Energy optimization in fluid catalytic cracking and dehydrogenation units.

Abstract

A process is described that involves the use of a dry sorbent injection (DSI) unit or a slurry reagent injection (SRI) unit to remove sulfur compounds from flue gas. For example, flue gas from an FCC regenerator is used to make superheated and saturated steam. The flue gas is then sent to a DSI unit to remove sulfur compounds and then to an economizer (or heat exchanger) to heat boiler feed water or combustion air. Additional energy can be recovered in the economizer because the temperature is not reduced as much as in the wet scrubber process.

Description

[Technical field]

[0001] (Statement of priority) This application claims priority to U.S. Patent Application No. 17 / 538,411, filed November 30, 2021, which is incorporated by reference in its entirety herein. [Background technology]

[0002] Conventional treatment of flue gas from fluid catalytic cracking (FCC) and fluidized bed dehydrogenation units 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 a temperature of 400-500°F to a temperature of 140-194°F using a water quench. The cooled flue gas is contacted with NaOH, which reacts with the sulfur compounds to form Na2SO3 and / or Na2SO4, and water, which are removed. 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. The treated flue gas can then be vented to the atmosphere.

[0003] However, this system has high capital costs and high operating costs due to the use of NaOH, water, electricity, flocculants, and slurry handling. Furthermore, this system requires a large area and is maintenance intensive. The wet scrubber process has high make-up water requirements due to the use of water quench and aqueous NaOH solution. This system also suffers from corrosion issues associated with the use of H2SO4 and concerns of spray nozzle fouling due to the presence of salt. Substantial amounts of sensible energy are not recovered due to SO3 (acid) dew point limitations. Insufficient energy recovery is due to high stack temperatures and insufficient thermal profile (quenching the boiler flue gas outlet to adiabatic saturation to enable wet sulfur removal and possibly then reheating the flue gas to the Selective Catalytic Reduction (SCR) inlet temperature requirements required to enable nitrogen (NOx) removal). This can result in a negative energy balance. Additionally, there can be problems with the H2SO4 / SO3 blue plume caused by the submicron aerosols (H2SO4) formed, and the white plume caused by water condensation when the flue gas is released to the atmosphere. This can be avoided by heating the stream, but this approach increases capital and operating costs.

[0004] Therefore, there is a need for improved processes for treating flue gases containing sulfur compounds. [Brief description of the drawings]

[0005] [Figure 1] 1 illustrates an embodiment of a method according to the present invention. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0006] This process involves the use of a dry sorbent injection (DSI) unit or a slurry reagent injection (SRI) unit to remove sulfur compounds from the flue gas. For example, flue gas from an FCC regenerator is used to make superheated and saturated steam. The flue gas is then sent to a DSI unit to remove sulfur compounds and then to an economizer (or heat exchanger) to heat boiler feed water, thermal oil, or combustion air. Because the flue gas temperature is not reduced as much as in the wet scrubber process, additional heat energy can be recovered from the flue gas in the economizer.

[0007] The increased energy recovery is directly correlated with the SOx content (acid dew point) of the flue gas. By utilizing a dry sorbent injection (DSI) system or a slurry reagent injection (SRI) system, the unharvested sensible heat energy can be captured, substantially improving the energy efficiency of the FCC unit and avoiding negative energy balance. The increased energy efficiency achieved by utilizing DSI and SRI systems instead of wet gas scrubber systems can also be applied to any type of FCC-style process or fluidized dehydrogenation process, such as fully-combusted and partially-combusted FCC units, and fluidized bed propane and / or butane dehydrogenation units, where flue gases having SOx concentrations above environmental limits are produced.

[0008] The process provides a substantial increase in energy recovery by adding an economizer downstream of the DSI (or SCR) or SRI, and an improved thermal profile in the case of downstream SCR (i.e., less reheat required to heat the effluent). Energy optimization is achieved by avoiding the need to cool the flue gas to adiabatic saturation temperature (e.g., 140-194°F). Instead, the temperature of the effluent is maintained after sulfur removal and particulate removal by a dry scrubber system or a slurry reagent injection system. Thus, the SO3 dew point limitation on the HRSG boiler is removed, and additional sensible energy can be removed down to the water dew point by implementing a gas-to-gas and / or gas-to-liquid heat exchanger downstream of the dry scrubber system, slurry reagent injection system, or nitrogen removal unit (e.g., in the form of an SCR). The recovered sensible energy can be used to preheat the boiler feed water used in the HRSG boiler and / or catalytic cooler, thereby reducing or eliminating the possibility of a negative energy balance. Low-pressure (LP) or medium pressure (MP) steam can be generated, which can be used in FCC processes, fluid dehydrogenation processes, and / or solvent-based carbon capture units. The value generated by additional energy recovery increases as the sulfur content in the flue gas increases, because SO3 dew point limitations limit the sensible heat recovery that can be performed in the HRSG.

[0009] The novel configuration allows for up to 20% additional thermal energy recovery by cooling the flue gas to 300°F instead of 450°F (made possible by performing sulfur removal at 450°F). This additional energy can be used to preheat combustion air for the CO combustor (if present) and / or DFAH, and / or boiler feed water for the HRSG and / or catalytic cooler (if present). The LP or MP streams can be used in the FCC process, the fluid dehydrogenation process, and / or the solvent-based carbon capture unit, as described above.

[0010] Removing sulfur upstream of the economizer reduces the risk of tube corrosion and greatly improves system reliability. The process reduces or eliminates corrosion (H2SO4) concerns in the sulfur removal step by staying above the water and acid dew points. By avoiding operation in corrosive conditions, stainless steel flue gas scrubbers are not required and the complete system can be made from carbon steel.

[0011] Additionally, because sulfur is removed, the flue gas outlet temperature at the economizer can be reduced from 450°F to 300°F. Thus, additional preheating of the boiler feed water (BFW) to 350°F is no longer required (typical BFW is 230-250°F), which eliminates the need for circulating (steam drum) water pumps (one-third of the BFW flow) and eliminates BFW dew point issues. This results in improved reliability and reduced maintenance requirements (e.g., fewer tube failures and fewer tube replacements).

[0012] Dry scrubbing or slurry injection systems significantly reduce or eliminate the need for make-up water by avoiding the need to quench the flue gas to adiabatic saturation temperatures (140-194°F), meet slurry handling concentration requirements, and maintain water balance. Because DSI technology does not require water, and water is considered a scarce resource, system water metrics are significantly improved. Make-up water consumption can be reduced by up to 60%.

[0013] The present invention also eliminates concerns about spray nozzle fouling by avoiding the need for complex slurry handling, and avoids the white plume as a result of water condensation and the blue plume as a result of H2SO4 aerosol emissions. In addition, when using NaHCO3, up to 21% of NO xReductions can be achieved, but system pressure drop can be up to 50% lower. When using KOH as the scrubbing reagent, the scrubbed residue is a K2SO4 / KNO3 fertilizer (4.47% CAGR) with saleable value.

[0014] In partial combustion FCC, the outlet temperature from the CO combustor is 890-1040°C.

[0015] In the case of partial combustion FCC, the outlet temperature from the FCC regenerator is 650-700°C. In the case of full combustion FCC, the outlet temperature is 690-740°C, while in the case of dehydrogenation process, the outlet temperature is 690-760°C.

[0016] In the case of partial combustion FCC, full combustion FCC and dehydrogenation processes, the flue gas outlet temperature from the HRSG is 200-290°C.

[0017] One aspect of the invention includes a method for treating flue gas from a fluid catalytic cracking (FCC) unit catalyst regenerator, an FCC unit catalyst regenerator CO burner, or a dehydrogenation unit catalyst regenerator. In one embodiment, the method includes the steps of transferring heat from a flue gas stream from the FCC unit catalyst regenerator, the FCC unit catalyst regenerator CO burner, or a dehydrogenation reactor to a boiler feed water stream in a heat recovery steam generator (HRSG) to form a cooled flue gas stream and a steam stream, the flue gas stream including one or more of sulfur-containing compounds, nitrogen-containing compounds, and catalyst fines, the flue gas stream having a temperature in the range of 200° C. to 290° C., the temperature being above the dew point of water, and reacting the one or more of the sulfur-containing compounds, the nitrogen-containing compounds, or both in the cooled flue gas stream from the HRSG with a reactant in a decontamination reactor, the reactant including one or more of NaHCO3, NaOH, KOH, Na2SO4, N forming a reactor effluent stream comprising one or more of NaNO3, NaNO2, Na2CO3, K2SO4, and KNO3 while maintaining the reactor effluent stream at a temperature in the range of 200°C to 290°C; filtering the reactor effluent stream to remove at least one of Na2SO4, NaNO3, NaNO2, Na2CO3, K2SO4, KNO3, and catalyst fines to form a filtered reactor effluent stream; and preheating a combustion air stream or a boiler feed water stream with the filtered reactor effluent stream, thereby reducing the temperature to between 130°C to 200°C and maintaining it above the dew point of water.

[0018] In some embodiments, preheating the combustion air stream or the boiler feed water stream with the filtered reactor effluent stream comprises preheating the combustion air stream or the boiler feed water stream with the filtered reactor effluent stream using a gas / gas heat exchanger or a gas / liquid heat exchanger.

[0019] In some embodiments, the flue gas stream comprises a flue gas stream from a partial combustion FCC unit regenerator, and the method further comprises combusting CO in the flue gas stream in a combustor to form a fully oxidized flue gas stream, and transferring heat from the flue gas stream comprises transferring heat from the fully oxidized flue gas stream.

[0020] In some embodiments, the combustion air stream is delivered to a CO combustor.

[0021] In some embodiments, filtering the reactor effluent stream comprises filtering the reactor effluent stream using a bag filter or an electrostatic precipitator.

[0022] In some embodiments, the method further includes splitting the filter material stream into two portions, recirculating a first portion to the decontamination reactor, and recovering a second portion.

[0023] In some embodiments, nitrogen-containing compounds are present in the cooled flue gas stream in an amount less than 1000 ppm(v) on a dry basis.

[0024] In some embodiments, sulfur-containing compounds are present in the cooled flue gas stream in an amount less than 5000 ppm(v) on a dry basis.

[0025] In some embodiments, the HRSG includes a superheated steam section and a saturated steam section, and transferring heat from the flue gas stream to the boiler feedwater stream includes introducing the flue gas stream into the superheated steam section to generate a superheated steam stream and a partially cooled flue gas stream, introducing the boiler feedwater stream and the partially cooled flue gas stream into the saturated steam section to generate 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 flue gas stream to generate the superheated steam stream.

[0026] In some embodiments, the reactants are in dry or slurried form.

[0027] Another aspect of the invention is a method for treating flue gas from a fluid catalytic cracking (FCC) unit catalyst regenerator, an FCC unit catalyst regenerator CO combustor, or a dehydrogenation unit catalyst regenerator. In one embodiment, the method includes the steps of: introducing a flue gas stream from an FCC unit catalyst regenerator, an FCC unit catalyst regenerator CO combustor, or a dehydrogenation reactor into a superheated steam section of a heat recovery steam generator (HRSG) to produce a superheated steam stream and a partially cooled flue gas stream, the HRSG including a superheated steam section and a saturated steam section, the flue gas stream including one or more of sulfur-containing compounds, nitrogen-containing compounds, and catalyst particulates, the flue gas stream having a temperature in the range of 200° C. to 290° C., the temperature being above a dew point of water; introducing a boiler feed water stream and the partially cooled flue gas stream into the saturated steam section of the HRSG to produce a saturated steam stream; introducing at least a portion of the saturated steam stream into the superheated steam section of the HRSG; superheating the saturated steam stream with the flue gas stream to produce the superheated steam stream; and removing the cooled flue gas stream from the HRSG. The method includes reacting one or more of sulfur-containing compounds, nitrogen-containing compounds, or both in the flue gas stream with reactants in a decontamination reactor, the reactants including one or more of NaHCO3, NaOH, KOH, and forming a reactor effluent stream including one or more of Na2SO4, NaNO3, NaNO2, Na2CO3, K2SO4, and KNO3, while maintaining the reactor effluent stream at a temperature in the range of 200°C to 290°C; filtering the reactor effluent stream using a bag filter or an electrostatic precipitator to remove at least one of Na2SO4, NaNO3, NaNO2, Na2CO3, K2SO4, KNO3, and catalyst fines to form a filtered reactor effluent stream; and preheating a combustion air stream or a boiler feed water stream with the filtered reactor effluent stream, thereby reducing the temperature to between 130°C to 200°C and maintaining it above the dew point of water.

[0028] In some embodiments, preheating the combustion air stream or the boiler feed water stream with the filtered reactor effluent stream comprises preheating the combustion air stream or the boiler feed water stream with the filtered reactor effluent stream using a gas / gas heat exchanger or a gas / liquid heat exchanger.

[0029] In some embodiments, the flue gas stream comprises a flue gas stream from a partial combustion FCC unit regenerator, and the method further comprises combusting CO in the flue gas stream in a combustor to form a fully oxidized flue gas stream, and transferring heat from the flue gas stream comprises transferring heat from the fully oxidized flue gas stream.

[0030] In some embodiments, the combustion air stream is delivered to a CO combustor.

[0031] In some embodiments, the method further includes splitting the filter material stream into two portions, recirculating a first portion to the decontamination reactor, and recovering a second portion.

[0032] In some embodiments, nitrogen-containing compounds are present in the cooled flue gas stream in an amount less than 1000 ppm(v) on a dry basis.

[0033] In some embodiments, sulfur-containing compounds are present in the cooled flue gas stream in an amount less than 5000 ppm(v) on a dry basis.

[0034] In some embodiments, the reactants are in dry or slurried form.

[0035] Another aspect of the invention is an apparatus for treating flue gas from a fluid catalytic cracking (FCC) unit catalyst regenerator, an FCC unit catalyst regenerator CO burner, or a dehydrogenation unit catalyst regenerator. In one embodiment, the apparatus comprises a heat recovery steam generator 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, the flue gas inlet of the superheated steam section being in fluid communication with an outlet of the FCC unit catalyst regenerator, the FCC unit catalyst regenerator CO burner, or the dehydrogenation unit catalyst regenerator, the saturated steam section having a flue gas inlet, a flue gas outlet, a boiler feed water inlet, and a saturated steam outlet, the flue gas inlet of the saturated steam section being in fluid communication with the flue gas outlet of the superheated steam section, and the saturated steam outlet of the saturated steam section being 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, the flue gas inlet of the decontamination reactor being 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, the flue gas inlet of the filter section being in fluid communication with the flue gas outlet of the decontamination reactor inlet; and a heat exchanger having a flue gas inlet and a flue gas outlet, the flue gas inlet of the heat exchanger being in fluid communication with the flue gas outlet of the filter section, the heat exchanger being in thermal communication with a boiler feedwater flow, the boiler feedwater flow being in fluid communication with the boiler feedwater inlet of the saturated steam section.

[0036] In some embodiments, the CO combustor has a flue gas inlet, a flue gas outlet, and a combustion air inlet, the flue gas outlet of the CO combustor in fluid communication with the flue gas inlet of the superheated steam section, the heat exchanger in thermal communication with the combustion air flow, and the combustion air flow in fluid communication with the combustion air inlet of the CO combustor.

[0037] The diagram illustrates one embodiment of process 100. For partially burned FCC flue gas, a flue gas stream 105 is sent to a CO combustor 110 along with a fuel gas stream 115 (or other fuel source) and combustion air 120 to combust the CO in the flue gas. The fully burned stream 125 is then sent to an HRSG superheated steam unit 130. The FCC regenerator flue gas exit temperature for partially burned FCC is in the range of 650-700°C, and the temperature after the CO combustor is 890-1040°C.

[0038] In the case of a full combustion FCC regenerator or a dehydrogenation unit catalyst regenerator, the flue gas stream 105 is sent to the HRSG superheated steam unit 130 and there is no CO combustor. The flue gas outlet temperature for the full combustion FCC case is in the range of 650-760°C, whereas for the dehydrogenation process it is in the range of 650-740°C.

[0039] The partially cooled flue gas stream 145 is sent to a HRSG saturated steam unit 150. The boiler feed water stream 135 is heated by the partially cooled flue gas stream 145 to form a saturated steam stream 160 and a condensate stream 165.

[0040] A portion 170 of the saturated steam stream 160 is sent to the HRSG steam superheat unit 130. The remainder 175 of the saturated steam stream 160 may be sent to other parts of the plant for use as needed.

[0041] The cooled flue gas stream 180 from the HRSG saturated steam unit 150 is mixed with reactants 185 (dry or slurry) and sent to the decontamination reactor 190, where the reactants react with sulfur-containing compounds. The filter zone 210 removes particulates and fines. When the filter zone 210 comprises an electrostatic precipitator, electricity is supplied to the filter zone 210, and / or IA is supplied to the filter zone 210 comprising a bag filter. Filtered material including one or more of Na2SO4, NaNO3, NaNO2, Na2CO3, K2SO4, and KNO3, and catalyst particulates is removed from the filter zone 210. The filtered material 220A can be removed from the process. Alternatively, or in addition, the filtered material 220B can be recycled to the decontamination reactor 190 to increase the Na2CO3 conversion yield (i.e., from 85% to 98% by weight).

[0042] The filtered flue gas 225 is sent to a heat exchanger 230 where it is heat exchanged with stream 235, which may be boiler feed water or combustion gas, to form a heated stream 240. If the heated stream 240 is boiler feed water, it may be sent to the HRSG saturated steam unit 150 as boiler feed water stream 155. If the heated stream 240 is combustion air, it may be sent to the CO combustor 110. Alternatively, or in addition, all or a portion 245 of the heated stream 240 may be sent to other areas of the plant as needed. For example, the heated boiler feed water may be sent to a catalyst cooler in the regenerator section, a main column bottoms generator, a reboiler in a downstream solvent-based CO2 capture plant, etc.

[0043] The heat exchanged combustion flue gas stream 250 may be discharged to the atmosphere. EXAMPLES

[0044] Example 1: Thermal energy recovery The simulation was performed assuming complete combustion with the FCC regenerator outlet temperature of 704°C (1300°F) and O2 concentration of 2%. Table 1 shows the combustion products.

[0045] [Table 1]

[0046] In the base case, the temperature is reduced from 704°C (1300°F) to 232°C (450°F), resulting in a recovery rate of 289.9 MMBTU / hr.

[0047] Using the DSI system, the temperature was reduced from 704°C (1300°F) to 149°C (300°F), resulting in a recovery rate of 337.0 MMBTU / hr, which represents a 16% (47.1 MMBTU / hr) increase in energy recovery.

[0048] The simulation was performed assuming partial combustion with the CO combustor outlet at 982°C (1800°F) and an O2 concentration of 2%. Table 2 shows the combustion products.

[0049] [Table 2]

[0050] In the base case, the temperature is reduced from 982°C (1800°F) to 232°C (450°F), resulting in a recovery rate of 629.7 MMBTU / hr.

[0051] Using the DSI system, the temperature was reduced from 982°C (1300°F) to 149°C (300°F), resulting in a recovery rate of 692.3 MMBTU / hr, which represents a 10% (62.5 MMBTU / hr) increase in energy recovery.

[0052] Example 2: Use of desulfurized make-up water Table 3 shows the flow rate, SOx content, and NaHCO3 make-up requirement of an FCC flue gas stream to desulfurize the flue gas. The purpose of this table is to show that make-up water is not required to desulfurize the flue gas stream. The following desulfurization reactions are occurring: 2NaHCO3 → Na2CO3 + CO2 + H2O Na2CO3+SO2+1 / 2O2→Na2SO4+CO2 Na2CO3+SO3→Na2SO4+CO2

[0053] [Table 3]

[0054] Table 4 shows the flow rate, SOx content, and NaOH(aq) make-up requirement of the FCC flue gas stream to desulfurize the flue gas. Table 4 shows that make-up water is required to desulfurize the flue gas stream because NaOH is injected into the scrubber as an aqueous solution (typically at a concentration of 20 wt%). The following desulfurization reactions are occurring: 2NaOH+SO2 →Na2SO3+H2O 2NaOH+SO3 →Na2SO4+H2O

[0055] What is not shown is that scrubber effluents are formed having Na salt concentrations of 5-10 wt %, thus requiring additional make-up water to avoid salt precipitation.

[0056] [Table 4]

[0057] Example 3: Use of Quench Water: Wet Scrubber vs. Dry Scrubber Table 5 shows that using a wet scrubber with a full-fired FCC regenerator requires 84,430 lb / hr of make-up water to quench the flue gas to adiabatic saturation temperature. The total amount of water to the atmosphere is 189,361 lb / hr.

[0058] [Table 5]

[0059] Table 6 shows that using a wet scrubber with a partial burn FCC regenerator requires 11,2300 lb / hr of make-up water to quench the flue gas to adiabatic saturation temperature. The amount of water vented to the atmosphere is 205,060 lb / hr.

[0060] [Table 6]

[0061] With the DSI system, the flue gas desulfurization can be done at high temperatures (above the acid and water dew points) so no make-up water is required. For the full burn FCC regenerator, the amount of water to atmosphere is 104,931 lb / hr, a savings of 45%. For the partial burn FCC regenerator, the amount of water to atmosphere is 137,760 lb / hr, a savings of 45%.

[0062] Specific Embodiments While the following will be described in conjunction with specific embodiments, it will be understood that this description is illustrative, but is not intended to limit the scope of the foregoing description and appended claims.

[0063] A first embodiment of the invention is a method for treating flue gas from a fluid catalytic cracking (FCC) unit catalyst regenerator, an FCC unit catalyst regenerator CO burner, or a dehydrogenation unit catalyst regenerator, comprising the steps of transferring heat from a flue gas stream from the FCC unit catalyst regenerator, the FCC unit catalyst regenerator CO burner, or the dehydrogenation reactor to a boiler feed water stream in a heat recovery steam generator (HRSG) to form a cooled flue gas stream and a steam stream, the flue gas stream comprising one or more of sulfur-containing compounds, nitrogen-containing compounds, and catalyst fines, the flue gas stream having a temperature in the range of 200° C. to 290° C., the temperature being greater than the dew point of water and an acid comprising sulfuric acid and / or sulfur trioxide; and transferring heat from the flue gas stream from the HRSG to a boiler feed water stream to form a cooled flue gas stream and a steam stream, the flue gas stream comprising one or more of sulfur-containing compounds, nitrogen-containing compounds, and catalyst fines, the flue gas stream having a temperature in the range of 200° C. to 290° C., the temperature being greater than the dew point of water and an acid comprising sulfuric acid and / or sulfur trioxide; with a reactant in a decontamination reactor, the reactants including one or more of NaHCO3, NaOH, KOH to form a reactor effluent stream including one or more of Na2SO4, NaNO3, NaNO2, Na2CO3, K2SO4, and KNO3, while maintaining the reactor effluent stream at a temperature in the range of 200°C to 290°C; filtering the reactor effluent stream to remove at least one of Na2SO4, NaNO3, NaNO2, Na2CO3, K2SO4, KNO3, and catalyst fines to form a filtered reactor effluent stream; and preheating a combustion air stream or a boiler feed water stream with the filtered reactor effluent stream, thereby reducing the temperature to between 130°C to 200°C and maintaining it above the dew point of water. An embodiment of the present invention is one, any, or all of the previous embodiments of this paragraph, including up to and including the first embodiment of this paragraph, wherein preheating the combustion air stream or the boiler feed water stream with the filtered reactor effluent stream comprises preheating the combustion air stream or the boiler feed water stream with the filtered reactor effluent stream using a gas / gas heat exchanger or a gas / liquid heat exchanger.An embodiment of the invention is one, any, or all of the previous embodiments of this paragraph, including through the first embodiment of this paragraph, where the flue gas stream comprises a flue gas stream from a partial combustion FCC unit regenerator, the method further comprises combusting CO in the flue gas stream in a combustor to form a fully oxidized flue gas stream, and where transferring heat from the flue gas stream comprises transferring heat from the fully oxidized flue gas stream. An embodiment of the invention is one, any, or all of the previous embodiments of this paragraph, including through the first embodiment of this paragraph, where the combustion air stream is sent to a CO combustor. An embodiment of the invention is one, any, or all of the previous embodiments of this paragraph, including through the first embodiment of this paragraph, where filtering the reactor effluent stream comprises filtering the reactor effluent stream using a bag filter or an electrostatic precipitator. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including the first embodiment of this paragraph, further comprising splitting the filter material stream into two portions, recycling the first portion to the decontamination reactor, and recovering the second portion. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including the first embodiment of this paragraph, wherein the nitrogen-containing compounds are present in the cooled flue gas stream in an amount less than 1000 ppm(v) on a dry basis. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including the first embodiment of this paragraph, wherein the sulfur-containing compounds are present in the cooled flue gas stream in an amount less than 5000 ppm(v) on a dry basis.An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including up to and including the first embodiment of this paragraph, wherein the HRSG includes a superheated steam section and a saturated steam section, and wherein transferring heat from the flue gas stream to the boiler feedwater stream includes: introducing the flue gas stream into the superheated steam section to produce a superheated steam stream and a partially cooled flue gas stream; introducing the boiler feedwater stream and the partially cooled flue gas stream into the saturated steam section to produce 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 flue gas stream to produce the superheated steam stream. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including up to and including the first embodiment of this paragraph, wherein the reactants are in dry or slurried form.

[0064] A second embodiment of the present invention is a method for treating flue gas from a fluid catalytic cracking (FCC) unit catalyst regenerator, an FCC unit catalyst regenerator CO burner, or a dehydrogenation unit catalyst regenerator, comprising the steps of: introducing a flue gas stream from the FCC unit catalyst regenerator, the FCC unit catalyst regenerator CO burner, or the dehydrogenation reactor into a superheated steam section of a heat recovery steam generator (HRSG) to produce a superheated steam stream and a partially cooled flue gas stream, the HRSG comprising a superheated steam section and a saturated steam section, the flue gas stream comprising one or more of sulfur-containing compounds, nitrogen-containing compounds, and catalyst fines, the flue gas stream having a temperature in the range of 200° C. to 290° C., the temperature being greater than a dew point of water and an acid comprising sulfuric acid and / or sulfur trioxide; introducing a boiler feed water stream and the partially cooled flue gas stream into the saturated steam section of the HRSG to produce a saturated steam stream; introducing at least a portion of the saturated steam stream into the superheated steam section of the HRSG; superheating the stream with a flue gas stream to produce a superheated steam stream; and reacting one or more of sulfur-containing compounds, nitrogen-containing compounds, or both in the cooled flue gas stream from the HRSG with reactants in a decontamination reactor, the reactants comprising one or more of NaHCO3, NaOH, KOH, and forming a reactor effluent stream comprising one or more of Na2SO4, NaNO3, NaNO2, Na2CO3, K2SO4, and KNO3, while heating the reactor effluent stream at a temperature in the range of 200° C. to 290° C. maintaining a temperature of ambient air; filtering the reactor effluent stream using a bag filter or electrostatic precipitator to remove at least one of the Na2SO4, NaNO3, NaNO2, Na2CO3, K2SO4, KNO3, and the catalyst fines to form a filtered reactor effluent stream; and preheating a combustion air stream or a boiler feed water stream with the filtered reactor effluent stream, thereby reducing the temperature to between 130° C. and 200° C. and maintaining it above the dew point of water.An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including through the second embodiment of this paragraph, where preheating the combustion air stream or the boiler feed water stream with the filtered reactor effluent stream comprises preheating the combustion air stream or the boiler feed water stream with the filtered reactor effluent stream using a gas-to-gas heat exchanger or a gas-to-liquid heat exchanger. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including through the second embodiment of this paragraph, where the flue gas stream comprises a flue gas stream from a partial combustion FCC unit regenerator, the method further comprises combusting CO in the flue gas stream in a combustor to form a fully oxidized flue gas stream, and transferring heat from the flue gas stream comprises transferring heat from the fully oxidized flue gas stream. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including through the second embodiment of this paragraph, where the combustion air stream is sent to a CO combustor. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including up to the second embodiment of this paragraph, further comprising splitting the filter material stream into two portions, recycling the first portion to the decontamination reactor, and recovering the second portion. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including up to the second embodiment of this paragraph, wherein the nitrogen-containing compounds are present in the cooled flue gas stream in an amount less than 1000 ppm(v) on a dry basis. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including up to the second embodiment of this paragraph, wherein the nitrogen-containing compounds are present in the cooled flue gas stream in an amount less than 5000 ppm(v) on a dry basis. An embodiment of the present invention is any one, any or all of the previous embodiments of this paragraph, including up to the second embodiment of this paragraph, wherein the reactants are in dry or slurried form.

[0065] A third embodiment of the invention is an apparatus for treating flue gas from a fluid catalytic cracking (FCC) unit catalyst regenerator, an FCC unit catalyst regenerator CO burner, or a dehydrogenation unit catalyst regenerator, comprising a heat recovery steam generator 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, the flue gas inlet of the superheated steam section being in fluid communication with an outlet of the FCC unit catalyst regenerator, the FCC unit catalyst regenerator CO burner, or the dehydrogenation unit catalyst regenerator, the saturated steam section having a flue gas inlet, a flue gas outlet, a boiler feed water inlet, and a saturated steam outlet, the flue gas inlet of the saturated steam section being in fluid communication with the flue gas outlet of the superheated steam section, and the saturated steam outlet of the saturated steam section. the heat recovery steam generator 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, the flue gas inlet of the decontamination reactor 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, the flue gas inlet of the filter section in fluid communication with the flue gas outlet of the decontamination reactor inlet; and a heat exchanger having a flue gas inlet and a flue gas outlet, the flue gas inlet of the heat exchanger in fluid communication with the flue gas outlet of the filter section, the heat exchanger in thermal communication with a boiler feedwater flow, the boiler feedwater flow in fluid communication with the boiler feedwater inlet of the saturated steam section. An embodiment of the invention is one, any, or all of the previous embodiments in this paragraph, including through the third embodiment of this paragraph, wherein the CO combustor has a flue gas inlet, a flue gas outlet, and a combustion air inlet, the flue gas outlet of the CO combustor in fluid communication with the flue gas inlet of the superheated steam section, the heat exchanger in thermal communication with the combustion air flow, and the combustion air flow in fluid communication with the combustion air inlet of the CO combustor.

[0066] Without further elaboration, it is believed that, using the preceding description, one skilled in the art can utilize the present invention to its fullest extent and easily ascertain the essential characteristics of the present invention, and can make various changes and modifications to the present invention to adapt it to various uses and conditions, without departing from the spirit and scope of the present invention. The preceding preferred specific embodiments are therefore to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way, but are intended to cover various modifications and equivalent arrangements falling within the scope of the appended claims.

[0067] Above, all temperatures are set forth in degrees Celsius and all parts and percentages are by weight unless otherwise stated.

Claims

1. 1. A method for treating flue gas from a fluid catalytic cracking (FCC) unit catalyst regenerator, an FCC unit catalyst regenerator CO combustor, or a dehydrogenation unit catalyst regenerator, comprising: transferring heat from a flue gas stream (125) from the FCC unit catalyst regenerator, the FCC unit catalyst regenerator CO combustor, or the dehydrogenation reactor to a boiler feed water stream (155) in a heat recovery steam generator (HRSG) to form a cooled flue gas stream (145) and a steam stream (140), wherein the flue gas stream (125) comprises one or more of sulfur-containing compounds, nitrogen-containing compounds, and catalyst fines, and the flue gas stream (145) has a temperature in the range of 200° C. to 290° C., the temperature being greater than the dew point of water and an acid comprising sulfuric acid and / or sulfur trioxide; Reacting one or more of the sulfur-containing compounds, the nitrogen-containing compounds, or both in the cooled flue gas stream from the HRSG with a reactant (185) in a decontamination reactor (190), the reactant (185) being NaHCO ３ , NaOH, KOH, ２ SO ４ , NaNO ３ , NaNO ２ , Na ２ CO ３ , K ２ SO ４ , and KNO ３ forming a reactor effluent stream (195) comprising one or more of: The reactor effluent stream (195) is filtered to remove the Na ２ SO ４ , the NaNO ３ , the NaNO ２ , the Na ２ CO ３ , the K ２ SO ４ , the KNO ３ and removing at least one of the catalyst fines to form a filtered reactor effluent stream (225). preheating a combustion air stream or boiler feed water stream (235) with said filtered reactor effluent stream (225), thereby reducing the temperature to between 130°C and 200°C and maintaining it above the dew point of water; A method comprising:

2. 2. The method of claim 1, wherein preheating the combustion air stream or the boiler feedwater stream (235) with the filtered reactor effluent stream (225) comprises preheating the combustion air stream or the boiler feedwater stream (235) with the filtered reactor effluent stream (225) using a gas / gas heat exchanger or a gas / liquid heat exchanger (230).

3. The flue gas stream (125) comprises a flue gas stream (125) from a partial combustion FCC unit regenerator (110), and the method comprises:

2. The method of claim 1, further comprising: combusting CO in the flue gas stream (105) in a CO combustor (110) to form a fully oxidized flue gas stream (125), and wherein transferring heat from the flue gas stream (125) comprises transferring heat from the fully oxidized flue gas stream (125).

4. The method of claim 3 , wherein the combustion air stream (120) is delivered to the CO combustor (110).

5. 2. The method of claim 1, wherein filtering the reactor effluent stream (195) comprises filtering the reactor effluent stream (195) using a bag filter or an electrostatic precipitator (210).

6. splitting the filter material stream into two portions (220A and 220B); recycling a first portion (220B) to said decontamination reactor (190); recovering the second portion (220A); The method of claim 1 further comprising:

7. 2. The method of claim 1, wherein the nitrogen-containing compounds are present in the cooled flue gas stream in an amount less than 1000 ppm(v) on a dry basis.

8. 2. The method of claim 1, wherein the sulfur-containing compounds are present in the cooled flue gas stream in an amount less than 5000 ppm(v) on a dry basis.

9. The HRSG includes a superheated steam section (130) and a saturated steam section (150), and the step of transferring heat from the flue gas flow (125) to the boiler feedwater flow (155) comprises: introducing said flue gas stream (125) into said superheated steam section (130) to produce a superheated steam stream (140) and a partially cooled flue gas stream (145); introducing the boiler feedwater stream (155) and the partially cooled flue gas stream (145) into the saturated steam section (150) to produce a saturated steam stream (160); introducing at least a portion (170) of the saturated steam stream (160) into the superheated steam section (130); superheating said saturated steam stream (170) with said flue gas stream (125) to produce said superheated steam stream (140); The method of claim 1 , comprising:

10. The method of claim 1 , wherein the reactants (185) are in dry or slurried form.

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