirculating in line 166 to provide a preheated dry carbon dioxide recirculation stream in line 169, which moves to the carbon dioxide recirculation compressor 190. From the CO2 recirculation compressor 190, a compressed preheated dry CO2 recirculation stream in line 194 is withdrawn and moves to the mixer 196 to provide a CO2-rich oxidation stream in line 197. In the current scheme, water knockout occurs upstream of the carbon dioxide recirculation compressor 190. The current scheme includes a heat exchanger 152 and a cooler 160 for water removal and provides water level control in the circulating carbon dioxide loop. According to an exemplary embodiment, the carbon dioxide stream recirculating in line 166 moves through the heater 167, raising the temperature of the carbon dioxide stream 5 °C (9 °F) to 50 °C (90 °F) above the dew point of the carbon dioxide stream to avoid carbonic acid corrosion in any of the downstream equipment. The preheated dry carbon dioxide recirculation stream in line 169 from the heater 167 moves to the carbon dioxide recirculation compressor 190. From the carbon dioxide recirculation compressor 190, a compressed preheated dry carbon dioxide recirculation stream in line 194 is withdrawn and moves to the mixer 196 to provide a carbon dioxide-rich oxidation stream in line 197.

[0047] The compressed preheated dry carbon dioxide recirculation stream in line 194 moves to the regenerator unit 120 after mixing with the oxygen stream in line 104 in the mixer 196. In some embodiments, a deoxygenation operation can also be included in the separation section 111 or the decontamination reactor 140 to meet the specifications for the use of carbon dioxide.

[0048] Referring now to FIG. 2, another exemplary embodiment of a process and apparatus for regenerating a catalyst from a fluidized catalyst process is addressed with reference to process and apparatus 201. The elements of FIG. 2 may have the same configuration as those of FIG. 1, with each having the same reference number and similar operating conditions. The fluidized catalyst process shown in FIG. 2 is an FCC process operating under complete combustion conditions. Accordingly, the heat recovery section 125 does not have a carbon monoxide combustor. The heat recovery section 125 is provided with an HRSG 129.

[0049] The carbon dioxide-rich oxidation stream within line 197 moves to the FCC regenerator unit 120 operating under complete combustion conditions. From the regenerator unit 120, a carbon dioxide-rich flue gas stream within line 122 is withdrawn. The carbon dioxide-rich flue gas stream within line 122 moves to the heat recovery section 125 to recover heat from the carbon dioxide-rich flue gas stream within line 122. In an exemplary embodiment, the heat recovery section 125 is the HRSG129’. The HRSG129’ includes a superheated steam section 124 and a saturated steam section 130. The carbon dioxide-rich flue gas stream within line 122 moves to the superheated steam section 124 of the HRSG129’, transfers heat to a portion of the steam stream within line 138, and generates a superheated steam stream within line 126’ and a heat-exchanged carbon dioxide-rich flue gas stream within line 128. The heat-exchanged carbon dioxide-rich flue gas stream within line 128 is sent to the saturated steam section 130 of the HRSG129’. In the saturated steam section 130, the boiler feed water stream 127 is heated by the heat-exchanged carbon dioxide-rich flue gas stream within line 128 to form a saturated steam stream within line 134 and a partially cooled carbon dioxide-rich flue gas stream within line 132’. The condensate stream within line 133 is withdrawn from the saturated steam section 130. A portion of the steam stream within line 138 of the saturated steam stream 134 is sent to the HRSG superheated steam section 124 to be superheated. The remaining steam within line 136 of the saturated steam stream within line 134 can be sent to the remainder of the plant for use as needed. The partially cooled carbon dioxide-rich flue gas stream within line 132’ is withdrawn from the saturated steam section 130 and moves to the decontamination reactor 140. A dry reactant 131 can be mixed with the partially cooled carbon dioxide-rich flue gas stream within line 132’ to provide a mixed stream within line 137’. The mixed stream within line 137’ moves to the decontamination reactor 140. The recirculated filtration material within line 156 may be recirculated with the mixed stream within line 137’ and sent to the decontamination reactor 140 within line 139’. The remaining process is the same as that described in FIG. 1.

[0050] Yet another exemplary embodiment of a process and apparatus for regenerating a catalyst from a fluidized catalyst process is addressed with reference to the process and apparatus 301 shown in FIG. 3. The elements of FIG. 2 may have the same configuration as in FIG. 2, each having the same reference numeral and similar operating conditions. The process and apparatus for regenerating a catalyst from the fluidized catalyst process shown in FIG. 3 includes, in addition to the elements shown in FIG. 2, a third-stage separator TSS210 and a flue gas expander (220).

[0051] The carbon dioxide-rich flue gas stream within line 122 moves to TSS210 and separates catalyst fines in the underflow stream within line 214. The carbon dioxide-rich flue gas stream with reduced catalyst fines is separated into the overflow stream within line 212 from TSS210. The catalyst fines from the underflow stream within line 214 from TSS210 are further concentrated in the underflow stream within line 214. The underflow stream within line 214 from TSS210 moves directly to the decontamination reactor 140 after being mixed with the dried reactants within line 131 within line 137’’ and possibly after being mixed with the recycled filtration material within line 156 within line 139’’. In an exemplary embodiment, the underflow stream within line 214 is combined with the partially cooled carbon dioxide-rich flue gas stream within line 132’’ and the dried reactants within line 131 to provide a combined partially cooled carbon dioxide-rich flue gas stream within line 137’’ that moves to the decontamination reactor 140. In another exemplary embodiment, the partially cooled carbon dioxide-rich flue gas stream within line 132’’ and the underflow stream within line 214 each move to the decontamination reactor 140. The recycled filtration material within line 156 may be recycled with the combined partially cooled carbon dioxide-rich flue gas stream within line 137’’ and sent to the decontamination reactor 140 within line 139’. The catalyst fines from the underflow stream within line 214 are separated within the filter section 150. The separated catalyst fines are removed within line 155 from the filter section 150. A portion of the separated catalyst fines may be recycled within line 156 to the decontamination reactor 140 within line 139’’. Thus, the present process discloses a direct integration between the TSS of the FCC process and the decontamination reactor 140 and / or the filter section 150.

[0052] Returning to TSS210, the carbon dioxide-rich flue gas stream with reduced catalyst fines in the overflow stream within line 212 moves to flue gas expander 220 where, as described above herein, energy is extracted in the form of work and / or electricity. In an exemplary embodiment, expander 220 is coupled to a generator for blue electricity generation. After electricity generation, the exhausted overflow stream within line 222 from flue gas expander 220 moves to heat recovery section 125. The remaining process is the same as that described in FIG. 2.

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

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

[0055] As the electrolyzer 90, although not limited thereto, various types of electrolyzers including a polymer electrolyte membrane / proton exchange membrane (PEM / PEMEC), an alkaline electrolysis cell (AEC), an anion exchange membrane (AEM), and a solid oxide electrolysis cell (SOE / SOEC) can be used. According to the present disclosure, the utility generated in the fluidized catalyst process can be used in the electrolysis section of the electrolyzer 90. Specifically, the electricity generated in the flue gas expander 220, the superheated steam flow in line 126’, and the saturated steam flow 136 from the HRSG129’ can be used in the electrolyzer 90. In PEM, AEC, AEM, and SOEC electrolyzers, the electricity generated in the power recovery section can be used. In addition, in the SOEC electrolyte, heat in the form of steam can be used in the SOEC to reduce the need for the utility generated and exported in the process and apparatus 401. In the SOEC electrolyzer, 25% to 30% of the total energy requirement can be supplied by heat. In an exemplary embodiment, the heat generated from the FCC regenerator flue gas from the FCC unit can be supplied to the SOEC electrolyzer. Apart from collecting the heat generated from the FCC regenerator flue gas, other heat sources such as the heat collected from the main column top of the FCC unit are also envisioned for integration. Furthermore, apart from using electricity to split water, the electricity generated in the process units as disclosed previously can also be used for compression for electrolyzers such as AEC, AEM, and PEM electrolyzers. The electrolyzer can use the electricity generated in the expander turbine installed in the FCC regenerator flue gas section of the FCC unit described above herein, upstream of the steam boiler and downstream of the TSS210. In an exemplary embodiment, the electrolyzer 90 can use a portion of the electricity generated from the flue gas expander 220.In another exemplary embodiment, the electrolyzer 90 can use the thermal energy or steam generated in the FCC process.

[0056] Referring to FIG. 4, the oxygen source 90 is the electrolyzer 90. The electrolyzer 90 can be selected from one or more electrolyzers including, but not limited to, a polymer electrolyte membrane / proton exchange membrane (PEM / PEMEC), an alkaline electrolytic cell (AEC), an anion exchange membrane (AEM), and a solid oxide electrolytic cell (SOE / SOEC) as previously described. An air stream in line 92 and a water stream in line 94 are supplied to the electrolyzer 90. Heat 96 is also provided to the electrolyzer 90 from any suitable heat source. In an exemplary embodiment, the heat 96 to the electrolyzer 90 is supplied from any suitable process unit of the FCC unit. However, the heat to the electrolyzer 90 can be supplied from any other heat source. Various utilities generated within the FCC unit can be used in the electrolyzer 90. In a plurality of embodiments, the electricity in line 224 from the flue gas expander 220, the superheated steam flow in line 126' from the superheated steam section 124 of the HRSG 129', and the saturated steam flow in line 136 of the saturated steam section 130 of the HRSG 129' move to the electrolyzer 90. The hydrogen generated within the electrolyzer 90 can be withdrawn in line 98. The oxygen stream is withdrawn from the electrolyzer 90 in line 104 and moves to the mixer 196. The remaining process is the same as that described in FIG. 3.

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

[0058] Yet another exemplary embodiment of a process and apparatus for regenerating a catalyst from a fluid catalytic process is addressed with reference to the process and apparatus 501 shown in FIG. 5. The elements of FIG. 5 may have the same configuration as in FIG. 4, each having the same reference numbers and similar operating conditions. The process and apparatus for regenerating a catalyst from the fluid catalytic process shown in FIG. 5 includes, in addition to the elements shown in FIG. 4, a methanol synthesis unit 80 for providing a methanol stream 86.

[0059] According to the method and apparatus 501 shown in FIG. 5, the carbon dioxide stream in line 168 can be moved to the methanol synthesis unit 80 to provide the methanol stream 86. In the case of the process and apparatus 501 having the methanol synthesis unit 80 shown in FIG. 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 and pollutant removal. As described above herein for the regenerator unit 120 in partial combustion mode, the flue gas stream in line 122 is sent to the CO combustor 124 to oxidize carbon monoxide to CO2.

[0060] Methanol can be produced from the methanol synthesis unit 80 by hydrogenating carbon dioxide over a methanol synthesis catalyst. A suitable methanol synthesis catalyst may be copper on a zinc oxide and alumina support. The synthesis conditions include a temperature of 200 - 300 °C and 3.5 - 10 MPa. The reaction equilibrium typically requires methanol separation and recycle of unreacted reagents back to the synthesis reaction. The methanol stream is provided in line 86. The methanol stream in line 86 may contain methanol, dimethyl ether, ethanol, or a combination thereof.

[0061] The carbon dioxide stream for methanol synthesis in 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 in line 168 may require treatment in a pressure swing adsorption (PSA) unit or a temperature swing adsorption (TSA) unit for the removal of trace pollutants such as SOx, NOx, NH3, O2, and H2O. Other particulate matter can be removed in the pollutant removal unit 184. Trace substances can be removed from the carbon dioxide stream 168 to isolate CO2 and this can be moved to the methanol synthesis unit 80.

[0062] According to the exemplary embodiment shown in FIG. 5, the methanol synthesis carbon dioxide stream within line 168 can be compressed within treatment compressor 180 to an intermediate pressure suitable for contaminant removal. The compressed synthesis carbon dioxide stream within line 182 may be supplied to contaminant removal unit 184 for removal of contaminants. The contaminant-removed carbon dioxide stream within line 185 exits contaminant removal unit 184. The stored carbon dioxide stream within line 186 can be taken from the contaminant-removed carbon dioxide stream within line 185 for storage. The contaminant-removed carbon dioxide stream may be taken to methanol synthesis unit 80 within line 187.

[0063] Prior to methanol synthesis, the contaminant-removed synthesis carbon dioxide stream within line 187 may be further compressed within synthesis compressor 200 to synthesis pressure. The synthesis carbon dioxide stream is supplied to methanol synthesis unit 80 within line 202 to provide a methanol stream within line 86. The hydrogen within line 83 also travels to methanol synthesis unit 80. According to certain embodiments of the present disclosure, the hydrogen within line 83 can be selected from one or both of blue hydrogen and green hydrogen. According to an exemplary embodiment, the hydrogen within line 83 is blue hydrogen. According to another exemplary embodiment, the hydrogen within line 83 is green hydrogen. The methanol stream within line 86 is removed from methanol synthesis unit 80.

[0064] Any of the foregoing lines, conduits, units, devices, containers, surrounding environments, zones, or the like may be equipped with one or more monitoring components including sensors, measurement devices, data capture devices, or data transmission devices. Signals, processes, or state measurements, and data from the monitoring components can be used to monitor the situation within, around, and above the process equipment. The 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 that may be private or public, general or specific, direct or indirect, wired or wireless, encrypted or unencrypted, and / or combinations thereof. The present specification is not intended to be limited in this regard. Further, the figures may include one or more exemplary sensors located on one or more conduits. Nevertheless, sensors may be present over each flow so that the corresponding parameters can be controlled accordingly.

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

Example

[0066] A comparative analysis was performed, showing that the utility cost of the dry scrubbing and carbon dioxide recycle stream disclosed in this process is lower compared to wet scrubbing and carbon dioxide recycle stream. The results are shown in Tables A and B below.

[0067]

Table 1

[0068]

Table 2

[0069] From the table above, it is clear that the process including dry scrubbing using a carbon dioxide recycle stream provides a net operating utility cost reduction of 6.46 - 0.0 = 6.46 MM$ / year, along with a capital expenditure reduction of 30.47 - 24.48 = 5.99 MM$ / year compared to wet scrubbing using a carbon dioxide recycle stream.

[0070] Specific embodiments The following is described in conjunction with specific embodiments, but it should be understood that this description is illustrative of the foregoing description and the scope of the appended claims and is not intended to limit those scopes.

[0071] The first embodiment of the present disclosure is a process for regenerating a catalyst from a fluidized catalyst process, comprising providing an oxygen stream and a preheated carbon dioxide recycle stream, mixing the oxygen stream and the preheated carbon dioxide recycle 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 of the 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 effluent stream containing reactant salts, filtering the reactor effluent stream to remove the reactant salts and catalyst fines to produce a filtered reactor effluent stream, and collecting a carbon dioxide recycle stream from the filtered reactor effluent stream. Some embodiments of the present disclosure further include moving the carbon dioxide recycle stream to a heater to provide a preheated carbon dioxide recycle stream, any one or all of the embodiments from the first embodiment to the embodiments up to this point in this paragraph. Some embodiments of the present disclosure are any one or all of the embodiments from the first embodiment to the embodiments up to this point in this paragraph, wherein the reactants are in a dry form. Some embodiments of the present disclosure are any one or all of the embodiments from the first embodiment to the embodiments up to this point in this paragraph, wherein the decontamination reactor operates at a temperature of 200°C to 600°C to react one or more of the sulfur-containing compounds, nitrogen-containing compounds, or both in the carbon dioxide-rich flue gas stream with the reactants. Some embodiments of the present disclosure are any one or all of the embodiments from the first embodiment to the embodiments up to this point in this paragraph, wherein the carbon dioxide-rich oxidation stream contains an oxygen concentration of 30 mol% or less. Some embodiments of the present disclosure are any one or all of the embodiments from the first embodiment to the embodiments up to this point in this paragraph, wherein the oxygen stream is provided from an electrolyzer or an air separation unit. Some embodiments of the present disclosure further include transferring heat from the carbon dioxide-rich flue gas stream to a boiler feed water stream in a heat recovery section to form a partially cooled carbon dioxide-rich flue gas stream and a steam stream, any one or all of the embodiments from the first embodiment to the embodiments up to this point in this paragraph.In certain embodiments of the present disclosure, the heat recovery section is a heat recovery steam generator (HRSG) that transfers heat from a carbon dioxide-rich flue gas stream to a boiler feed water stream within the HRSG to form a partially cooled carbon dioxide-rich flue gas stream and a steam stream, and moves the partially cooled carbon dioxide-rich flue gas stream to a decontamination reactor, which is one, any, or all of the embodiments of this paragraph from the first embodiment of this paragraph to the embodiments heretofore of this paragraph. Certain embodiments of the present disclosure further include separating a carbon dioxide-rich oxidation stream into a first portion and a second portion, moving the first portion of the carbon dioxide-rich oxidation stream to a regenerator unit, and moving the second portion of the carbon dioxide-rich oxidation stream to a heat recovery section, which is one, any, or all of the embodiments of this paragraph from the first embodiment of this paragraph to the embodiments heretofore of this paragraph. Certain embodiments of the present disclosure are one, any, or all of the embodiments of this paragraph from the first embodiment of this paragraph to the embodiments heretofore of this paragraph, wherein the heat recovery section is a heat recovery section of a carbon monoxide combustor. Certain embodiments of the present disclosure are one, any, or all of the embodiments of this paragraph from the first embodiment of this paragraph to the embodiments heretofore of this paragraph, wherein the fluid catalytic process is selected from a fluid catalytic cracking (FCC) process, a methanol to olefin (MTO) process, or both. Certain embodiments of the present disclosure further include moving a carbon dioxide-rich flue gas stream to a third stage separator (TSS) to separate catalyst fines in the underflow stream and provide a carbon dioxide-rich flue gas stream with reduced catalyst fines in the overflow stream, generating electricity from the overflow stream in an expander, and moving the overflow stream to a heat recovery section, which is one, any, or all of the embodiments of this paragraph from the first embodiment of this paragraph to the embodiments heretofore of this paragraph. Certain embodiments of the present disclosure are one, any, or all of the embodiments of this paragraph from the first embodiment of this paragraph to the embodiments heretofore of this paragraph, wherein the reactant includes one or more of sodium bicarbonate (NaHCO3), calcium hydroxide (Ca(OH)2), and trona salt (Na2CO3·NaHCO3·2H2O).In certain embodiments of the present disclosure, the reactant salt is one or more of sodium sulfate (Na2SO4), sodium carbonate (Na2CO3), and sodium nitrate (NaNO3), any or all of the first through the then-current embodiments of this paragraph. Certain embodiments of the present disclosure further include moving the filtered reactor effluent stream through a heat exchanger to provide a partially cooled filtered reactor effluent stream; cooling the partially cooled filtered reactor effluent stream to provide a cooled filtered reactor effluent stream; separating water from the cooled filtered reactor effluent stream to provide a carbon dioxide stream; and separating the carbon dioxide stream into a carbon dioxide recycle stream and a separated carbon dioxide stream, any or all of the first through the then-current embodiments of this paragraph. Certain embodiments of the present disclosure further include moving the above-described separated carbon dioxide stream to a methanol synthesis unit to provide a methanol stream, any or all of the first through the then-current embodiments of this paragraph. Certain embodiments of the present disclosure further include compressing a preheated dry carbon dioxide recycle stream to provide a compressed preheated dry carbon dioxide recycle stream and moving the compressed preheated dry carbon dioxide recycle stream to a regenerator unit, any or all of the first through the then-current embodiments of this paragraph. Certain embodiments of the present disclosure include that the HRSG comprises a superheated steam section and a saturated steam section, any or all of the first through the then-current embodiments of this paragraph.Certain embodiments of the present disclosure further include moving a carbon dioxide-rich flue gas stream to the superheated steam section of an HRSG to produce a superheated steam stream and a heat-exchanged carbon dioxide-rich flue gas stream, moving a boiler feed water stream and the heat-exchanged carbon dioxide-rich flue gas stream to the saturated steam section of the HRSG to form a partially cooled carbon dioxide-rich flue gas stream and a saturated steam stream, introducing at least a portion of the saturated steam stream into the superheated steam section of the HRSG, and superheating the saturated steam stream with the carbon dioxide-rich flue gas stream to produce a superheated steam stream, which is one, any, or all of the embodiments thus far in this paragraph from the first embodiment of this paragraph.

[0072] A second 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 recycle stream, mixing the oxygen stream and the preheated carbon dioxide recycle stream to provide a carbon dioxide-rich oxidation stream, separating the carbon dioxide-rich oxidation stream into a first portion and a 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 carbon dioxide-rich oxidation stream to a heat recovery section to provide a partially cooled carbon dioxide-rich flue gas stream and a steam stream, reacting one or more of 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 effluent stream containing reaction salts, filtering the reactor effluent stream to remove the reaction salts and catalyst fines to produce a filtered reactor effluent stream, and collecting a carbon dioxide recycle stream from the filtered reactor effluent stream.

[0073] A third embodiment of the present disclosure is an 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, 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 feed water 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 carbon dioxide separation unit in fluid communication with the flue gas outlet of the heat exchanger, and a heater in fluid communication downstream of the carbon dioxide separation unit.

[0074] Without further elaboration, using the foregoing description, one skilled in the art should be able to utilize the present disclosure to its fullest extent without departing from the spirit and scope of the present disclosure and should be able to readily ascertain the essential characteristics of the present disclosure and make various changes and modifications to the present disclosure and adapt it to various uses and conditions. Therefore, the foregoing preferred specific embodiments should be construed as merely illustrative and not in any way limiting the remainder of the present disclosure, which is intended to cover various modifications and equivalent configurations within the scope of the appended claims.

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

Claims

1. A process for regenerating a catalyst from a fluidized catalyst process, comprising: providing an oxygen stream and a preheated carbon dioxide recycle stream; mixing the oxygen stream and the preheated carbon dioxide recycle stream to provide a carbon dioxide-rich oxidation stream; transferring the carbon dioxide-rich oxidation stream to a regenerator unit to provide a carbon dioxide-rich flue gas stream; reacting one or more of the 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 effluent stream containing reaction salts; filtering the reactor effluent stream to remove the reaction salts and catalyst fines to produce a filtered reactor effluent stream; collecting a carbon dioxide recycle stream from the filtered reactor effluent stream; A process for regenerating a catalyst from a fluidized catalyst process, comprising the above steps.

2. The process according to claim 1, further comprising transferring the carbon dioxide recycle stream to a heater to provide the preheated carbon dioxide recycle stream.

3. The process according to claim 1, wherein the reactants are in a dry form.

4. The process according to claim 1, wherein the decontamination reactor operates at a temperature of 200°C to 600°C to react one or more of the sulfur-containing compounds, nitrogen-containing compounds, or both in the carbon dioxide-rich flue gas stream with the reactants.

5. The process according to claim 1, wherein the carbon dioxide-rich oxidation stream contains an oxygen concentration of 30 mol% or less.

6. The process according to claim 1, wherein the oxygen stream is provided from an electrolyzer or an air separation unit.

7. The process according to claim 1, further comprising transferring heat from the carbon dioxide-rich flue gas stream to a boiler feed water stream in a heat recovery section to form a partially cooled carbon dioxide-rich flue gas stream and a steam stream.

8. The heat recovery section is a heat recovery steam generator (HRSG), transferring heat from the carbon dioxide-rich flue gas stream to a boiler feed water stream in the HRSG to form the partially cooled carbon dioxide-rich flue gas stream and the steam stream, transferring the partially cooled carbon dioxide-rich flue gas stream to the decontamination reactor; The process according to claim 7, comprising the above steps.

9. separating the carbon dioxide-rich oxidation stream into a first portion and a second portion; moving the first portion of the carbon dioxide-rich oxidation stream to the regenerator unit; moving the second portion of the carbon dioxide-rich oxidation stream to the heat recovery section; The process according to claim 7, further comprising.

10. An apparatus for regenerating a catalyst, comprising: a heat recovery section including a superheated steam section and a saturated steam section; the 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; the saturated steam section having a flue gas inlet, a flue gas outlet, a boiler feed water 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 carbon dioxide separation unit in fluid communication with the flue gas outlet of the heat exchanger; a heater in fluid communication downstream of the carbon dioxide separation unit; An apparatus for regenerating a catalyst, comprising.

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