Process for regenerating a catalyst from a fluidized catalyst process at high pressure

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 benefit of U.S. Provisional Patent Application No. 63 / 390,891, filed Jul. 20, 2022; U.S. Provisional Patent Application No. 63 / 407,151, filed Sep. 15, 2022; U.S. Provisional Patent Application No. 63 / 485,194, filed Feb. 15, 2023; and U.S. Patent Application No. 18 / 144,790, filed May 8, 2023, the entire contents of each of which are incorporated herein by reference.

[0002] (Field of the Invention) This technical field relates to processes and apparatus for regenerating catalysts from fluid catalytic processes. 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 can be produced from such a system, including gasoline products and / or light products such as propene and / or ethene.

[0004] Fluid catalytic cracking (FCC) is a hydrocarbon conversion process achieved by contacting hydrocarbons with a catalyst consisting of finely divided particulate matter within a fluidized reaction zone. The reactions in catalytic cracking, in contrast to hydrocracking, are carried out without substantial hydrogen 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 the coke derived from the catalyst. The coke-containing catalyst, referred to herein as coke catalyst, is continuously removed from the reaction zone and replaced by a substantially coke-free catalyst from the regenerator zone. 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 objective 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 substantially complete removal of coke from the catalyst. This substantially 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 complete combustion.

[0006] Conventional regenerators typically include a vessel having a coke 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 the catalyst entrained in the flue gas before the flue gas exits the regenerator.

[0007] Alternative processes 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 the oxides, such as methanol, into 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, 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 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 particulate removal and conversion of carbon monoxide (CO), and then the flue gas is typically discharged into the atmosphere. Further, incomplete combustion to carbon monoxide can result from insufficient fluidization or aeration of the coke catalyst in the regenerator, or insufficient distribution of the coke catalyst into the regenerator. Generally, the flue gas exiting the regenerator contains carbon monoxide, carbon dioxide, nitrogen, and water, along with small amounts of other chemical species. Flue gas treatment methods are effective but have high capital and operating costs.

[0009] Conventional treatment of flue gas from FCC units and MTO units involves the use of wet gas cleaning technologies 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 a temperature of 400 - 500°F to a temperature of 140 - 194°F using water quench. The cooled flue gas contacts sodium hydroxide that reacts with 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 be optionally heated and treated to remove nitrogen compounds. 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 due to 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 (H2SO4) and concerns about fouling of spray nozzles 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 from 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 submicron aerosols formed, and white plumes caused by water condensation when the flue gas is discharged to the atmosphere. This can be avoided by heating the stream, but this approach increases capital and operating costs. After treatment, the treated flue gas is generally either discharged to the atmosphere or sent for further component 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 significant long-lived greenhouse gas in the Earth's atmosphere. Carbon dioxide capture from flue gas remains expensive from both the perspectives of capital expenditure and operating costs. In a fluid catalytic process, air is used to regenerate the spent catalyst. As a result of this operation, the carbon dioxide in the FCC flue gas has a lower amount, in contrast to the amount of undesirable components from the perspective of carbon dioxide capture, and brings not only high capital expenditure due to a large amount of flue gas but also high solvent circulation rates and significant operating costs as solvent regeneration loads. Separately from this, the flue gas requires large-scale flue gas treatment prior to carbon capture in order to meet strict specifications to avoid high solvent decomposition rates. This results in high capital expenditure and operating costs associated with various longer impurity removal operations. In addition, typically, a wet gas scrubber is used, which brings, in addition to insufficient energy recovery from the flue gas, a large amount of makeup water, problems related to corrosion and fouling in the plant, difficulties in slurry handling, and the risk of blue plumes as a result of water condensation upon release to the atmosphere, as well as white 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 costs of a 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 combust coke from a spent catalyst. Since air contains a large amount (79 mol%) of nitrogen (N₂), the carbon dioxide partial pressure is low. As a result, the carbon dioxide in the FCC flue gas is in a smaller amount, such as 15 - 25 mol%, and the remainder is an undesirable component. This process discloses supplying a carbon dioxide-rich oxidation 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 as compared to the undesirable components by 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 with an oxygen stream, and moving the carbon dioxide-rich oxidation stream to a regenerator for combusting coke from a spent catalyst. The carbon dioxide-rich oxidation stream provides an atmosphere substantially free of nitrogen in 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. This process and this apparatus increase the capacity of existing units. The carbon dioxide-rich oxidation stream provides conditions substantially free of nitrogen and improves the necessity of a high-temperature regenerator when air is moved to the regenerator because the molar heat capacity of carbon dioxide is higher than that of nitrogen.

[0015] Furthermore, this process provides a dry cleaning step for the treatment of flue gas. The dry cleaning step avoids corrosion problems as compared to a wet cleaning step. The dry cleaning step also eliminates the possibility of blue / white plumes due to water condensation and / or sulfuric acid aerosol in the wet cleaning step. This process also provides heat integration between the carbon dioxide recycle stream and the dry cleaning step and provides a substantial increase in energy recovery from the flue gas enabled through dry cleaning.

Brief Description of the Drawings

[0016] Various embodiments are described below with reference to 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 "direct communication" or "directly" means that the flow from the upstream component enters the downstream component without passing through a fractionation or conversion unit and undergoing a compositional change by physical fractionation or chemical conversion.

[0021] The term "column" means a 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 overhead line and bottoms line refer to the net lines 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. The process includes the use of a dry sorbent injection (DSI) unit to remove sulfur compounds from flue gas generated from the regenerated catalyst from the fluid catalytic process. The fluid catalytic process can be any fluid catalytic process that regenerates a catalyst, including an FCC process or an MTO process. The flue gas from the regenerator of the fluid catalytic process is used to make superheated steam and saturated steam. The flue gas is then sent to the DSI unit to remove sulfur compounds and then to a heat recovery exchanger, which can be a heat exchanger for heating a carbon dioxide recycle stream, as described in detail below. The flue gas temperature does not drop as much as in the case of a wet scrubber process, so 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 was not harvested can be captured, substantially improving the energy efficiency of the 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 where the flue gas is produced at an SOx concentration that exceeds environmental limits.

[0027] The process provides a substantial increase in energy recovery by adding 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 before or after the DSI to preheat the boiler feed water used in a heat recovery steam generator (HRSG) and / or a catalyst cooler and / or a CO combustor, thereby reducing or eliminating the possibility of a negative energy balance. Alternatively, low-pressure (LP) steam 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 tube corrosion and significantly improves the reliability of the system. The disclosed process reduces or eliminates concerns about corrosion due to sulfuric acid. Avoiding operation in a corrosive regime eliminates the need for a stainless-steel flue gas scrubber, and a complete system can be made from carbon steel.

[0030] The DSI technology does not require water, which is considered a scarce resource, so the water usage of the system is significantly improved. The process also avoids the need for complex slurry handling, eliminates concerns about fouling of spray nozzles in wet gas scrubbers, and avoids white plumes resulting from water condensation and blue plumes resulting from sulfuric acid aerosol emissions. Additionally, when using NaHCO3 as a DSI reactant, up to 21% NOx reduction can be achieved, while the pressure drop of 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 (N2), enters the regenerator flue gas, resulting in a lower carbon dioxide partial pressure. Nitrogen occupies an unnecessary volume and leads to a large 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 is relatively high, which may be the reason for the refiner's resistance to implementing carbon dioxide (CO2) 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 the capital and operating costs for carbon dioxide capture.

[0032] In the wet scrubbing process, it is necessary to saturate the flue gas by passing it 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 overall capital expenditure, it is proposed to recover heat / energy from the flue gas stream after dry scrubbing. The process of the present invention recovers heat from the flue gas after dry scrubbing by means of a heat recovery exchanger. The heat recovery exchanger may be used for heat exchange with the carbon dioxide recycle stream, but the recycled carbon dioxide stream can be heated to the desired temperature level for transfer to the regenerator without the need for external heating equipment. Furthermore, this process withdraws a carbon dioxide recycle stream from the flue gas stream after the dry scrubbing step.

[0033] In the FCC process, the flue gas from the regenerator is generally moved 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 taken 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 is sent to a fourth stage separator to separate the catalyst fines. The TSS in the FCC process can be directly integrated with the filter section. Therefore, the fourth stage separator for the underflow stream from the TSS can be omitted. Therefore, the underflow stream from the TSS is directly moved 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 expansion turbine where 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 only 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 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 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 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 in the heat recovery section, where a combustion air stream is added to burn the flue gas, releasing heat, and that heat is 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 removed by replacing other purges such as the air supplied to the CO combustor, the dry air (DA) purge point, and the fluffing air in the regenerator with a portion of the carbon dioxide-rich oxidation stream containing oxygen and the recirculated 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 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 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 to release heat and that heat is recovered. By operating the regenerator in the partial combustion mode to maximize the carbon monoxide yield, the unit will limit the amount of heat released within the regenerator as compared to completely burning the coke to carbon dioxide. This reduces the regenerator temperature and allows for a higher ratio of catalyst to oil in 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 catalyst regeneration includes 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 catalytic 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 electrolyzer. Accordingly, the oxygen stream in line 104 may be supplied from an electrolyzer. The carbon dioxide recycle stream in line 186 is preheated in heat exchanger 190 to provide a preheated carbon dioxide recycle stream in line 194. The oxygen stream in line 104 and the preheated carbon dioxide recycle stream in 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 transferred to the regenerator unit 120. The spent catalyst stream from the fluid catalytic process in line 102 is also transferred to the regenerator unit 120. In one aspect, the carbon dioxide-rich oxidation stream in line 197 includes an oxygen concentration of 30 mol% or less.

[0037] In a fluid catalytic process, the catalyst particles are repeatedly circulated between the reaction zone and the catalyst regenerator unit 120. During regeneration, the coke deposited on the catalyst particles during the reaction in the reaction zone is removed at high temperature by oxidation in the regenerator unit 120. The removal of the coke deposits restores the activity of the catalyst particles to the point where they 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 prior to further processing. The carbon dioxide-rich flue gas stream in line 122 is moved to the heat recovery section 125 to transfer heat from the carbon dioxide-rich flue gas stream in line 122 to the boiler feed water stream in line 127, forming a partially cooled carbon dioxide-rich flue gas stream in line 132 and a steam stream in line 126. The heat recovery section 125 can include an HRSG or a CO combustor and an HRSG. As described above herein, when the regenerator unit 120 is operating under partial combustion, a portion of the carbon dioxide-rich oxidation stream in line 197 is sent 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 is sent to the regenerator unit 120, and the second portion of the carbon dioxide-rich oxidation stream in line 199 is sent to the CO combustor of the heat recovery section 125.

[0039] Under partial combustion operation, the carbon dioxide-rich flue gas stream in line 122 is sent to the CO combustor 124 of 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 fully combusted stream from the carbon monoxide combustor is sent to the HRSG unit 129 of the heat recovery section 125. In an exemplary embodiment, the flue gas outlet temperature of the FCC regenerator for a partial combustion 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 does not exist. Thus, under the complete combustion regenerator unit 120, the carbon dioxide-rich flue gas stream in line 122 is sent to the HRSG unit 129. The complete combustion or partial combustion MTO regenerator may operate at a temperature 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 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 withdrawn from the HRSG unit 129. The partially cooled carbon dioxide-rich flue gas stream in line 132 is withdrawn from the heat recovery section 125. The partially cooled carbon dioxide-rich flue gas stream in line 132 is processed to remove impurities. The flue gas outlet temperature from the HRSG for the partial combustion FCC regenerator or the complete combustion FCC process or MTO process may be in the range of 200 °C to 290 °C.

[0041] The partially cooled carbon dioxide-rich flue gas stream 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 aspect, the partially cooled carbon dioxide-rich flue gas stream of line 132 from the heat recovery section 125 is mixed with the dry reactants 131 to provide a mixed stream of line 137, and the mixed stream 137 is sent together 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 stream in line 132 to form a reactor effluent stream containing the 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 reactants in slurry form. 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 of 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 the reactant salts of line 142 is moved to the filter section 150 for particle removal.

[0042] The filter section 150 removes particulates and fines from the reactor effluent stream 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 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 filtered material 154 can be removed from the process at line 155. Alternatively, or additionally, the filtered material may be recycled to the decontamination reactor 140 as a recycled filtered material of line 156 to increase the sodium carbonate conversion yield. The recycled filtered material of line 156 may be recycled with the mixed stream of line 137 and sent to the decontamination reactor 140 of line 139. Thus, the reactant salts and catalyst fines are removed from the reactor effluent stream 142 in the filter section 150 to produce the filtered reactor effluent stream of line 152. The filtered reactor effluent stream of line 152 is transferred to the carbon dioxide separation section 111 where carbon dioxide is separated from the filtered reactor effluent stream. The separation section 111 may include heat exchangers 190, coolers 160 and 180, knock out drums (KOD) 163 and 184 for separation, a heater 167, a compressor 170, and a generator 175.

[0043] Since the reactants are used in dry form, the filtered reactor effluent stream in line 152 still has a fairly high temperature. Heat / energy can still be recovered from the filtered reactor effluent stream in line 152. The filtered reactor effluent stream in line 152 is heat-exchanged with the carbon dioxide recycle stream in line 186 in heat exchanger 190 to provide a preheated carbon dioxide recycle stream in line 194 and a partially cooled and filtered reactor effluent stream in line 192. In an exemplary embodiment, heat exchanger 190 is a gas-gas type heat exchanger. Optionally, the partially cooled and filtered reactor effluent stream 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 stream 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 a cooling medium. Alternatively, the first cooler 160 can be an air cooler. In one aspect of the present disclosure, the first cooler 160 may be optional, and the cooled and filtered reactor effluent stream in 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 effluent stream in line 162 to provide a carbon dioxide stream, which is taken out from the top of the KOD in line 164. Water is taken out as stream 165 from the bottom of the first KOD 163. This process recycles the carbon dioxide stream in line 164 to the regenerator unit 120. Thus, a part or all of the carbon dioxide stream in line 164 can be taken and mixed with the oxygen stream 104 to provide a carbon dioxide-rich oxidation stream 197 for the regenerator unit 120. In one embodiment, the carbon dioxide stream is separated into a carbon dioxide stream for recycle in line 166 and a separated carbon dioxide stream in line 168. The separated carbon dioxide stream in line 168 may be taken out and sent for storage. The separated carbon dioxide stream in line 168 is SO x 、NO xFor 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 in line 168 may be appropriately treated and sent to a storage site. According to this process, the carbon dioxide stream for recirculation in line 166 may be further treated before recirculation to the regenerator unit 120.

[0045] The carbon dioxide stream for recirculation in line 166 may be moved to a carbon dioxide recirculation compressor 170 to provide a compressed carbon dioxide recirculation stream in line 172. The compressed carbon dioxide recirculation stream in line 172 may be moved to a generator 175 to provide a partially cooled carbon dioxide recirculation stream in line 176 and a vapor stream in line 177 from the water stream in line 174. The vapor stream 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 stream. The partially cooled carbon dioxide recirculation stream in line 176 is cooled in a second cooler 180 to provide a cooled carbon dioxide recirculation stream in line 182, which is moved to a second knockout drum (KOD) 184. The second cooler 180 can 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 stream in line 172 at the outlet of the carbon dioxide recirculation compressor 170 is at a high temperature. The compressed carbon dioxide recirculation stream 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 stream in line 172 may be used to preheat the BFW stream in a BFW preheater (not shown). Therefore, the compressed carbon dioxide recirculation stream in line 172 may be moved to the BFW preheater and then to the second cooler 180.

[0046] The cooling and condensation of the cooled and filtered reactor effluent stream in line 192 using the first cooler 160 can result in the formation of an aqueous phase. This can lead to the formation of carbonic acid due to the reaction of carbon dioxide and water. The formation of carbonic acid 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 preferably selected to withstand any carbonic acid corrosion. According to one embodiment of the present disclosure, the heater 167 may be present upstream of the carbon dioxide recycle compressor 170. According to one aspect, the heater 167 may be used to raise the temperature of the carbon dioxide stream for recirculation in line 166 to provide a heated carbon dioxide stream for recirculation in line 169 that is moved to the carbon dioxide recycle compressor 170. According to an exemplary embodiment, the carbon dioxide stream for recirculation in line 166 is moved to the heater 167 to raise the temperature of the carbon dioxide stream by 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 heated carbon dioxide stream for recirculation in line 169 is moved to the carbon dioxide recycle compressor 170 to provide a compressed carbon dioxide recycle stream in line 172 and is moved to the low-pressure steam generator 175 and the second cooler 180 as described above. The heater 167 is preferably disposed downstream of the first KOD 163 to allow for greater condensation of water and separation of water in the KOD.

[0047] In the second KOD 184, water is separated from the cooled carbon dioxide recycle stream of line 182 to provide a dry carbon dioxide recycle stream, which is withdrawn from the top of the KOD to line 186. Water is withdrawn as stream 187 from the bottom of the second KOD 184. The dry carbon dioxide recycle stream of line 186 is heat exchanged with the filtered reactor effluent stream of line 152 in heat exchanger 190 to provide a preheated dry carbon dioxide recycle stream of line 194. The preheated dry carbon dioxide recycle stream of line 194 is mixed with the oxygen stream of line 104 in mixer 196 and then moved to the regenerator unit 120. In some embodiments, a deoxygenation operation may be included in the separation section 111 or the decontamination reactor 140 to meet the specifications regarding 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 fluid catalytic process is addressed with reference to process and apparatus 201. The elements of FIG. 2 may have the same configuration as FIG. 1, each having the same reference numbers and similar operating conditions. The fluid catalytic process as shown in FIG. 2 is an FCC process operating under complete combustion conditions. Accordingly, the heat recovery section 125 does not have a CO combustor. The heat recovery section 125 includes an HRSG 129.

[0049] The carbon dioxide-rich oxidation stream of line 197 is transferred to an FCC regenerator unit 120 operating under complete combustion conditions. From the regenerator unit 120, a carbon dioxide-rich flue gas stream of line 122 is withdrawn. The carbon dioxide-rich flue gas stream of line 122 is transferred to a heat recovery section 125 to recover heat from the carbon dioxide-rich flue gas stream of line 122. In an exemplary embodiment, the heat recovery section 125 is an HRSG129’. The HRSG129’ includes a superheated steam section 124 and a saturated steam section 130. The carbon dioxide-rich flue gas stream of line 122 is transferred to the superheated steam section 124 of the HRSG129’ to transfer heat to a partial steam stream of line 138, generating a superheated steam stream of line 126’ and a heat-exchanged carbon dioxide-rich flue gas stream of line 128. The heat-exchanged carbon dioxide-rich flue gas stream of line 128 is sent to the saturated steam section 130 of the HRSG129’. In the saturated steam section 130, a boiler feed water stream 127 is heated by the heat-exchanged carbon dioxide-rich flue gas stream of line 128 to form a saturated steam stream of line 134 and a partially cooled carbon dioxide-rich flue gas stream of line 132’. A condensate stream of line 133 is withdrawn from the saturated steam section 130. The partial steam stream of line 138 of the saturated steam stream 134 is sent to the HRSG superheated steam section 124 to be superheated. The remaining steam of line 136 of the saturated steam stream 134 can be sent to other parts of the plant for use as needed. The partially cooled carbon dioxide-rich flue gas stream of line 132’ is withdrawn from the saturated steam section 130 and transferred to a decontamination reactor 140. A dry reactant 131 may be mixed with the partially cooled carbon dioxide-rich flue gas stream of line 132’ to provide a mixed stream of line 137’. The mixed stream of line 137’ is transferred to the decontamination reactor 140. The recycled filtration material of line 156 may be recycled with the mixed stream of line 137’ and sent to the decontamination reactor 140 of line 139’. The remainder of the 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 fluid catalytic process is addressed with reference to a process and apparatus 301 as shown in FIG. 3. The elements of FIG. 2 may have the same configuration as FIG. 2, 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. 3 includes, in addition to the elements shown in FIG. 2, a third stage separator (TSS) (210) and a flue gas expander (220).

[0051] The carbon dioxide-rich flue gas stream in line 122 is moved to the TSS 210 to separate the catalyst fines in the underflow stream of line 214. The carbon dioxide-rich flue gas stream with reduced catalyst fines is separated into the overflow stream of line 212 from the TSS 210. The catalyst fines from the underflow stream of line 214 from the TSS 210 are further concentrated in the underflow stream of line 214. The underflow stream in line 214 from the TSS 210 is moved directly to the decontamination reactor 140. In an exemplary embodiment, the underflow stream of line 214 is combined with the partially cooled carbon dioxide-rich flue gas stream of line 132'' to provide a combined partially cooled carbon dioxide-rich flue gas stream of line 137'', which is moved to the decontamination reactor 140. In another exemplary embodiment, the partially cooled carbon dioxide-rich flue gas stream of line 132'' and the underflow stream of line 214 are moved separately to the decontamination reactor 140. The recycled filter material in line 156 may be recycled with the combined partially cooled carbon dioxide-rich flue gas stream of line 137'' and sent to the decontamination reactor 140 of line 139''. The catalyst fines from the underflow stream of line 214 are separated in the filter section 150. The separated catalyst fines are removed from the filter section 150 in line 155. 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 of line 212 is transferred to the flue gas expander 220 where, as described above herein, energy is extracted in the form of work and / or electricity. In an exemplary embodiment, the expander 220 is coupled to a generator for blue power generation. After power generation, the overflow stream of line 222 from the flue gas expander 220 is transferred to the heat recovery section 125. The remainder of the 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 a process and apparatus 401 as shown in FIG. 4. The elements of FIG. 4 may have the same configuration as FIG. 3, each having the same reference numeral 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) or an electrolyzer. In an exemplary embodiment, the oxygen source 90 is an electrolyzer 90.

[0055] Examples of the electrolyzer 90 include, but are not limited to, polymer electrolyte membrane / proton exchange membrane (PEM / PEMEC), alkaline electrolysis cell (AEC), anion exchange membrane (AEM), and solid oxide electrolysis cell (SOE / SOEC). Various types of electrolyzers may be used. According to the present disclosure, the useful substances produced in the fluidized catalyst process may 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 HRSG 130 can be used in the electrolyzer 90. In PEM, AEC, AEM, and SOEC electrolyzers, the electricity generated in the power recovery section may be used. Additionally, in SOEC electrolyzers, heat in the form of steam may be used in the SOEC to reduce the need for useful substances produced and conveyed to the process and apparatus 401. In SOEC electrolyzers, 25% to 30% of the total energy requirement may be supplied by heat. In an exemplary embodiment, the heat generated from the FCC regenerator flue gas from the FCC unit may be supplied to the SOEC electrolyzer. Apart from capturing the heat generated from the FCC regenerator flue gas, other heat sources such as the heat captured from the main column top of the FCC unit are also envisioned for integration. Further, apart from using electricity to decompose water, the electricity generated in the process units as disclosed previously may also be used for compression for electrolyzers such as AEC, AEM, and PEM electrolyzers. The electrolyzer may use the electricity generated in the expander turbine installed in the FCC regenerator flue gas section of the FCC unit as described above in this specification, upstream of the steam boiler and downstream of the TSS 210. In an exemplary embodiment, the electrolyzer 90 may use a portion of the electricity generated from the flue gas expander 220. In another exemplary embodiment, the electrolyzer 90 may use the thermal energy or steam generated in the FCC process.

[0056] Referring to FIG. 4, the oxygen source 90 is an electrolyzer 90. The electrolyzer 90 may be selected from one or more electrolyzers including, but not limited to, a high temperature 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) as described above. The air stream in line 92 and the 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 useful materials generated in the FCC unit can be used in the electrolyzer 90. In an embodiment, 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 from the saturated steam section 130 of the HRSG 129' are transferred to the electrolyzer 90. The hydrogen generated in the electrolyzer 90 can be withdrawn in line 98. The oxygen stream is withdrawn from the electrolyzer 90 in line 104 and transferred to the mixer 196. The remainder of the process is the same as that described in FIG. 3.

[0057] To maintain the same volumetric flow rate as in the basic case, as a result of the increased molecular weight of carbon dioxide compared to air which is mostly nitrogen, more mass of inert gas is introduced into the regenerator unit 120, which may cause the temperature in the regenerator unit 120 to drop. To keep the regenerator temperature constant, the following means may be used. a) Install an electric heating coil in the regenerator and use electricity generated within the process or from any supply 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 supply source, or c) Directly combust fuel gas and / or natural gas within the regenerator, or d) Continuously combust a direct combustion air heater, or e) Burn torch oil and / or FCC slurry oil within the FCC regenerator. The use of electricity to heat the coil within the regenerator unit is a more sustainable and environmentally friendly means. The present process includes using electricity generated from the FCC process disclosed above as a heat source for the heating coil within 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 within 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] Yet another exemplary embodiment of a process and apparatus for regenerating a catalyst from a fluid catalytic process is addressed with reference to a process and apparatus 501 as 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. A process and apparatus for regenerating a catalyst from a fluid catalytic process as shown in FIG. 5 comprises, in addition to the elements shown in FIG. 4, a methanol synthesis unit 80 for providing a methanol stream 86.

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

[0060] Methanol may be produced by hydrogenating carbon dioxide on a methanol synthesis catalyst from the methanol synthesis unit 80. 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 the separation of methanol and the recirculation of unreacted reagents to the synthesis reaction. The methanol stream is provided at line 86. The methanol stream of line 86 may include methanol, dimethyl ether, ethanol, or a combination thereof.

[0061] The carbon dioxide stream for methanol synthesis of 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 of line 168 is SO x , NO x , NH3, O2, and H2O may require treatment in a pressure swing adsorption (PSA) unit or a temperature swing adsorption (TSA) unit for the removal of trace amounts of contaminants. 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 and this may be moved to the methanol synthesis unit 80.

[0062] According to an exemplary embodiment shown in FIG. 5, the methanol synthesis carbon dioxide stream of line 168 may be compressed in the process compressor 310 to an intermediate pressure suitable for contaminant removal. The compressed synthesis carbon dioxide stream of line 312 may be supplied to the contaminant removal unit 320 for removal of contaminants. The contaminant-removed carbon dioxide stream of line 322 exits the contaminant removal unit 320. The stored carbon dioxide stream of line 324 may be taken from the contaminant-removed carbon dioxide stream of line 322 for storage. The contaminant-removed synthesis carbon dioxide stream may be taken in line 326 to the methanol synthesis unit 340.

[0063] Prior to methanol synthesis, the contaminant-removed synthesis carbon dioxide stream of line 326 may be further compressed in the synthesis compressor 330 to the synthesis pressure. The synthesis carbon dioxide stream is supplied to the methanol synthesis unit 340 in line 332, and a methanol stream is supplied to line 342. The hydrogen of line 334 is also moved to the methanol synthesis unit 340. According to an embodiment of the present disclosure, the hydrogen in line 334 may be selected from one or both of blue hydrogen and green hydrogen. 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 taken out from the methanol synthesis unit 340.

[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 condition measurements from the monitoring components, as well as data, can be used to monitor the situation within, around, and above the 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 that may be private or public, general or specific, direct or indirect, wired or wireless, encrypted or unencrypted, and / or combinations thereof. This specification is not intended to be limiting in this regard. Further, the figures may include one or more exemplary sensors disposed on one or more conduits. Nevertheless, sensors may be present on each flow such that the corresponding parameters can be controlled accordingly.

[0065] Signals, measurements, and / or data generated or recorded by a monitoring component 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 from one or more monitoring components data related to at least a portion of a device associated with a process. 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 to demonstrate lower operating costs for dry scrubbing with heat integration for carbon dioxide recycle streams as disclosed in this process compared to wet scrubbing without heat integration for carbon dioxide recycle streams. The results are shown in Tables A and B.

[0067]

Table 1

[0068]

Table 2

[0069] From the above table, it is clear that the process including dry cleaning with heat integration for the carbon dioxide recycle stream provides a net operating cost reduction of 6.46 - 1.11 = 5.35 MM$ / year and has almost the same capital expenditure compared to wet cleaning without heat integration for the 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 them.

[0071] The 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 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. An embodiment of the present disclosure further comprises preheating the carbon dioxide recycle stream by heat exchange with the filtered reactor effluent stream to provide the preheated carbon dioxide recycle stream, which is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph, wherein the reactants are in a dry form. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of 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. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph, wherein the carbon dioxide-rich oxidation stream contains an oxygen concentration of 30 mol% or less. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph, wherein the oxygen stream is supplied from an electrolyzer or an air separation unit. An embodiment of the present disclosure further comprises 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, which is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph.One embodiment of the present disclosure is that the heat recovery section is a heat recovery steam generator (HRSG), which transfers heat from the exhaust heat recovery boiler to the 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 previous embodiments of this paragraph to the first embodiment of this paragraph. One embodiment of the present invention further includes 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, 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 previous embodiments of this paragraph to the first embodiment of this paragraph. One embodiment of the present disclosure is that the heat recovery section is the heat recovery section of a carbon monoxide (CO) boiler, which is one, any, or all of the previous embodiments of this paragraph to the first embodiment of this paragraph. One embodiment of the present disclosure is that the fluid catalytic process is selected from a fluid catalytic cracking (FCC) process, a methanol-to-olefin (MTO) process, or both, which is one, any, or all of the previous embodiments of this paragraph to the first embodiment of this paragraph. One embodiment of the present disclosure further includes moving the carbon dioxide-rich flue gas stream to a third-stage separator (TSS) to separate the 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 previous embodiments of this paragraph to the first embodiment of this paragraph. One embodiment of the present disclosure is that the reactant salt contains one or more of sodium sulfate (Na2SO4), sodium carbonate (Na2CO3), and sodium nitrate (NaNO3), which is one, any, or all of the previous embodiments of this paragraph to the first embodiment of this paragraph.One embodiment of the present disclosure includes heat exchanging a filtered reactor effluent stream with a carbon dioxide recycle stream in a heat exchanger to provide a preheated carbon dioxide recycle stream and a partially cooled and filtered reactor effluent stream; and optionally cooling the partially cooled and filtered reactor effluent stream to provide a cooled and filtered reactor effluent stream; separating water from the cooled and filtered reactor effluent stream to provide a carbon dioxide stream; and separating the carbon dioxide stream into a carbon dioxide stream separated from the carbon dioxide recycle stream, which is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph. One embodiment of the present disclosure includes compressing a carbon dioxide recycle stream to provide a compressed carbon dioxide recycle stream; moving the compressed carbon dioxide recycle stream to a low-pressure steam generator to provide a low-pressure steam stream and a partially cooled carbon dioxide recycle stream; cooling the partially cooled carbon dioxide recycle stream to provide a cooled carbon dioxide recycle stream; separating water from the cooled carbon dioxide recycle stream to provide a dry carbon dioxide recycle stream; preheating the dry carbon dioxide recycle stream by heat exchanging the filtered reactor effluent stream with the dry carbon dioxide recycle stream to provide a preheated dry carbon dioxide recycle stream; and moving the preheated dry carbon dioxide recycle stream to a regenerator unit, which is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph. One embodiment of the present disclosure further includes heating a recycled carbon dioxide stream to provide a warm carbon dioxide recycle stream and recycling the warm carbon dioxide recycle stream to a regenerator unit, which is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph. One embodiment of the present disclosure further includes moving the separated carbon dioxide stream to a methanol synthesis unit to provide a methanol stream, which is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph. One embodiment of the present disclosure is that the HRSG includes a superheated steam section and a saturated steam section, which is one, any, or all of the preceding embodiments of this paragraph to the first embodiment of this paragraph.One embodiment of the present disclosure further includes moving a carbon dioxide-rich flue gas stream to the superheated steam section of the HRSG to generate 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, and superheating the saturated steam stream with the carbon dioxide-rich flue gas stream to generate a superheated steam stream, and is one, any, or all of the preceding embodiments of this paragraph to 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, which includes 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 CO2-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 CO2-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 a sulfur-containing compound, a nitrogen-containing compound, 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 generate a filtered reactor effluent stream, and collecting a carbon dioxide recycle stream from the filtered reactor effluent stream, and is a process for regenerating a catalyst from a fluid catalytic process.

[0073] A third embodiment of the present disclosure is an apparatus for regenerating a catalyst, including a heat recovery section including a superheated steam section and a saturated steam section, a flue gas inlet, a flue gas outlet, a saturated steam inlet, and a superheated steam outlet. The superheated steam section has a flue gas inlet of the superheated steam section in fluid communication with an outlet of a regenerator unit. The saturated steam section has a flue gas inlet, a flue gas outlet, a boiler feed water inlet, and a saturated steam outlet, and 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 has a flue gas inlet, a flue gas outlet, and a reactant inlet, and 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 has a flue gas inlet, a flue gas outlet, and a filter material outlet, and 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 has a flue gas inlet and a flue gas outlet, and 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 is in fluid communication with the flue gas outlet of the heat exchanger, and the carbon dioxide separation unit is in thermal communication with the flue gas outlet of the filter section via a carbon dioxide recirculation flow in the heat exchanger. The apparatus for regenerating a catalyst includes the carbon dioxide separation unit.

[0074] Without further elaboration, using the foregoing description, those 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 easily identify the essential characteristics of the present disclosure, 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 illustrative only and not as limiting the remainder of the present disclosure in any way, and are intended to cover various modifications and equivalent configurations within the scope of the appended claims.

[0075] In the above, all temperatures are described 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; collecting a carbon dioxide recycle stream from the carbon dioxide-rich flue gas stream; preheating the carbon dioxide recycle stream by heat exchange with the carbon dioxide-rich flue gas stream to provide the preheated carbon dioxide recycle stream.

2. reacting one or more of sulfur-containing compounds, nitrogen-containing compounds, or both in the carbon dioxide-rich flue gas stream with a reactant in a scrubbing reactor to form a reactor effluent stream containing a reactant salt; filtering the reactor effluent stream to remove the reactant salt and catalyst fines to produce a filtered reactor effluent stream; collecting a carbon dioxide recycle stream from the filtered reactor effluent stream. The process according to claim 1, further comprising:

3. The process according to claim 2, wherein the reactant is in a dry form.

4. The process according to claim 2, wherein the scrubbing 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 reactant.

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 supplied 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 the boiler feed water stream in the HRSG to form the partially cooled carbon dioxide-rich flue gas stream and the steam stream. Moving the partially cooled carbon dioxide-rich flue gas stream to the decontamination reactor, the process of claim 7, comprising:

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 of claim 7, further comprising:

10. An apparatus for regenerating a catalyst, 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, wherein the carbon dioxide separation unit is in thermal communication with the flue gas outlet of the filter section via a carbon dioxide recirculation stream in the heat exchanger, an apparatus for regenerating a catalyst.

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