Dehydrogenation process for alkanes and alkylaromatic hydrocarbons.

Abstract

A hydrocarbon feed may be contacted with the dehydrogenation catalyst particles to produce a conversion effluent comprising coked catalyst particles and dehydrogenated hydrocarbons. The coked catalyst particles may be contacted with an oxidant and a fuel to produce a combustion effluent which may comprise low-coke catalyst particles and combustion gases. The low-coke catalyst particles may be contacted with an oxidizing gas at an oxidation temperature for a duration of at least 30 seconds to produce conditioned catalyst particles which may have an activity which may be lower than the coked catalyst particles. The conditioned catalyst particles may be contacted with a reducing gas to produce regenerated catalyst particles which may have a dehydrogenation activity which may be higher than the coked catalyst particles. The dehydrogenated hydrocarbons may be cooled and compressed, and a number of products may be separated from the compressed gas stream.

Description

[Technical field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims priority to and the benefit of U.S. Provisional Application No. 63 / 232,959, filed August 13, 2021, and U.S. Provisional Application No. 63 / 328,971, filed April 8, 2022, the disclosures of both of which are incorporated herein by reference in their entireties.

[0002] Field The present disclosure relates to 1 The present disclosure relates to a process for the dehydrogenation of one or more alkanes and / or one or more alkylaromatic hydrocarbons in the presence of fluidized catalyst particles to produce an effluent comprising one or more olefins. [Background technology]

[0003] background The catalytic dehydrogenation of alkanes and / or alkylaromatic hydrocarbons is an endothermic, equilibrium-limited, industrially important chemical conversion process. Alkanes, e.g., C2-C 16 Dehydrogenation of alkanes and / or alkyl aromatic hydrocarbons, such as ethylbenzene, can be accomplished via a variety of different supported catalyst particle systems, such as Pt-, Cr-, Ga-, V-, Zr-, In-, W-, Mo-, Zn-, and Fe-based systems. Among the existing propane dehydrogenation processes, certain processes use an alumina-supported chromia catalyst, which provides one of the highest propylene yields of about 50% (55% propane conversion with 90% propylene selectivity), which is achieved at temperatures of about 560°C to 650°C and low pressures of 20 kPa absolute to 50 kPa absolute. It is desirable to increase the propylene yield to increase the efficiency of the dehydrogenation process without having to operate at such low pressures. Increasing the temperature of the dehydrogenation process is one way to increase the conversion of the process according to the thermodynamics of the process. For example, at 670° C. and 100 kPa absolute pressure, in the absence of any inert / diluent, the equilibrium propylene yield was estimated by simulation to be about 74%. However, at such high temperatures, the catalyst particles are deactivated very quickly and / or the propylene selectivity becomes uneconomically low. The rapid deactivation of the catalyst particles is believed to be due to coke deposition and / or agglomeration of the active phase on the catalyst particles. Although the coke can be removed by combustion with an oxygen-containing gas, the agglomeration of the active phase is believed to be exacerbated during the combustion process, which rapidly reduces the activity and stability of the catalyst particles. Thus, there is a need for improved processes for dehydrogenating alkanes and / or alkylaromatic hydrocarbons. The present disclosure meets this and other needs. Summary of the Invention

[0004] summary A process for upgrading alkane and / or alkylaromatic hydrocarbons is provided. In some embodiments, the hydrocarbon upgrading process may include (I) contacting a hydrocarbon-containing feed with fluidized dehydrogenation catalyst particles in a conversion zone to effect dehydrogenation of at least a portion of the hydrocarbon-containing feed to produce a conversion effluent that may include coked catalyst particles and one or more dehydrogenated hydrocarbons. The hydrocarbon-containing feed may be one or more C2-C 16 Linear or branched alkanes, at least one C4-C 16 Cyclic alkanes, one or more of C8-C 16 The hydrocarbon-containing feed may contain any C2-C alkyl aromatic hydrocarbons, alkyl aromatic hydrocarbons, or mixtures thereof. 16 Alkanes and any C8-C 16 Based on the mass of aromatic hydrocarbons, 0.1 hours -1 ~1,000 hours -1 The catalyst particles may be contacted at mass hourly space velocities in the range of C2-C 16 Alkanes and any C8-C 16The mass ratio of the fluidized dehydrogenation catalyst particles to the total amount of aromatic hydrocarbons may range from 3 to 100. The hydrocarbon-containing feed and the catalyst particles may be contacted at a temperature ranging from 600° C. to 750° C. The process may also include the step of (II) separating from the conversion effluent a first particulate stream rich in coked catalyst particles and a first gaseous stream rich in one or more dehydrogenated hydrocarbons. The process may also include the step of (III) contacting at least a portion of the coked catalyst particles in the first particulate stream with an oxidant and a fuel in a combustion zone to cause combustion of at least a portion of the coke to produce a combustion effluent that may include coke-reduced catalyst particles and combustion gases. The dehydrogenation activity of the coke-reduced catalyst particles may be lower than the dehydrogenation activity of the coked catalyst particles. The process may also include the step of (IV) separating from the combustion effluent a second particulate stream rich in coke-reduced catalyst particles and a second gaseous stream rich in combustion gases. The process may also include (V) contacting at least a portion of the low-coke catalyst particles in the second particle stream with an oxidizing gas in an oxygen soak zone at an oxidation temperature in the range of 620° C. to 1,000° C. for a duration of at least 30 seconds to produce conditioned catalyst particles having an activity that may be lower than the coked catalyst particles. The process may also include (VI) contacting at least a portion of the conditioned catalyst particles with a reducing gas in a reduction zone to produce regenerated catalyst particles having a dehydrogenation activity that may be higher than the coked catalyst particles. The process may also include (VII) contacting an additional amount of a hydrocarbon-containing feed with at least a portion of the regenerated catalyst particles in a conversion zone to produce an additional amount of a converted effluent that may include recoked catalyst particles and an additional amount of one or more dehydrogenated hydrocarbons. The process may also include (VIII) cooling the first gas stream to produce a cooled gas stream. The process may also include (IX) compressing at least a portion of the cooled gas stream to produce a compressed gas stream. The process may also include the step of (X) separating a plurality of products from the compressed gas stream. [Brief description of the drawings]

[0005] [Figure 1] According to one or more described embodiments, a system for dehydrogenating a hydrocarbon-containing feed is provided. [Diagram 2] It is shown that the catalyst composition was stable for propane dehydrogenation for more than 60 cycles. [Diagram 3] It is shown that the catalyst composition (Catalyst 10) maintained its performance over 204 cycles. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0006] Detailed Description Below, various specific embodiments, versions and examples of the present invention are described, including preferred embodiments and definitions adopted herein for the purpose of understanding the claimed invention. The detailed description below provides certain preferred embodiments, but those skilled in the art will recognize that these embodiments are merely exemplary and that the present invention may be practiced in other ways. For purposes of determining infringement, the scope of the present invention refers to any one or more of the appended claims, including their equivalents, and elements or limitations that are equivalent to those recited. Any reference to the "invention" may refer to one or more, but not necessarily all, of the invention defined by the claims. In this disclosure, a process is described as including at least one "step." Each step should be understood to be an act or operation that may be performed once in the process or multiple times in a continuous or discontinuous manner. Unless otherwise specified or the context clearly indicates otherwise, the steps of the process may be performed consecutively in the order as described, with or without overlap with one or more other steps, or, in some cases, in any other order. Furthermore, one or more or even all steps may be performed simultaneously on the same or different batches of material. For example, in a continuous process, a first step of the process may be performed on raw material just fed at the beginning of the process while a second step may be performed simultaneously on intermediate material resulting from processing of raw material fed to the process at an earlier point in the first step. Preferably, the steps are performed in the order as described.

[0007] Unless otherwise indicated, all numbers indicating quantities in this disclosure should be understood to be modified in all cases by the term "about". It should also be understood that the exact numerical values ​​used in the specification and claims constitute specific embodiments. Efforts have been made to ensure the accuracy of the example data. However, it should be understood that any measured data inherently contains a certain level of error due to the limitations of the techniques and / or instruments utilized to make the measurements. Certain embodiments and features are described herein with a series of upper numerical limits and a series of lower numerical limits, and unless otherwise indicated, it should be understood that ranges including any combination of two values ​​are contemplated, for example, any combination of a lower limit with any upper limit, any combination of two lower limits, and / or any combination of two upper limits. As used herein, the indefinite article "a" or "an" means "at least one" unless otherwise specified or the context clearly dictates otherwise. Thus, embodiments using "a reactor" or "a conversion zone" include embodiments using one, two, or more than two reactors or conversion zones, unless otherwise specified or the context clearly dictates that only one reactor or conversion zone is used.

[0008] As used herein, the terms "up" and "down," "upward" and "downward," "upper" and "lower," "upwardly" and "downward," "above" and "below," and other similar terms refer to positions relative to one another and are not intended to imply a specific spatial orientation, as devices and methods using the same terms may be equally effective at various angles or orientations. The term "hydrocarbon" means (i) any compound consisting of hydrogen atoms and carbon atoms or (ii) any mixture of two or more of such compounds of (i). The term "Cn hydrocarbon" (where n is a positive integer) means (i) any hydrocarbon compound containing a total of n carbon atoms in its molecule or (ii) any mixture of two or more of such hydrocarbon compounds of (i). Thus, C2 hydrocarbons can be ethane, ethylene, acetylene, or any mixture in any ratio of at least two of these compounds. "Cm~Cn hydrocarbon" or "Cm-Cn hydrocarbon" (where m and n are positive integers and m < n) means any one of Cm, Cm+1, Cm+2, ..., Cn-1, Cn hydrocarbons, or any mixture of two or more of these. Thus, "C2~C3 hydrocarbon" or "C2-C3 hydrocarbon" can be any one of ethane, ethylene, acetylene, propane, propene, propyne, propadiene, cyclopropane, and any mixture in any ratio of two or more of these components. "Saturated C2-C3 hydrocarbon" can be ethane, propane, cyclopropane, or any mixture in any ratio of two or more of these. "Cn+ hydrocarbon" means (i) any hydrocarbon compound containing at least n carbon atoms in total in its molecule or (ii) any mixture of two or more of such hydrocarbon compounds of (i). "Cn- hydrocarbon" means (i) any hydrocarbon compound containing at most n carbon atoms in total in its molecule or (ii) any mixture of two or more of such hydrocarbon compounds of (i). "Cm hydrocarbon stream" means a hydrocarbon stream consisting essentially of Cm hydrocarbons. "Cm-Cn hydrocarbon stream" means a hydrocarbon stream consisting essentially of Cm-Cn hydrocarbons.

[0009] For the purposes of this disclosure, the nomenclature of elements is that of Hawley's Condensed Chemical Dictionary, 16 thThe periodic table is based on the version of the periodic table (under new notation) provided in Ed., John Wiley & Sons, Inc., (2016), Appendix V. For example, group 8 elements include Fe, group 9 elements include Co, and group 10 elements include Ni. As used herein, the term "metalloid" refers to the following elements: B, Si, Ge, As, Sb, Te, and At. In this disclosure, when a given element is indicated as being present, it may be present in the elemental state or as any compound thereof, unless otherwise stated or the context clearly indicates otherwise. The term "alkane" means a saturated hydrocarbon. The term "cyclic alkane" means a saturated hydrocarbon that contains a cyclic carbon ring in its molecular structure. Alkanes can be straight-chained, branched, or cyclic. The term "aromatic" is to be understood in accordance with its art-recognized scope and includes alkyl substituted and unsubstituted mononuclear and polynuclear compounds. When used in expressions such as "X-rich" or "rich in X" with respect to an exit stream obtained from an apparatus, e.g., a conversion zone, the term "rich" means that the stream contains material X at a higher concentration than in the feed material supplied to the same apparatus from which the stream is withdrawn. When used in expressions such as "X-lean" or "lean in X" with respect to an exit stream obtained from an apparatus, e.g., a conversion zone, the term "lean" means that the stream contains material X at a lower concentration than in the feed material supplied to the same apparatus from which the stream is withdrawn.

[0010] The term "mixed metal oxide" refers to a composition that contains oxygen atoms and at least two different metal atoms that are intermixed on an atomic scale. For example, a "mixed Mg / Al metal oxide" has O, Mg, and Al atoms intermixed on an atomic scale and is substantially identical to the composition obtained by calcining Mg / Al hydrotalcite having the general chemical formula: [ka] In the formula, A is the counter anion of the negative charge n, x ranges from >0 to <e1, and m is ≥0. The material composed of nm-sized MgO particles and nm-sized Al2O3 particles mixed together is not a mixed metal oxide because Mg atoms and Al atoms are not mixed at the atomic scale but at the nm scale.

[0011] The term "selectivity" refers to the production rate of a specific compound (on a carbon molar basis) in a catalytic reaction. As an example, the expression "the alkane hydrocarbon conversion reaction has 100% selectivity for olefin hydrocarbons" means that 100% (on a carbon molar basis) of the alkane hydrocarbons converted in the reaction are converted into olefin hydrocarbons. When used with respect to a specific reactant, the term "conversion rate" means the amount of the reactant consumed in the reaction. For example, when the specific reactant is propane, a 100% conversion rate means that 100% of the propane is consumed in the reaction. The yield (on a carbon molar basis) is the conversion rate × selectivity. The term "plenum" means a region in a reactor or separator that facilitates fluid communication between the tubes or ducts that carry the hot product stream from the reactor or separator to the outlet. A reactor or separator may have multiple plenums, for example, a first plenum and a second plenum, and the term plenum refers to any of the multiple plenums unless otherwise specified. The term "slurry" means any liquid stream that contains fine powder or solid in an amount up to 20 wt% based on the mass of the slurry. The term "sludge" means any liquid stream that contains fine powder or solid in the range from >20 wt% to 40 wt% based on the mass of the slurry. The term "cake" means any liquid stream that contains fine powder or solid in an amount >40 wt% based on the mass of the slurry.

[0012] Summary The hydrocarbon-containing feed may be contacted with the fluidized dehydrogenation catalyst particles in any suitable conversion zone to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed to produce a conversion effluent that may include coked catalyst particles and one or more dehydrogenated hydrocarbons. The hydrocarbon-containing feed may be one or more C2-C 16 Linear or branched alkanes, at least one C4-C 16 Cyclic alkanes, one or more of C8-C 16 In some embodiments, the one or more dehydrogenated hydrocarbons may be or include ethylene, propylene, one or more butenes, one or more pentenes, or mixtures thereof. In some embodiments, the conversion effluent may also include benzene. The hydrocarbon-containing feed may be any C2-C 16 Alkanes and any C8-C 16 Based on the mass of aromatic hydrocarbons, 0.1 hours -1 ~1,000 hours -1 The catalyst particles may be contacted at mass hourly space velocities in the range of C2-C 16 Alkanes and any C8-C 16 The mass ratio of the fluidized dehydrogenation catalyst particles to the total amount of aromatic hydrocarbons may range from 3 to 100. The hydrocarbon-containing feed and the catalyst particles may be contacted at a temperature ranging from 600°C to 750°C. From the conversion effluent, a first particulate stream rich in coked catalyst particles and a first gaseous stream rich in one or more dehydrogenated hydrocarbons may be separated or otherwise obtained. In some embodiments, the first particulate stream and the first gaseous stream may be separated from the conversion effluent in one or more separation devices or gas-solid separators. In some embodiments, the first particulate stream and the first gaseous stream may be separated from the conversion effluent by one or more cyclones. In some embodiments, the first particulate stream and the first gaseous stream may be separated from the conversion effluent in a primary separation device and a secondary separation device downstream and in fluid communication with the primary separation device, such as a primary cyclone and a secondary cyclone. In some embodiments, the first particulate stream and the first gaseous stream may be separated from the conversion effluent in a primary separation device.

[0013] In some embodiments, at least a portion of the coked catalyst particles in the first particle stream may be contacted with an oxidant and a fuel in a combustion zone to cause at least a portion of the coke to be combusted to produce a combustion effluent that may include reduced coke catalyst particles and combustion gases. In such embodiments, a portion of the heat required to produce reduced coke catalyst particles is provided by the combustion of the fuel. In other embodiments, at least a portion of the coked catalyst particles in the first particle stream may be contacted with an oxidant in a combustion zone to cause at least a portion of the coke to be combusted to produce a combustion effluent that may include reduced coke catalyst particles and combustion gases. In such embodiments, any hydrocarbons present in the combustion zone may be from entrained hydrocarbons from the conversion effluent. In other words, in such embodiments, no supplemental fuel is introduced into the combustion zone. More precisely, a portion of the heat required to produce reduced coke catalyst particles may be provided by an electric heater or other heating device. In both embodiments that use a fuel or an electric heater, respectively, to provide a portion of the heat required to produce reduced coke catalyst particles, the dehydrogenation activity of the reduced coke catalyst particles may be lower than the dehydrogenation activity of the coked catalyst particles.

[0014] A second particulate stream rich in catalyst particles with less coke and a second gaseous stream rich in combustion gases may be separated from the combustion effluent. In some embodiments, the second particulate stream and the second gaseous stream may be separated from the combustion effluent in one or more separators or gas-solid separators. In some embodiments, the second particulate stream and the second gaseous stream may be separated from the combustion effluent by one or more cyclones, e.g., one cyclone or two, three, four, or five or more cyclones connected in series. In some embodiments, the second particulate stream and the second gaseous stream may be separated from the combustion effluent in a primary separator and a secondary separator downstream and in fluid communication with the primary separator, e.g., a primary cyclone and a secondary cyclone. In some embodiments, the second particulate stream and the second gaseous stream may be separated from the combustion effluent in the primary separator. In some embodiments, the combustion zone may include a dense fluidized bed operating in a bubbling regime, a turbulent regime, or a fast fluidization regime. In such an embodiment, a second particle stream, rich in catalyst particles and low in coke, may be withdrawn from the dense bed.

[0015] In some embodiments, when fuel is introduced into the combustion zone, at least a portion of the low coke catalyst particles in the second particle stream may be contacted with an oxidizing gas for a duration or time to produce conditioned catalyst particles that may have a lower dehydrogenation activity than the dehydrogenation activity of the coked catalyst particles in the oxygen-soaked zone. In some embodiments, when fuel is introduced into the combustion zone, at least a portion of the low coke catalyst particles in the second particle stream may be contacted with an oxidizing gas for a duration of at least 30 seconds at an oxidation temperature in the range of 620° C. to 1,000° C. to produce conditioned catalyst particles. In some embodiments, when supplemental fuel is not introduced into the combustion zone and heat is provided to the combustion zone using an electric heater, the low coke catalyst particles in the second particle stream may avoid contact with an oxidizing gas in the oxygen-soaked zone. In some embodiments, at least a portion of the conditioned catalyst particles may be contacted with a reducing gas in a reduction zone to produce regenerated catalyst particles having a higher dehydrogenation activity than the coked catalyst particles. In other embodiments, when supplemental fuel is not introduced into the combustion zone and heat is provided therein using an electric heater, at least a portion of the low-coke catalyst particles in the second particle stream may be contacted with a reducing gas in a reduction zone to produce regenerated catalyst particles having a higher dehydrogenation activity than the coked catalyst particles. It has been found that the catalyst particles disclosed herein exhibit improved activity and selectivity after undergoing a reduction step before recontacting with an additional amount of a hydrocarbon-containing feed. Furthermore, the reduced catalyst particles may maintain the improved activity and selectivity for 10 minutes or more in the presence of a hydrocarbon-containing feed. In some embodiments, the first gaseous stream rich in the dehydrogenated hydrocarbon(s) may be cooled to produce a cooled gaseous stream. At least a portion of the cooled gaseous stream may be compressed to produce a compressed gaseous stream. A number of products may be separated from the compressed gaseous stream.

[0016] Hydrocarbon Dehydrogenation Process The hydrocarbon-containing feed may be contacted with the dehydrogenation catalyst particles in any suitable conversion zone to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed to produce a conversion effluent that may include coked catalyst particles and one or more dehydrogenated hydrocarbons. In some embodiments, the conversion effluent may also include benzene. In some embodiments, the dehydrogenation catalyst particles may include a Group 8-10 element disposed on a support. In some embodiments, the hydrocarbon-containing feed and the dehydrogenation catalyst particles may be contacted in the conversion zone in a conversion zone disposed in a continuous type process typically utilized in a fluidized bed reactor. In some embodiments, the conversion zone may be disposed in a riser reactor. In other embodiments, the conversion zone may be disposed in a downer reactor. In yet other embodiments, the conversion zone may be disposed in a vortex reactor. In other embodiments, the conversion zone may be disposed in a reactor to allow the fluidized dehydrogenation catalyst particles to form a relatively dense turbulent or fast fluidized bed therein during contact with the hydrocarbon-containing feed. Relatively dense turbulent or fast fluidized bed means a fluidized bed with a gas superficial velocity greater than the transition velocity, expressed as the critical velocity between the bubbling and turbulent bed transition, but less than the transport velocity that defines the air transport regime in which the dehydrogenation catalyst particles are carried, as in a riser reactor. In other embodiments, the conversion zone may be arranged with a dehydrogenation reactor that includes a lower section operating as a fast fluidized or turbulent bed and an upper section operating as a riser with the average catalyst flow and the average gas flow simultaneously upward. In other embodiments, the conversion zone and the combustion zone may be located in a modified fluid catalytic cracking reactor-regenerator unit. The modified fluid catalytic cracking reactor-regenerator unit may have been previously utilized to carry out a fluid catalytic cracking process modified for use in the dehydrogenation process described herein. For example, an oxygen soak zone and a reduction zone may be incorporated into the fluid catalytic cracking reactor-regenerator to provide a suitable modified fluid catalytic cracking unit.

[0017] Any number of reactors may be operated in series and / or parallel. Any two or more types of reactors may be used in combination with each other. When two or more reactors are used, the reactors may be operated at the same and / or different conditions and may receive the same or different hydrocarbon-containing feeds. When two or more reactors are used, the reactors may be arranged in series, parallel, or combinations thereof with respect to each other. In some embodiments, suitable reactors may be or include, but are not limited to, high gas velocity riser reactors, high gas velocity downer reactors, vortex reactors, reactors having a relatively high density fluidized catalyst bed at a first or lower end and a relatively low density fluidized catalyst in a riser located at a second or upper end, multiple riser and / or downer reactors operated in parallel and / or sequentially and operating at the same or different conditions with respect to each other, or combinations thereof.

[0018] In some embodiments, the dehydrogenation catalyst particles may be pneumatically moved through the reaction system, for example, by a carrier or transport fluid, fed to a conversion zone, fed to a combustion zone, fed to an oxygen-soaked zone (if such step is required), transported through conduits connecting two or more locations, etc. Transport fluids may include, but are not limited to, a diluent, one or more reactants in gaseous form, i.e., one or more C2-C 16 Alkanes, at least one of C8-C 16The transport fluid may be or include an alkyl aromatic hydrocarbon, one or more dehydrogenated hydrocarbons, or a mixture thereof. Suitable transport fluids may be or include, but are not limited to, molecular nitrogen, volatile hydrocarbons such as methane, ethane, and / or propane, argon, carbon monoxide, carbon dioxide, water vapor, and the like. The amount of transport fluid may be sufficient to keep the dehydrogenation catalyst particles in a fluidized state and transport the dehydrogenation catalyst particles from one location, e.g., a combustion zone, to a second location, e.g., a conversion zone. In some embodiments, the mass ratio of the dehydrogenation catalyst particles to the transport fluid may range from 5, 10, 15, or 20 to 50, 60, 80, 90, or 100. Suitable injection points for the transport fluid may be set at multiple points along any one or more transfer lines connecting any two zones, such as a combustion zone and a conversion zone, or other locations.

[0019] The hydrocarbon-containing feed and the dehydrogenation catalyst particles may be contacted at a temperature ranging from 300°C, 350°C, 400°C, 450°C, 500°C, 550°C, 600°C, 620°C, 630°C, 640°C, 650°C, 660°C, 670°C, 680°C, 690°C, or 700°C to 725°C, 750°C, 760°C, 780°C, 800°C, 825°C, 850°C, 875°C, or 900°C. In some embodiments, the hydrocarbon-containing feed and the dehydrogenation catalyst particles may be contacted at a temperature of at least 620°C, at least 630°C, at least 640°C, at least 650°C, at least 660°C, at least 670°C, at least 680°C, at least 690°C, or at least 700°C up to 725°C, 750°C, 760°C, 780°C, 800°C, 825°C, 850°C, 875°C, or 900°C. In some embodiments, the hydrocarbon-containing feed may be introduced into the conversion zone and contacted therein with the dehydrogenation catalyst particles for a duration or time of ≦5 hours, ≦4 hours, ≦3 hours, ≦1 hour, ≦0.5 hours, ≦0.1 hours, ≦3 minutes, ≦1 minute, ≦30 seconds, or ≦0.1 seconds. In other embodiments, the hydrocarbon-containing feed may be introduced into the conversion zone and contacted therein with the dehydrogenation catalyst particles for a time ranging from 0.1 seconds, 1 second, 1.5 seconds, 2 seconds, or 2.5 seconds to 3 seconds, 5 seconds, 10 seconds, 20 seconds, 30 seconds, 45 seconds, 1 minute, 1.5 minutes, 2 minutes, 2.5 minutes, or 3 minutes. In some embodiments, the average residence time of the dehydrogenation catalyst particles in the conversion zone may be < 7 min, < 6 min, < 5 min, < 4 min, < 3 min, < 2 min, < 1.5 min, < 1 min, < 45 sec, < 30 sec, < 20 sec, < 15 sec, < 10 sec, < 7 sec, < 5 sec, < 3 sec, < 2 sec, or < 1 sec. In some embodiments, the average residence time of the dehydrogenation catalyst particles in the conversion zone may be longer than the average residence time of the gaseous components in the conversion zone, such as the hydrocarbon-containing feed and the converted effluent resulting therefrom.

[0020] The hydrocarbon-containing feed and the dehydrogenation catalyst particles may be contacted under a hydrocarbon partial pressure of at least 20 kPa absolute. This hydrocarbon partial pressure is at least 20 kPa absolute. 16 Alkanes and any C8-C 16 The total partial pressure of alkyl aromatic hydrocarbons. In some embodiments, the hydrocarbon partial pressure during contact of the hydrocarbon-containing feed with the dehydrogenation catalyst particles can range from 20 kPa absolute, 50 kPa absolute, 100 kPa absolute, 150 kPa, 200 kPa, 300 kPa absolute, 500 kPa absolute, 750 kPa absolute, or 1,000 kPa absolute to 1,500 kPa absolute, 2,500 kPa absolute, 4,000 kPa absolute, 5,000 kPa absolute, 7,000 kPa absolute, 8,500 kPa absolute, or 10,000 kPa absolute. This hydrocarbon partial pressure is determined by the total partial pressure of any C2-C4 alkyl aromatic hydrocarbons in the hydrocarbon-containing feed. 16 Alkanes and any C8-C 16 is the total partial pressure of alkyl aromatic hydrocarbons. In some embodiments, the hydrocarbon-containing feed is at least 60 vol.%, at least 65 vol.%, at least 70 vol.%, at least 75 vol.%, at least 80 vol.%, at least 85 vol.%, at least 90 vol.%, at least 95 vol.%, or at least 99 vol.% of a single C2-C 16 In some embodiments, the hydrocarbon-containing feed and the dehydrogenation catalyst particles may comprise a single C2-C alkane having a pressure of at least 20 kPa absolute, at least 50 kPa absolute, at least 70 kPa absolute, at least 100 kPa absolute, at least 150 kPa absolute, or at least 250 kPa absolute, up to 300 kPa absolute, 400 kPa absolute, 500 kPa absolute, or 1,000 kPa absolute. 16 The contact may be under pressure of an alkane, such as propane.

[0021] The hydrocarbon-containing feed may be contacted with the dehydrogenation catalyst particles in the conversion zone at any mass hourly space velocity (WHSV) effective for carrying out the dehydrogenation process. In some embodiments, the WHSV is less than 0.1 hour -1 , 0.2 hours -1 , 0.4 hours -1 , 0.8 hours -1 , 2 hours -1 , 4 hours -1 , or 8 hours -1 16 hours from -1 , 32 hours -1 , 64 hours -1 , 100 hours -1 , 250 hours -1 , 500 hours -1 , 750 hours -1 or 1,000 hours -1 In some embodiments, the dehydrogenation catalyst particles and any C2-C 16 Alkanes and any C8-C 16 The ratio of the total amount of alkyl aromatic hydrocarbons can range from 1, 3, 5, 10, 15, 20, 25, 30, or 40 to 50, 60, 70, 80, 90, 100, 110, 125, or 150 on a mass to mass basis. In some embodiments, at least a portion of the fluidized dehydrogenation catalyst particles in the conversion zone are removed and fed to a heat input device where the dehydrogenation catalyst particles can be heated, and the heated catalyst particles can be fed back to the conversion zone. Because the reactions occurring in the conversion zone are endothermic, it may be beneficial to remove a portion of the fluidized dehydrogenation catalyst particles from the conversion zone after some contact with the hydrocarbon-containing feed to further increase the temperature. Heat may be transferred indirectly from any suitable heat transfer medium provided by an electric heater or any other suitable heater typically used to indirectly heat catalyst particles. In another embodiment, heat may be added directly into the conversion zone.

[0022] In some embodiments, the hydrocarbon-containing feed may optionally undergo one or more pretreatment processes prior to introduction into the conversion zone. In some embodiments, the hydrocarbon-containing feed may be preheated to a temperature of up to ≦620° C. and introduced into the conversion zone at or near the preheat temperature. In some embodiments, the hydrocarbon-containing feed may be purified by removing at least a portion of any sulfur compounds, at least a portion of any nitrogen compounds, at least a portion of any methane, at least a portion of any C2 hydrocarbons, at least a portion of any C 4+ The hydrocarbon-containing feed may be treated to remove at least a portion of the hydrocarbons, or any combination thereof, to produce a pre-treated hydrocarbon-containing feed, which may be introduced into the conversion zone. In other embodiments, the hydrocarbon-containing feed may be treated by adding one or more additives thereto, such as one or more sulfur compounds, to produce a pre-treated hydrocarbon-containing feed, which may be introduced into the conversion zone.

[0023] The first particulate stream, rich in coked catalyst particles and depleted in one or more dehydrogenated hydrocarbons, and the first gaseous stream, rich in one or more dehydrogenated hydrocarbons, may be separated or otherwise obtained from the conversion effluent by any suitable device. In some embodiments, the first particulate stream and the first gaseous stream may be obtained from the conversion effluent by one or more solid-gas impingement separators, for example, one or more cyclone separators. In some embodiments, the cyclone separators may be or include a two-stage or "linked" arrangement, including both positive and negative pressure arrangements. In some embodiments, suitable cyclone separators may include those disclosed in U.S. Pat. Nos. 4,502,947; 4,985,136; and 5,248,411. In other embodiments, the first particulate stream and the first gaseous stream may be obtained from the conversion effluent via a "T" shaped conduit that allows the majority of the coked catalyst particles to flow by gravity in one direction and the gaseous components to flow in the other direction. In some embodiments, the first gaseous stream rich in one or more dehydrogenated hydrocarbons may also contain entrained coked catalyst particles. In such embodiments, the first particle stream rich in coked catalyst particles and poor in one or more dehydrogenated hydrocarbons may contain >95%, >96%, >97%, >98%, or >99%, >99.9%, >99.99% of the dehydrogenation catalyst particles in the conversion effluent. Thus, in some embodiments, the first gaseous stream rich in one or more dehydrogenated hydrocarbons may contain entrained coked catalyst particles in an amount of >0.001%, >0.005%, >0.01%, >0.05%, >0.1%, >0.5%, >1%, or >1.5% to 3%, 4%, or 5% of the dehydrogenation catalyst particles in the conversion effluent.

[0024] In some embodiments, at least a portion of the coked catalyst particles in the first particle stream may be contacted in the combustion zone with one or more oxidants and, optionally, one or more hydrocarbon fuels to cause combustion of at least a portion of the coke and, if present, the fuel to produce a combustion effluent that may include catalyst particles with reduced coke and combustion gases. In other embodiments, at least a portion of the coked catalyst particles in the first particle stream may be contacted in the combustion zone with one or more oxidants in the absence of supplemental fuel to cause combustion of at least a portion of the coke to produce a combustion effluent that may include catalyst particles with reduced coke and combustion gases. In some embodiments, when supplemental fuel is not introduced into the combustion zone, heat may be provided to the combustion zone using an electric heater or other heating device. When fuel is used, in some embodiments, the combustion zone may include a riser in which the average catalyst flow and the average gas flow may be simultaneously upward. In some embodiments, the combustion zone may include a lower section operating as a fast flowing, turbulent, or bubbling bed and an upper section operating as a riser in which the average catalyst flow and the average gas flow may be simultaneously upward. In some embodiments, the combustion zone may include a fast-flow, turbulent, or bubbling bed where the average catalyst flow may be downward and the average gas flow may be upward. This soaking zone may occur in a fast-flow, turbulent, or bubbling bed reactor where the average catalyst flow may be downward and the average gas flow may be upward. Separation of the coke-poor catalyst particles entrained in the upwardly moving combustion gas and separation of the conditioning catalyst particles entrained in the upwardly moving oxidizing gas may occur in the same set of separation devices. When no fuel is used, the combustion zone may also function as the oxygen soaking zone. In some embodiments, the mutual arrangement of the oxygen soaking zone and the combustion zone may be the same or similar to the arrangement and method of the oxygen soaking zone and the combustion zone arranged and described in U.S. Pat. Nos. 10,647,634 and 10,688,477, and WO 2020 / 263544.

[0025] The oxidant may be or include, but is not limited to, molecular oxygen, ozone, carbon dioxide, water vapor, or mixtures thereof. In some embodiments, an amount of oxidant in excess of the amount required to burn 100% of the coke on the coked catalyst particles may be used to increase the rate of coke removal from the catalyst particles, which may result in a decrease in the time required for coke removal, leading to an increase in the yield of upgraded products produced in a given time. The optional fuel may be or include, but is not limited to, molecular hydrogen, methane, ethane, propane, liquefied petroleum gas, or mixtures thereof. The optional fuel may be mixed with an inert gas, such as argon, neon, helium, molecular nitrogen, methane, or mixtures thereof.

[0026] The coked catalyst particles and the oxidant and, if present, the fuel may be contacted with each other at a temperature ranging from 500° C., 550° C., 600° C., 650° C., 700° C., 750° C., or 800° C. to 900° C., 950° C., 1,000° C., 1,050° C., or 1,100° C. In some embodiments, the coked catalyst particles and the oxidant and, if present, the fuel may be contacted with each other at a temperature ranging from 500° C.-1,100° C., 600° C.-1,100° C., 600° C.-1,000° C., 650° C.-950° C., 700° C.-900° C., or 750° C.-850° C. to generate the combustion effluent. The coked catalyst particles and the oxidant and, if present, the fuel may be contacted with each other under oxidant partial pressures ranging from 20 kPa absolute, 50 kPa absolute, 70 kPa absolute, 100 kPa absolute, 150 kPa absolute, or 200 kPa absolute to 300 kPa absolute, 500 kPa absolute, 750 kPa absolute, or 1,000 kPa absolute to produce a combustion effluent. The coked catalyst particles and the oxidant and, if present, the fuel may be contacted with each other for a time ranging from 0.1 seconds, 0.5 seconds, 1 second, 3 seconds, 5 seconds, 10 seconds, 15 seconds, 30 seconds, 1 minute, 2 minutes, or 5 minutes to 10 minutes, 20 minutes, 30 minutes, 40 minutes, 50 minutes, or 60 minutes. For example, the coked catalyst particles and the oxidant and, if present, the fuel may be contacted with each other for a time ranging from 0.5 seconds to 50 minutes, 55 minutes, or 60 minutes. In some embodiments, the coked catalyst particles and the oxidant and, if present, the fuel may be contacted with each other for a time sufficient to remove ≧50 wt%, ≧75 wt%, or ≧90 wt%, or >99% of any coke disposed on the catalyst particles.

[0027] In some embodiments, the time that the coked catalyst particles and the oxidant and, if present, fuel are in contact with each other may be longer than the time that the catalyst particles are in contact with the hydrocarbon-containing feed to produce the converted effluent. For example, the time that the coked catalyst particles and the oxidant and, if present, the fuel are in contact with each other can be at least 50%, at least 100%, at least 300%, at least 500%, at least 1,000%, at least 10,000%, at least 30,000%, at least 50,000%, at least 75,000%, at least 100,000%, at least 250,000%, at least 500,000%, at least 750,000%, at least 1,000,000%, at least 1,250,000%, at least 1,500,000%, at least 1,800,000%, at least 2,500,000%, at least 3,500,000%, or 4,140,000% longer than the time that the catalyst particles are in contact with the hydrocarbon-containing feed to produce the converted effluent. Without wishing to be bound by theory, it is believed that at least a portion of the metal elements, e.g., Group 8-10 elements, e.g., Pt, located on the support in the coked catalyst particles may be agglomerated relative to the catalyst particles prior to contact with the hydrocarbon-containing feed. It is believed that during combustion of at least a portion of the coke on the coked catalyst particles, at least a portion of the metal elements, e.g., Group 8-10 elements, may be redispersed around the support. Redispersing at least a portion of any agglomerated metal elements, e.g., Group 8-10 elements, may increase the dehydrogenation activity and improve selectivity of the catalyst particles over multiple cycles.

[0028] In some embodiments, at least a portion of the low coke catalyst particles in the second particle stream may be contacted with an oxidizing gas in the oxygen soaking zone to produce conditioned catalyst particles. Preferably, the low coke catalyst particles in the second particle stream may be contacted with an oxidizing gas in the oxygen soaking zone when fuel is introduced into the combustion zone. When fuel is not introduced into the combustion zone and heat is provided to the combustion zone using an electrical or other heating device, the low coke catalyst particles in the second particle stream may be sent directly to the reduction zone, which is described in more detail below, and thus do not need to be contacted with an oxidizing gas. However, it should be understood that when fuel is not introduced into the combustion zone, the low coke catalyst particles in the second particle stream may also be contacted with an oxidizing gas in the oxygen soaking zone, if desired. It should also be understood that when fuel is not introduced into the combustion zone, the combustion zone and the oxygen soaking zone may be combined into a single zone for both coke burning and oxygen soaking, and a single oxidizing gas may be used for both coke burning and oxygen soaking. In this embodiment, the terms "low coke catalyst particles" and "conditioned catalyst particles" refer to the same stream of catalyst particles.

[0029] In some embodiments, the low coke catalyst particles in the second particle stream may be contacted with an oxidizing gas at an oxidation temperature ranging from 620° C., 650° C., 675° C., 700° C., or 750° C. to 800° C., 850° C., 900° C., 950° C., or 1,000° C. to produce conditioned catalyst particles. In some embodiments, the low coke catalyst particles in the second particle stream may be contacted with an oxidizing gas for a duration or time ranging from 20 seconds, 30 seconds, 1 minute, 2 minutes, 3 minutes, or 5 minutes to 10 minutes, 15 minutes, 20 minutes, 25 minutes, 30 minutes, 40 minutes, 50 minutes, or 60 minutes to produce conditioned catalyst particles. The conditioned catalyst particles may have a dehydrogenation activity lower than the dehydrogenation activity of the coked catalyst particles. In some embodiments, the oxidative gas introduced into the oxygen soak zone may contain ≦5 mol%, ≦3 mol%, ≦1 mol%, ≦0.5 mol%, or ≦0.1 mol% HO. Contacting the oxidative gas with the low-coke catalyst particles in the second particle stream is sometimes referred to as "dry air soaking." It should be understood that the oxidative gas and any other gaseous components in the oxygen soak zone contain ≦5 mol%, ≦3 mol%, ≦1 mol%, ≦0.5 mol%, or ≦0.1 mol% HO. It has surprisingly and unexpectedly been found that contacting low coke catalyst particles produced in the presence of an optional fuel with an oxidizing gas containing 5 mole % or less HO can significantly improve the activity and / or selectivity of the regenerated catalyst produced via contact with a reducing gas, as described in more detail below. Without wishing to be bound by theory, it is believed that HO present in the oxidizing gas or produced as a combustion product can significantly reduce the effectiveness of redispersion of the Group 8-10 elements, e.g., Pt, and thus the effectiveness of the regenerated catalyst.

[0030] In some embodiments, at least a portion of the low-coke catalyst particles in the second particle stream when fuel is not introduced into the combustion zone, or at least a portion of the conditioned catalyst particles when fuel is introduced into the combustion zone, may be contacted with a reducing gas in the reduction zone to produce regenerated catalyst particles. Suitable reducing gases (reductants) may be or include, but are not limited to, molecular hydrogen, carbon monoxide, methane, ethane, ethylene, propane, propylene, steam, or mixtures thereof. In some embodiments, the reducing gas may be mixed with an inert gas, such as argon, neon, helium, molecular nitrogen, or mixtures thereof. In such embodiments, at least a portion of the metal elements, e.g., Group 8-10 elements, in the regenerated catalyst particles may be reduced to a lower oxidation state, e.g., elemental state, compared to the metal elements, e.g., Group 8-10 elements, in the low-coke catalyst particles in the second particle stream (when fuel is not introduced into the combustion zone) and compared to the metal elements in the conditioned catalyst particles. In some embodiments, the low coke catalyst particles or conditioned catalyst particles in the second particle stream and the reducing gas may be contacted at a temperature ranging from 400° C., 450° C., 500° C., 550° C., 600° C., 620° C., 650° C., or 670° C. to 720° C., 750° C., 800° C., or 900° C. The low coke catalyst particles or conditioned catalyst particles in the second particle stream and the reducing gas may be contacted for a duration or time ranging from 0.1 seconds, 1 second, 2 seconds, 5 seconds, 10 seconds, 20 seconds, 30 seconds, 60 seconds, or 75 seconds to 100 seconds, 200 seconds, 300 seconds, 600 seconds, or 1,000 seconds, or 1,800 seconds. The coke-lean or conditioned catalyst particles in the second particle stream and the reducing gas may be contacted at a reducing gas partial pressure ranging from 20 kPa absolute, 50 kPa absolute, 70 kPa absolute, 100 kPa absolute, 150 kPa absolute, or 200 kPa absolute to 300 kPa absolute, 500 kPa absolute, 750 kPa absolute, or 1,000 kPa absolute.

[0031] In some embodiments, a first portion of the coked catalyst particles in the first particle stream rich in coked catalyst particles may be fed to a combustion zone for combustion of the coke disposed thereon, and a second portion of the coked catalyst particles in the first particle stream may be fed back to the conversion zone as is. In some embodiments, a first portion of the coked catalyst particles in the first particle stream rich in coked catalyst particles may be fed to a combustion zone for combustion of the coke disposed thereon, and a second portion of the coked catalyst particles may be fed to a reduction zone. In other embodiments, a first portion of the coked catalyst particles in the first particle stream rich in coked catalyst particles may be fed to a combustion zone for combustion of the coke disposed thereon, a second portion of the coked catalyst particles may be fed back to the conversion zone as is, and a third portion of the coked catalyst particles may be fed to the reduction zone. In other embodiments, a first portion of the coked catalyst particles in the first particle stream rich in coked catalyst particles may be fed to a combustion zone for combustion of the coke disposed thereon, a second portion of the coked catalyst particles may be recycled directly back to the conversion zone, a third portion of the coked catalyst particles may be fed to an oxygen soak zone, and a fourth portion of the coked catalyst particles may be fed to a reduction zone. In any of these embodiments, a portion of the coked catalyst particles, a portion of the catalyst particles in the second particle stream, a portion of the conditioned catalyst particles, and / or a portion of the regenerated catalyst particles may be removed from the process, and new or make-up catalyst particles may be introduced into the process, either continuously or intermittently. Removal of catalyst particles may occur as the catalyst particles break down into smaller pieces, become deactivated, and / or begin to convert the hydrocarbon-containing feed at undesirable conversion rates. In some embodiments, at least a portion of any removed catalyst particles may be transported to a metals reclamation facility where metals may be recovered.

[0032] At least a portion of the coked catalyst particles, at least a portion of the low coke catalyst particles in the second particle stream, at least a portion of the conditioned catalyst particles, at least a portion of the regenerated catalyst particles, fresh or make-up catalyst particles, or any mixture thereof, may be contacted with an additional amount of hydrocarbon-containing feed in the conversion zone to produce additional converted effluent and recoked catalyst particles. In some embodiments, the cycle time from contacting the hydrocarbon-containing feed with the catalyst particles to contacting the additional amount of hydrocarbon-containing feed with at least a portion of the regenerated particles may be ≦5 hours, ≦4 hours, ≦3 hours, ≦2 hours, ≦70 minutes, ≦60 minutes, ≦45 minutes, or ≦30 minutes, for example, from 1 minute to 70 minutes or from 5 minutes to 45 minutes. In some embodiments, one or more additional feeds, such as one or more stripping fluids, may be utilized to remove at least a portion of any entrained gaseous components from the catalyst particles. In some embodiments, the coked catalyst particles may be contacted with a stripping fluid prior to contact with the oxidant to remove at least a portion of any upgraded entrained hydrocarbons and / or molecular hydrogen, and / or other gaseous components. Similarly, the low coke catalyst particles, conditioned catalyst particles, and / or regenerated catalyst particles in the second particle stream may be contacted with a stripping gas to remove at least a portion of any entrained combustion gases, oxidizing gases, or reducing gases from the catalyst particles. In some embodiments, the stripping gas may be inert under the dehydrogenation, combustion, and / or reduction conditions. Suitable stripping fluids may be or include, but are not limited to, molecular nitrogen, helium, argon, carbon dioxide, steam, methane, or mixtures thereof. The stripping gas may be at a flow rate of about 0.1 m per cubic meter of catalyst particles. 3 ~10m 3 may be contacted with the coked catalyst particles, the regenerated catalyst particles, and / or the regenerated reduced catalyst particles at a volumetric ratio of the stripping gas.

[0033] As discussed above, the first cycle begins when the catalyst particles are contacted with a hydrocarbon-containing feed, and then contacted with at least an oxidant and a reducing gas to produce regenerated catalyst particles, and the first cycle ends when the regenerated catalyst particles are contacted with an additional amount of hydrocarbon-containing feed. For example, if some sweep fluid is utilized to strip residual hydrocarbons from the coked catalyst particles, the time during which the sweep fluid is utilized will be included in the cycle time. In one embodiment, a riser structure may be provided in which the hydrocarbon-containing feed may be mixed with a dilution gas in the riser and contacted with heated fluidized catalyst particles. The dilution gas may be or include, but is not limited to, molecular nitrogen, methane, steam, molecular hydrogen, or a mixture thereof. The mixed gas may convectively move or otherwise carry the fluidized catalyst particles through the riser while contacting and reacting as the mixture flows through the riser to produce a conversion effluent including one or more dehydrogenated hydrocarbons and coked catalyst particles. The residence time of the hydrocarbon-containing feed and the fluidized catalyst particles may be sufficient to achieve a desired conversion rate of the hydrocarbon-containing feed to one or more dehydrogenated hydrocarbons. The specific design of the riser, including fabrication and dimensions, may depend at least in part on the intended chemistry, but may typically require a velocity of more than 4.5 m / s under average gas composition. Suitable systems for carrying out the dehydrogenation of hydrocarbon-containing feeds include systems known in the art, such as flow reactors disclosed in U.S. Pat. Nos. 3,888,762; 7,102,050; 7,195,741; 7,122,160; and 8,653,317; U.S. Patent Application Publication Nos. 2004 / 0082824; 2008 / 0194891; and International Publication Nos. WO2001 / 85872; WO2004 / 029178; and WO2005 / 077867.

[0034] The first gas stream may be cooled to produce a cooled gas stream. In some embodiments, the first gas stream may be cooled via indirect heat exchange, by transferring heat from the first gas stream to a heat transfer medium in one or more heat exchangers, by direct contact with a quench medium, or by a combination thereof. In some embodiments, the first gas stream may be cooled exclusively by indirect heat exchange to produce a cooled gas stream. In other embodiments, the first gas stream may be cooled exclusively by direct contact with a quench medium. In other embodiments, the first gas stream may be cooled by indirect heat exchange or by direct contact with a quench medium in any order or sequence. In some embodiments, the first gaseous stream may be indirectly cooled by indirectly transferring heat to any suitable heat transfer medium. Suitable heat transfer media may be or include, but are not limited to, a hydrocarbon-containing feed to generate a preheated hydrocarbon-containing feed that may be introduced into the conversion zone, water, steam, other hydrocarbon streams, or any combination thereof. Any suitable heat exchanger may be used for indirect heat transfer from the first gaseous stream to the heat transfer medium.

[0035] In some embodiments, the first gaseous stream may be contacted with a first quench medium to generate a cooled gaseous stream. For example, when the separator or gas-solid separator is a cyclone, the first gaseous stream may be contacted with the first quench medium in the plenum of the cyclone. When multiple cyclones are used in series, the first gaseous stream may be contacted with the first quench medium anywhere between or after the multiple cyclones. In other embodiments, the first gaseous stream may be contacted in a transfer line in fluid communication with the outlet of the separator or gas-solid separator and the quench tower. In some embodiments, the first quench medium may be in the gas phase, the liquid phase, or a mixture of gas and liquid phases when contacted with the first gas stream, hi some embodiments, the first quench medium may be in the liquid phase when contacted with the first gas stream and may be entirely in the gas phase after contacting the first gas stream. In some embodiments, the first gaseous stream may be at a temperature of ≧600° C., ≧620° C., ≧630° C., ≧640° C., ≧650° C., ≧660° C., ≧670° C., ≧680° C., or ≧700° C. when initially contacted with the first quench medium and / or introduced into the heat exchanger for indirect transfer of heat to the heat transfer medium. In some embodiments, the cooling gaseous stream may be at a temperature that is at least 10° C., at least 20° C., at least 30° C., at least 60° C., 80° C., or at least 100° C. lower than the temperature of the first gaseous stream prior to contact with the first quench medium or introduction into the heat exchanger. In some embodiments, the cooling gaseous stream may be at a temperature in the range of 500° C., 515° C., 530° C., 550° C., or 560° C. to 575° C., 590° C., 600° C., 610° C., or 620° C. In some embodiments, the cooling gas stream may be at a temperature of ≧500°C or ≧550°C to <620°C.

[0036] In some embodiments, the cooling gas stream may be contacted with the second quench medium in a contacting zone disposed within the quench tower. In some embodiments, the second quench medium may be contacted countercurrently with the cooling gas stream within the quench tower. For example, the cooling gas stream may be introduced into the quench tower below the second quench medium and flow upward within the quench tower, and the second quench medium may flow downward within the quench tower. In some embodiments, the second quench medium may be introduced into the quench tower via one or more nozzles. As mentioned above, in some embodiments, the first gas stream may contain entrained coked catalyst particles therein. In such embodiments, a third gas stream containing one or more dehydrogenated hydrocarbons and substantially or completely free of entrained coked catalyst particles may be recovered as overhead from the quench tower, and a slurry stream that may contain at least a portion of the second quench medium and entrained coked catalyst particles may be recovered as bottoms from the quench tower. In some embodiments, the entrained coked catalyst particles may be entrained in the second quench medium if the second quench medium remains liquid, since the entrained coked catalyst particles may interact more strongly with liquids. In some embodiments, the third gas stream that is substantially free of entrained coked catalyst particles may contain some entrained coked catalyst particles, <10 wt%, <5 wt%, <3 wt%, <1 wt%, <0.5 wt%, <0.1 wt%, <0.01 wt%, or <0.001 wt%. In some embodiments, the gas stream may be at a temperature ranging from 50°C, 100°C, or 150°C to 200°C, 250°C, or 300°C.

[0037] If the first gaseous stream is directly contacted with the first quench medium, a condensed first quench medium stream may be withdrawn from the quench tower as a side draw, and at least a portion of the condensed first quench medium may be recycled to contact an additional amount of the first gaseous stream. In some embodiments, the condensed first quench medium withdrawn from the quench tower may be at a temperature ranging from 50°C, 60°C, or 70°C to 80°C, 100°C, or 120°C. When the first gas stream includes entrained catalyst particles, a slurry stream, which may include at least a portion of the second quenching medium and entrained coked catalyst particles, may be withdrawn as a bottoms stream from the quench tower. In some embodiments, the bottoms zone within the quench tower may contain an inventory of the slurry stream, and as a result, the slurry stream withdrawn from the quench tower may be drawn from this inventory. The slurry stream may be at a temperature ranging from 150° C., 200° C., or 250° C. to 300° C., 400° C., or 500° C. when withdrawn from the quench tower.

[0038] In some embodiments, the quench tower may include one or more internals that may facilitate separation of the cooling gas stream into the third gas stream, the first quench medium stream (if used), and the slurry stream. Exemplary internals include, but are not limited to, trays, grids, packing, or any combination thereof. Exemplary trays include, but are not limited to, fixed valve trays, jet tub trays, sieve trays, dual flow trays, baffle trays, square iron trays, draw off trays, shed deck trays, disc trays, donut trays, side by side-splash trays, or any combination thereof. Suitable fixed valve trays, sieve trays, dual flow trays, and grids include those disclosed in Distillation Design, Henry Z. Kister, McGraw-Hill Inc., 1992, pages 262-265 and 464-466. Suitable jet tub trays include those disclosed in International Publication No. WO2011 / 014345. In some embodiments, if the process conditions in the quench tower are such that the entrained coked catalyst particles may remain in the third gas stream withdrawn as overhead from the quench tower, the third gas stream may undergo further processing. In some embodiments, if the third gas stream withdrawn as overhead from the quench tower contains any entrained coked catalyst particles, the third gas stream may be further separated by one or more electrostatic precipitators, one or more filters, one or more screens, one or more membranes, wet gas scrubbers, contact with an absorbent scavengers, one or more additional quench towers, one or more electrocyclones, one or more hydrocyclones, one or more centrifuges, one or more plates or cones, or any combination thereof to remove at least a portion of the entrained coked catalyst particles from the gas stream.

[0039] In some embodiments, if the hydrocarbon-containing feed contains water and / or water is produced during the dehydrogenation reaction such that the resulting conversion effluent contains water, a water stream may be recovered from the quench tower as a second side draw from the quench tower. In such embodiments, the water stream may be removed from the process and a portion of the water stream may be recycled to the upper section of the quench tower to further facilitate separation of the entrained coked catalyst fines, the first quench medium, and the second quench medium, or combinations thereof, from the cooling gas stream in the quench tower. In some embodiments, at least a portion of the water stream may be vaporized and recycled to the inlet of the conversion zone as a co-feed for the hydrocarbon-containing feed. The first quench medium and the second quench medium may independently be or include, without limitation, one or more aromatic hydrocarbons, water, or mixtures thereof. In some embodiments, the aromatic hydrocarbons may be or include benzene, one or more mono-substituted benzenes, one or more di-substituted benzenes, one or more multi-substituted benzenes, and / or one or more polycyclic aromatic hydrocarbons having a normal boiling point of <580° C. In some embodiments, the polycyclic aromatic hydrocarbons may have a normal boiling point of <580° C., <550° C., <500° C., <400° C., <300° C., <200° C., or <100° C. Suitable aromatic hydrocarbons may be or include, but are not limited to, benzene, toluene, cumene, ethylbenzene, xylene, methylethylbenzene, trimethylbenzene, methylnaphthalene, A-100 solvent mixture, A-150 solvent mixture, A-200 solvent mixture, A-250 solvent mixture, middle distillates, ultra low sulfur diesel, heavy gas oil, or any mixture thereof. In some embodiments, the second quench medium may have low surface tension, high thermal stability, and low toxicity. In some embodiments, the first quench medium may be or include, but is not limited to, benzene, and the second quench medium may be or include, but is not limited to, A-100 solvent mixture, A-150 solvent mixture, A-200 solvent mixture, A-250 solvent mixture, middle distillate, ultra-low sulfur diesel, heavy gas oil, or any mixture thereof.

[0040] In some embodiments, the composition of the first quench medium and the composition of the second quench medium may be the same or different. In some embodiments, the composition of the first quench medium and the second quench medium may include one or more components that are the same and one or more components that are different, resulting in some of the compositions of the first quench medium and the second quench medium being the same and some of the compositions of the first quench medium and the second quench medium being different. In some embodiments, the second quench medium may have a normal boiling point that is higher than the normal boiling point of the first quench medium. In some embodiments, the first quench medium may be or include benzene, and the second quench medium may include one or more polycyclic aromatic hydrocarbons. In some embodiments, the first quench medium and / or the second quench medium may not be used. In some embodiments, the mass ratio of the first quench medium to the first gas stream may range from 0.01, 0.05, or 0.08 to 0.1, 0.2, or 0.3. In some embodiments, the mass ratio of the second quench medium to the cooling gas stream may range from 0.01, 0.1, or 0.3 to 0.5, 1, 2, or 5. In some embodiments, the mass ratio of the first quench medium to the second quench medium may range from 0.002, 0.02, or 0.2 to 1, 5, or 10.

[0041] When the first gas stream includes entrained coked catalyst particles, at least a portion of the entrained coked catalyst particles may be separated from the slurry to provide a recovered second quenching medium and a recovered entrained coked catalyst particle stream that are low in or free of any entrained coked catalyst particles. In some embodiments, at least a portion of the recovered second quenching medium may be recycled to the quench tower and contacted therein with an additional amount of the first quenched gas stream. In some embodiments, the entrained coked catalyst particles may be separated from the slurry by one or more liquid-solid separation devices. Suitable liquid-solid separation devices may be or include, but are not limited to, one or more filters, one or more membranes, one or more screens, one or more centrifuges, one or more settling tanks, or any combination thereof. In some embodiments, two or more liquid-solid separation devices may be used in parallel. As a result, at least one first liquid-solid separation device may be operated in a filtration mode while at least one second liquid-solid separation device may be operated in a backwash mode to remove the collected coked catalyst particles from the separation device. The filtration mode and the backwash mode may be alternated periodically. In some embodiments, when two or more filters are used to separate the entrained coked catalyst particles from the slurry, the backwash mode may include at least one compressed gas pulse through at least one filter in a countercurrent direction backwash mode to remove the separated coked catalyst particles from the filter. In some embodiments, combustion gas or flue gas recovered from the combustion zone may be used as a gas to backwash the filter. In some embodiments, a liquid stream may be used to backwash the filter. In some embodiments, suitable processes for recovering entrained coked catalyst particles from the slurry include the process disclosed in US Pat. No. 7,375,143.

[0042] In some embodiments, at least a portion of the cooled first gaseous stream, e.g., the third gaseous stream, which may be recovered from a quench tower, may be compressed to produce a compressed gaseous stream. At least a portion of the cooled first gaseous steam may be compressed in one or more compressors or compression stages to produce a compressed gaseous stream. A plurality of products may be separated from the compressed gaseous stream. The compressed gaseous stream may be introduced into a product recovery zone or unit from which a plurality of products may be separated. The product recovery unit may be or include, but is not limited to, any one or more of the following: a distillation column, a membrane separation, an adsorption bed, and a cryogenic separation. In some embodiments, the compressed gas stream may be separated into a light gas stream, an unreacted hydrocarbon-containing feed stream, a dehydrogenated hydrocarbon stream, and a liquid stream in the product recovery zone. In some embodiments, the light gas stream may include hydrogen, methane, butane, or any mixture thereof. In some embodiments, at least a portion of the light hydrocarbon stream may be introduced into the combustion zone as an optional fuel. The unreacted hydrocarbon-containing feed, e.g., ethane, propane, may be recycled to the conversion zone. The dehydrogenated hydrocarbon stream may be further processed to produce one or more products, e.g., polyethylene, polypropylene, or other polymers. The liquid stream or at least a portion thereof may be used as a first quench medium, a second quench medium, or a combination thereof. In some embodiments, the recovered olefin, e.g., propylene, may be used for polymer production. For example, the recovered olefin may be polymerized to produce a polymer having segments or units derived from the recovered propylene, e.g., polypropylene, ethylene-propylene copolymers, etc. The recovered isobutene can be used, for example, to produce one or more of oxygenates, such as methyl tert-butyl ether, fuel additives, such as diisobutene, synthetic elastomeric polymers, such as butyl rubber, etc. In some embodiments, the recovered olefins, such as propylene, isobutene, may be sent to an alkylation unit.

[0043] In some embodiments, the process recovery unit may also receive a fourth gaseous stream that may be recovered as an overhead product from a primary fractionator that receives and separates various products from the stream cracker effluent generated in the steam cracker. For example, the primary fractionator may separate the steam cracker effluent into a tar product, a steam cracker quench oil product, a steam cracker gas oil product, a steam cracker naphtha product, and a steam cracker gaseous overhead product that may include hydrogen, methane, ethane, ethylene, propane, propylene, butenes, butanes, pentanes, and other gaseous products. In some embodiments, the fourth gas stream may already be compressed, hi other embodiments, the fourth gas stream is combined with the third gas stream and this combined gas stream is compressed to produce a combined third and fourth compressed gas stream, which may be introduced into the product recovery zone.

[0044] In some embodiments, at least a portion of the coked catalyst particles in the recovered entrained coked catalyst particle stream may be transported to a reclamation facility. In such embodiments, at least a portion of the metallic element, e.g., Group 8-10 element(s), may be recovered from the coked catalyst particles in the recovered entrained catalyst particle stream. In some embodiments, at least a portion of the coked catalyst particles transported to the reclamation facility may be recovered in the form of a sludge or cake. In some embodiments, the liquid in the sludge or cake may include a portion of the second quenching medium. In other embodiments, the entrained coked catalyst particles may be substantially separated from the second quenching medium and transported in the form of fluidized particles. In yet other embodiments, the entrained coked catalyst particles may be substantially separated from the second quenching medium and mixed with another liquid medium to form another slurry, sludge, or cake, which may be transported to a reclamation facility. The recovered Group 8-10 element(s) may be recycled to make new catalyst particles, purified, sold, for example, commercially, or used for any other desired purpose.

[0045] In some embodiments, the electricity used in the combustion zone may be from a renewable source, such as solar, wind, geothermal, hydroelectric, etc. In some embodiments, pure O2 may be used in the combustion zone so that the capture and sequestration of CO2 produced during combustion may be facilitated. In some embodiments, the feed may be liquefied petroleum gas, including both C3 and C4 paraffin molecules. In some embodiments, the feed may be one or more components in natural gas liquids, commonly known as NGLs. In some embodiments, the feed may be derived from a renewable source, such as biomass fermentation or transformation. In some embodiments, at least a portion of the Group 8-10 element(s) may be recovered from the coked catalyst particles by any suitable process or combination of processes. Suitable processes for recovering at least a portion of the Group 8-10 element(s) include, but are not limited to, those described in U.S. Pat. No. 7,033,480; U.S. Patent Application Publication No. 2004 / 0219082; British Patent Application Publication No. GB829972A; Chinese Patent No. CN101760627; and / or Chinese Patent Publication No. CN104831071A.

[0046] dehydrogenation catalyst particles The dehydrogenation catalyst particles were concentrated to 0.001wt%, 0.002wt%, 0.003wt%, 0.004wt%, 0.005wt%, 0.006wt%, 0.007wt%, 0.008wt%, 0.009wt%, 0.01wt%, 0.015wt%, 0.02wt%, 0.025wt%, 0.03w%, 0.035wt%, 0.04wt%, 0.045wt%, 0.05w%, 0.055wt%, and 0.06wt%, based on the weight of the support. The support may comprise from 0.06 wt%, 0.065 wt%, 0.07 wt%, 0.08 wt%, 0.085 wt%, 0.09 wt%, 0.095 wt%, 0.1 wt%, 0.2 wt%, 0.3 wt%, 0.4 wt%, 0.5 wt%, 0.6 wt%, 0.7 wt%, 0.8 wt%, 0.9 wt%, or 1 wt% to 2 wt%, 3 wt%, 4 wt%, 5 wt%, or 6 wt% of a Group 8-10 element, such as Pt, disposed on the support. In some embodiments, the catalyst particles have a molecular weight of < 5.5 wt%, < 4.5 wt%, < 3.5 wt%, < 2.5 wt%, < 1.5 wt%, < 1 wt%, < 0.9 wt%, < 0.8 wt%, < 0.7 wt%, < 0.6 wt%, < 0.5 wt%, < 0.4 wt%, < 0.3 wt%, < 0.2 wt%, < 0.15 wt%, < 0.1 wt%, < 0.09 wt%, < 0.08 wt%, based on the weight of the support. %, ≦0.07wt%, ≦0.06wt%, ≦0.05wt%, ≦0.04wt%, ≦0.03wt%, ≦0.02wt%, ≦0.01wt%, ≦0.009wt%, ≦0.008wt%, ≦0.007wt%, ≦0.006wt%, ≦0.005wt%, ≦0.004wt%, ≦0.003wt%, or ≦0.002wt% of a Group 8-10 element disposed on the support. In some embodiments, the catalyst particles may comprise >0.001, >0.003 wt%, >0.005 wt%, >0.007, >0.009 wt%, >0.01 wt%, >0.02 wt%, >0.04 wt%, >0.06 wt%, >0.08 wt%, >0.1 wt%, >0.13 wt%, >0.15 wt%, >0.17 wt%, >0.2 wt%, >0.2 wt%, >0.23, >0.25 wt%, >0.27 wt%, or >0.3 wt% and <0.5 wt%, <1 wt%, <2 wt%, <3 wt%, <4 wt%, <5 wt%, or <6 wt% of a Group 8-10 element disposed on the support, based on the weight of the support.In some embodiments, the Group 8-10 element can be or include, but is not limited to, Fe, Co, Ni, Ru, Pd, Os, Ir, Pt, combinations or mixtures thereof, and in at least one embodiment, the Group 8-10 element can be or include Pt.

[0047] In some embodiments, the catalyst particles may optionally include two or more Group 8-10 elements, such as Pt and Ni and / or Pd. When two or more Group 8-10 elements are disposed on a support, the catalyst particles may include 0.001 wt%, 0.002 wt%, 0.003 wt%, 0.004 wt%, 0.005 wt%, 0.006 wt%, 0.007 wt%, 0.008 wt%, 0.009 wt%, 0.01 wt%, 0.015 wt%, 0.02 wt%, 0.025 wt%, 0.03 wt%, 0.035 wt%, 0.04 wt%, 0.045 wt%, 0.0 ... %, 0.06 wt%, 0.065 wt%, 0.07 wt%, 0.075 wt%, 0.08 wt%, 0.085 wt%, 0.09 wt%, 0.095 wt%, 0.1 wt%, 0.2 wt%, 0.3 wt%, 0.4 wt%, 0.5 wt%, 0.6 wt%, 0.7 wt%, 0.8 wt%, 0.9 wt%, or 1 wt% to 2 wt%, 3 wt%, 4 wt%, 5 wt%, or 6 wt% of all Group 8-10 elements disposed on the support. In some embodiments, an active component of a catalyst particle capable of effecting dehydrogenation of a hydrocarbon feed may include a Group 8-10 element(s).

[0048] In some embodiments, the catalyst particle may optionally include a promoter disposed on the support in an amount up to 10 wt% based on the weight of the support. The promoter, if present, may be or include, but is not limited to, Sn, Ga, Zn, Ge, In, Re, Ag, Au, Cu, combinations or mixtures thereof. In at least one embodiment, the promoter may be or include Sn. In some embodiments, the promoter may be associated with a Group 8-10 element. For example, a promoter and Pt disposed on the support may form Pt-promoter clusters, which may be redispersed on the support. The promoter may improve the selectivity / activity / life of the catalyst particle for a given upgraded hydrocarbon. In some embodiments, the promoter may improve the propylene selectivity of the catalyst particle when the hydrocarbon-containing feed includes propane. The catalyst particles may include the promoter in an amount of from 0.01 wt%, 0.1 wt%, 0.2 wt%, 0.3 wt%, 0.4 wt%, 0.5 wt%, 0.6 wt%, 0.7 wt%, 0.8 wt%, 0.9 wt%, or 1 wt% to 3 wt%, 5 wt%, 7 wt%, or 10 wt%, based on the weight of the support.

[0049] In some embodiments, the catalyst particles may optionally include one or more alkali metal elements disposed on the support in an amount of up to 5 wt %, based on the weight of the support. The alkali metal elements, if present, may be or include, but are not limited to, Li, Na, K, Rb, Cs, combinations or mixtures thereof. In at least one embodiment, the alkali metal elements may be or include K and / or Cs. In at least some embodiments, the alkali metal elements may be or include K and / or Cs. In some embodiments, the alkali metal elements, if present, may improve the selectivity of the catalyst particles for a given upgraded hydrocarbon. The catalyst particles may contain elemental alkali metal in an amount of from 0.01 wt%, 0.1 wt%, 0.2 wt%, 0.3 wt%, 0.4 wt%, 0.5 wt%, 0.6 wt%, 0.7 wt%, 0.8 wt%, 0.9 wt%, or 1 wt% to 2 wt%, 3 wt%, 4 wt%, or 5 wt%, based on the weight of the support.

[0050] The carrier may be or include, but is not limited to, one or more group 2 elements, combinations thereof, or mixtures thereof. In some embodiments, the group 2 element may be present in its elemental form. In other embodiments, the group 2 element may be present in the form of a compound. For example, the group 2 element may be present as an oxide, phosphate, halide, halate, sulfate, sulfide, borate, nitride, carbide, aluminate, aluminosilicate, silicate, carbonate, metaphosphate, selenide, tungstate, molybdate, chromate, chromate, dichromate, or silicide. In some embodiments, a mixture of any two or more compounds containing a group 2 element may be present in different forms. For example, the first compound may be an oxide and the second compound may be an aluminate. In this case, the first compound and the second compound contain the same or different group 2 elements from each other. The carrier may be selected from the group consisting of ≧0.5wt%, ≧1wt%, ≧2wt%, ≧3wt%, ≧4wt%, ≧5wt%, ≧6wt%, ≧7wt%, ≧8wt%, ≧9wt%, ≧10wt%, ≧11wt%, ≧12wt%, ≧13wt%, ≧14wt%, ≧15wt%, ≧16wt%, ≧17wt%, ≧18wt%, ≧19wt%, ≧20wt%, ≧21wt%, ≧22wt%, ≧23wt%, ≧24wt%, ≧25wt%, ≧26wt%, ≧27wt%, ≧28wt%, ≧29wt%, ≧30wt%, ≧31wt%, ≧32wt%, ≧33wt%, ≧34wt%, ≧35wt%, ≧36wt%, ≧37wt%, ≧38wt%, ≧39wt%, ≧40wt%, ≧41wt%, ≧42wt%, ≧43wt%, ≧44wt%, ≧45wt%, ≧46wt%, ≧47wt%, ≧48wt%, ≧49wt%, ≧50wt%, ≧51wt%, ≧52wt%, ≧53wt%, ≧54wt%, ≧55wt%, ≧56wt%, ≧57wt%, ≧58wt%, ≧59wt%, ≧60wt%, ≧61wt%, ≧62wt%, ≧63wt%, ≧64wt%, ≧65wt%, ≧66wt%, ≧67wt%, ≧68wt%, ≧69wt%, ≧70wt%, ≧71wt%, ≧72w %, ≧22wt%, ≧23wt%, ≧24wt%, ≧25wt%, ≧26wt%, ≧27wt%, ≧28wt%, ≧29wt%, ≧30wt%, ≧35wt%, ≧40wt%, ≧45wt%, ≧50wt%, ≧55wt%, ≧60wt%, ≧65wt%, ≧70wt%, ≧75wt%, ≧80wt%, ≧85, or ≧90wt% of a Group 2 element. In some embodiments, the support may comprise a Group 2 element in the range of 0.5 wt%, 1 wt%, 2 wt%, 2.5 wt%, 3 wt%, 5 wt%, 7 wt%, 10 wt%, 11 wt%, 13 wt%, 15 wt%, 17 wt%, 19 wt%, 21 wt%, 23 wt%, or 25 wt% to 30 wt%, 35 wt%, 40 wt%, 45 wt%, 50 wt%, 55 wt%, 60 wt%, 65 wt%, 70 wt%, 75 wt%, 80 wt%, 85 wt%, 90 wt%, or 92.34 wt%, based on the weight of the support. In some embodiments, the molar ratio of Group 2 element to Group 8-10 element(s) present is 0.24, 0.5, 1, 10, 50, 100, 300, 450, 600, 800, 1,000, 1,200, 1,500, 1,700, or 2,000 to 3,000, 3,500, 4,000, 4,500, 5,000, 5,500, 6,000, 6,500, 7,000, 7,500, 8,000, 8,500, 9,000, 9,500, 10,000, 1 The molecular weight may be in the range of 5,000, 20,000, 25,000, 30,000, 35,000, 40,000, 45,000, 50,000, 55,000, 60,000, 65,000, 70,000, 75,000, 80,000, 85,000, 90,000, 95,000, 100,000, 200,000, 300,000, 400,000, 500,000, 600,000, 700,000, 800,000, or up to 900,000.

[0051] In some embodiments, the support may be in the form of a mixed group 2 element / Al metal oxide comprising group 2 element and Al, with O, Mg, and Al atoms intermingled on the atomic scale. In some embodiments, the support may be or include group 2 element and Al in the form of oxides or one or more oxides of group 2 element and Al2O3 possibly intermingled on the nm scale. In some embodiments, the support may be or include an oxide of group 2 element, e.g., MgO, and Al2O3 intermingled on the nm scale. In some embodiments, the support may be or include a first amount of Group 2 element in the form of a mixed Group 2 element / Al metal oxide and a second amount of Group 2 element in the form of Al and an oxide of the Group 2 element, in which the mixed Group 2 element / Al metal oxide and the oxide of the Group 2 element may be intermingled on the nm scale, and the Group 2 element and Al in the mixed Group 2 element / Al metal oxide may be intermingled on an atomic scale. In other embodiments, the support may be or include a first amount of Group 2 element and a first amount of Al in the form of a mixed Group 2 element / Al metal oxide, a second amount of Group 2 element in the form of an oxide of the Group 2 element, and a second amount of Al in the form of Al2O3, in which the mixed Group 2 element / Al metal oxide, the oxide of the Group 2 element, and Al2O3 may be intermixed on the nm scale, and the Group 2 element and Al in the mixed Group 2 element / Al metal oxide may be intermixed on an atomic scale.

[0052] In some embodiments, when the support comprises a Group 2 element and Al, the mass ratio of Group 2 element to Al in the support can be in the range from 0.001, 0.005, 0.01, 0.05, 0.1, 0.15, 0.2, 0.3, 0.5, 0.7, or 1 to 3, 6, 12.5, 25, 50, 75, 100, 200, 300, 400, 500, 600, 700, 800, 900, or 1,000. In some embodiments, when the support comprises Al, the support may comprise Al in a range from 0.5 wt%, 1 wt%, 1.5 wt%, 2 wt%, 2.1 wt%, 2.3 wt%, 2.5 wt%, 2.7 wt%, 3 wt%, 4 wt%, 5 wt%, 6 wt%, 7 wt%, 8 wt%, 9 wt%, 10 wt%, or 11 wt% to 15 wt%, 20 wt%, 25 wt%, 30 wt%, 40 wt%, 45 wt%, or 50 wt% based on the weight of the support. In some embodiments, the carrier may be or include, but is not limited to, one or more of the following compounds: Mg w AlO 3+w (w is a positive number);Ca x AlO 3+x (x is a positive number);Sr y AlO 3+y (y is a positive number);Ba z AlO 3+z (z is a positive number); BeO; MgO; CaO; BaO; SrO; BeCO3; MgCO3; CaCO3; SrCO3, BaCO3; CaZrO3; Ca7ZrAl6O 18 ;CaTiO3;Ca7Al6O 18 ;Ca7HfAl6O 18;BaCeO3;one or more magnesium chromates, one or more magnesium tungstates, one or more magnesium molybdates, combinations thereof, and mixtures thereof. In some embodiments, the Group 2 element includes Mg, and at least a portion of the Group 2 element may be in the form of MgO or in the form of a mixed oxide including MgO. In some embodiments, the support may be or include, but is not limited to, a MgO-Al2O3 mixed metal oxide. In some embodiments, when the support is a MgO-Al2O3 mixed metal oxide, the support may have a molar ratio of Mg to Al equal to 20, 10, 5, 2, 1 to 0.5, 0.1, or 0.01.

[0053] Mg w AlO 3+w (w is a positive number), when present as a support or a component of a support, may have a molar ratio of Mg to Al ranging from 0.5, 1, 2, 3, 4, or 5 to 6, 7, 8, 9, or 10. In some embodiments, Mg w AlO 3+w may include MgAl2O4, Mg2Al2O5, or a mixture thereof. x AlO 3+x (x is a positive number), when present as a support or a component of a support, may have a molar ratio of Ca to Al of 1:12, 1:4, 1:2, 2:3, 5:6, 1:1, 12:14, or 1.5:1. x AlO 3+x may include tricalcium aluminate, dodecalcium heptaaluminate, monocalcium aluminate, monocalcium dialuminate, monocalcium hexaaluminate, dicalcium aluminate, pentacalcium trialuminate, tetracalcium trialuminate, or any mixture thereof. y AlO 3+y (y is a positive number), when present as a support or as a component of a support, may have a molar ratio of Sr to Al ranging from 0.05, 0.3, or 0.6 to 0.9, 1.5, or 3. z AlO 3+z(z is a positive number) may have a molar ratio of Ba to Al ranging from 0.05, 0.3, or 0.6 to 0.9, 1.5, or 3 when present as a support or as a component of a support.

[0054] In some embodiments, the support may also include at least one metal element and / or at least one metalloid element and / or at least one mixture thereof selected from groups other than, but not limited to, Groups 2 and 10, where the at least one metal element and / or at least one metalloid element is not Li, Na, K, Rb, Cs, Sn, Cu, Au, Ag, or Ga. When the support also contains compounds containing metal and / or metalloid elements selected from groups other than Groups 2 and 10 (wherein the at least one metal and / or at least one metalloid element is not Li, Na, K, Rb, Cs, Sn, Cu, Au, Ag, or Ga), the compounds may be present in the support as oxides, phosphates, halides, halates, sulfates, sulfides, borates, nitrides, carbides, aluminates, aluminosilicates, silicates, carbonates, metaphosphates, selenides, tungstates, molybdates, chromates, chromates, dichromates, or silicides. In some embodiments, the at least one metallic element and / or at least one metalloid element selected from a group other than Group 2 and Group 10 and / or at least one compound thereof (wherein the at least one metallic element and / or at least one metalloid element is not Li, Na, K, Rb, Cs, Sn, Cu, Au, Ag, or Ga) may be or include, without limitation, one or more rare earth elements, i.e., elements having an atomic number of 21, 39, or 57-71.

[0055] When the support comprises at least one metal element and / or at least one metalloid element selected from a group other than Group 2 and Group 10 and / or at least one compound thereof (wherein the at least one metal element and / or at least one metalloid element is not Li, Na, K, Rb, Cs, Sn, Cu, Au, Ag, or Ga), the at least one metal element and / or at least one metalloid element selected from a group other than Group 2 and Group 10 may function as a binder in some embodiments and may be referred to as a "binder." For clarity and simplicity of the description, the at least one metal element and / or at least one metalloid element selected from groups other than Groups 2 and 10 will be further described herein as a "binder", regardless of whether it is at least one metal element and / or at least one metalloid element selected from groups other than Groups 2 and 10 and / or at least one compound thereof (wherein the at least one metal element and / or at least one metalloid element is not Li, Na, K, Rb, Cs, Sn, Cu, Au, Ag, or Ga). It is known that in the literature, the compounds referred to herein as "binders" are sometimes also referred to as fillers, matrices, additives, etc. In some embodiments, the support may comprise from 0.01 wt%, 0.05 wt%, 0.1 wt%, 0.5 wt%, 1 wt%, 5 wt%, 10 wt%, 15 wt%, 20 wt%, 25 wt%, 30 wt%, 35 wt%, or 40 wt% to 50 wt%, 60 wt%, 70 wt%, 80 wt%, or 90 wt% of a binder based on the weight of the support. In some embodiments, suitable compounds including binders include, but are not limited to, the following: B2O3, AlBO3, Al2O3, SiO2, ZrO2, TiO2, SiC, Si3N4, aluminosilicates, zinc aluminosilicate, ZnO, VO, V2O3, VO2, V2O5, Ga s O t , In u O v , Mn2O3, Mn3O4, MnO (where s, t, u, and v are positive numbers), one or more molybdenum oxides, one or more tungsten oxides, one or more zeolites, and mixtures and combinations thereof.

[0056] The catalyst particles may have a median particle size ranging from 1 μm, 5 μm, 10 μm, 20 μm, 40 μm, or 60 μm to 80 μm, 100 μm, 115 μm, 130 μm, 150 μm, 200 μm, 300 μm, or 400, or 500 μm. The catalyst particles may have a median particle size ranging from 0.3 g / cm, as measured according to ASTM D7481-18 modified using 10, 25, or 50 mL graduated cylinders instead of 100 or 250 mL graduated cylinders. 3 , 0.4g / cm 3 , 0.5g / cm 3 , 0.6g / cm 3 , 0.7g / cm 3 , 0.8g / cm 3 , 0.9g / cm 3 , or 1g / cm 3 from 1.1 g / cm 3 , 1.2g / cm 3 , 1.3g / cm 3 , 1.4g / cm 3 , 1.5g / cm 3 , 1.6g / cm 3 , 1.7g / cm 3 , 1.8g / cm 3 , 1.9g / cm 3 , or 2 g / cm 3 In some embodiments, the catalyst particles may have an apparent loose bulk density ranging from ≦5 wt%, ≦4 wt%, ≦3 wt%, ≦2 wt%, ≦1 wt%, ≦0.7 wt%, ≦0.5 wt%, ≦0.4 wt%, ≦0.3 wt%, ≦0.2 wt%, ≦0.1 wt%, ≦0.07 wt%, or ≦0.05 wt% after 1 hour, measured according to ASTM D5757-11(2017). The morphology of the particles is mostly spherical, making them suitable for moving in a fluidized bed reactor. In some embodiments, the catalyst particles may have a size and density consistent with the Geldart A or Geldart B definition of a flowable solid. In some embodiments, the catalyst particles are 0.1 m 2 / g, 1m 2 / g, 10m 2 / g, or 100m 2 / g to 500m 2 / g, 800m 2 / g, 1,000m 2 / g, or 1,500m 2 The catalyst particles may have a surface area ranging from 0.1 to 1.0 μm / g. The surface area of ​​the catalyst particles can be measured according to the Brunauer-Emmett-Teller (BET) method using nitrogen adsorption-desorption (liquid nitrogen temperature, 77 K) on a Micromeritics 3flex instrument after degassing the powder at 350° C. for 4 hours. More information on this method can be found, for example, in “Characterization of Porous Solids and Powders: Surface Area, Pore Size and Density,” S. Lowell et al., Springer, 2004.

[0057] The preparation of the support can be accomplished by any known process. For simplicity and ease of explanation, the preparation of suitable supports, including mixed oxides of magnesium and aluminum (Mg(Al)O or MgO / Al2O3) supports, will be described in more detail. Catalyst synthesis techniques are well known, and the following description is for illustrative purposes and should not be considered as limiting the synthesis of supports or catalyst particles. In some embodiments, to make MgO / Al2O3 mixed oxide supports, Mg and Al precursors, such as Mg(NO3)2 and Al(NO3)3, can be mixed together and, for example, ball milled and then calcined to produce the support. In another embodiment, the two precursors can be dissolved in H2O, stirred to dryness (optionally with heat) and then calcined to produce the support. In another embodiment, the two precursors can be dissolved in H2O and then a base and a carbonate, such as NaOH / Na2CO3, can be added to produce hydrotalcite and then calcined to produce the support. In another embodiment, commercially available MgO and Al2O3 can be mixed and ball milled. In another embodiment, the Mg(NO3)2 precursor may be dissolved in H2O and the solution may be impregnated onto an existing support, such as an Al2O3 support, dried, and calcined to produce the support. In another embodiment, Mg from Mg(NO3)2 may be loaded onto an existing Al2O3 support by ion adsorption, followed by liquid-solid separation, drying, and calcination to produce the support. Without wishing to be bound by theory, the support produced by any one of the above methods and / or other methods may include (i) Mg and Al mixed together on the nm scale, (ii) Mg and Al in the form of mixed Mg / Al metal oxides, or (iii) a combination of (i) and (ii).

[0058] The Group 8-10 metal and any promoter and / or any alkali metal element may be loaded onto the mixed oxide support by any known technique. For example, one or more Group 8-10 element precursors, such as chloroplatinic acid, tetraammineplatinum nitrate, and / or tetraammineplatinum hydroxide, one or more promoter precursors (if used), such as salts such as SnCl4 and / or AgNO3, and one or more alkali metal element precursors (if used), such as KNO3, KCl, and / or NaCl, may be dissolved in water. This solution may be impregnated onto the support and then dried and calcined. In some embodiments, the Group 8-10 element precursor and optionally the promoter precursor and / or alkali metal element precursor may be loaded onto the support simultaneously or separately in a sequence separated by a drying and / or calcination step. In other embodiments, the Group 8-10 element and optionally the promoter and / or alkali metal element may be loaded onto the support by chemical vapor deposition. In this case, the precursors may be vaporized and accumulated on the support and then calcined. In other embodiments, the Group 8-10 element precursor and, optionally, the promoter precursor and / or alkali metal precursor can be loaded onto the support via liquid-solid separation after ion adsorption, drying and calcination. Optionally, the catalyst particles are synthesized using a one-pot synthesis method, in which the precursor of the support, the Group 8-10 metal active phase and the promoter are all mixed together, wet or dry, with or without any other additives to aid in the synthesis, and then dried and calcined.

[0059] In some embodiments, the catalyst particles can be formulated into Geldart A or B type particles by well-known spray drying processes. Spray-dried catalyst particles having an average cross-sectional area ranging from 20 μm, 40 μm, or 50 μm to 80 μm, 90 μm, or 100 μm are typically used in FCC type fluidized bed reactors. To make the spray-dried catalyst particles, the support, Group 8-10 element, and any additional components, such as promoters and / or alkali metals, can be slurried, including binders / additives, and then spray-dried and calcined. Alternatively, the Group 8-10 element, and any additional components, such as promoters and / or alkali metals, can be added to a formulated support to produce the formulated catalyst particles. Suitable processes that can be used to prepare the catalyst particles disclosed herein include those described in U.S. Pat. Nos. 4,788,371; 4,962,265; 5,922,925; 8,653,317; European Patent No. EP0098622; Journal of Catalysis 94 (1985), pp. 547-557; and / or Applied Catalysis 54 (1989), pp. 79-90.

[0060] Hydrocarbon-containing feed C2-C 16The alkane may be or include, but is not limited to, ethane, propane, n-butane, isobutane, n-pentane, isopentane, n-hexane, 2-methylpentane, 3-methylpentane, 2,2-dimethylbutane, n-heptane, 2-methylhexane, 2,2,3-trimethylbutane, cyclopentane, cyclohexane, methylcyclopentane, ethylcyclopentane, n-propylcyclopentane, 1,3-dimethylcyclohexane, or mixtures thereof. For example, the hydrocarbon-containing feed may include propane, which may be dehydrogenated to produce propylene, and / or isobutane, which may be dehydrogenated to produce isobutylene. In another example, the hydrocarbon-containing feed may include liquid petroleum gas (LP gas), which may be in the gas phase upon contact with the catalyst particles. In some embodiments, the hydrocarbons in the hydrocarbon-containing feed may be substantially composed of a single alkane, such as propane. In some embodiments, the hydrocarbon-containing feed comprises ≥ 50 mol%, ≥ 75 mol%, ≥ 95 mol%, ≥ 98 mol%, or ≥ 99 mol% of a single C-C 16 In some embodiments, the hydrocarbon-containing feed may comprise at least 50 vol%, at least 55 vol%, at least 60 vol%, at least 65 vol%, at least 70 vol%, at least 75 vol%, at least 80 vol%, at least 85 vol%, at least 90 vol%, at least 95 vol%, at least 97 vol%, or at least 99 vol% of a single C2-C 16 It may include alkanes such as propane.

[0061] C8-C 16 The alkyl aromatic hydrocarbon may be or include, but is not limited to, ethylbenzene, propylbenzene, butylbenzene, one or more ethyltoluenes, or mixtures thereof. In some embodiments, the hydrocarbon-containing feed contains ≥ 50 mol%, ≥ 75 mol%, ≥ 95 mol%, ≥ 98 mol%, or ≥ 99 mol% of a single C8-C8 hydrocarbon, based on the total mass of all hydrocarbons in the hydrocarbon-containing feed. 16It may include alkyl aromatic hydrocarbons, such as ethylbenzene. In some embodiments, ethylbenzene may be dehydrogenated to produce styrene. Thus, in some embodiments, the processes disclosed herein may include propane dehydrogenation, butane dehydrogenation, isobutane dehydrogenation, pentane dehydrogenation decyclization to cyclopentadiene, naphtha reforming, ethylbenzene dehydrogenation, ethyltoluene dehydrogenation, and the like.

[0062] In some embodiments, the hydrocarbon-containing feed may be diluted with one or more diluent gases. Suitable diluents may be or include, but are not limited to, argon, neon, helium, molecular nitrogen, carbon dioxide, methane, molecular hydrogen, or mixtures thereof. When the hydrocarbon-containing feed includes a diluent, the hydrocarbon-containing feed may be diluted with any C2-C4 16 Alkanes and any C8-C 16 The diluent may comprise from 0.1 vol%, 0.5 vol%, 1 vol%, or 2 vol% to 3 vol%, 8 vol%, 16 vol%, or 32 vol%, based on the total volume of the alkylaromatic hydrocarbon. When the diluent comprises molecular hydrogen, it is preferable that the diluent is a mixture of molecular hydrogen and any C2-C 16 Alkanes and any C8-C 16 The molar ratio of the total amount of alkylaromatic hydrocarbons may range from 0.1, 0.3, 0.5, 0.7, or 1 to 2, 3, 4, 5, 6, 7, 8, 9, or 10. In some embodiments, when a diluent is used, the diluent may be mixed with the hydrocarbon-containing feed and / or introduced or otherwise fed to the conversion zone as a separate feed via one or more inlets dedicated to feeding the diluent to the conversion zone. Similarly, the hydrocarbon-containing feed may be introduced to the conversion zone via one or more inlets dedicated to feeding the hydrocarbon-containing feed to the conversion zone.

[0063] In some embodiments, the hydrocarbon-containing feed is substantially free of water or water vapor, e.g., any C-C 16 Alkanes and any C8-C 16Based on the total volume of alkylaromatic hydrocarbons, there is <0.1 vol.% water or steam. In other embodiments, the hydrocarbon-containing feed may contain steam. For example, the hydrocarbon-containing feed may be a mixture of any C2-C 16 Alkanes and any C8-C 16 Based on the total volume of alkylaromatic hydrocarbons, the alkylaromatic hydrocarbons may contain from 0.1 vol%, 0.3 vol%, 0.5 vol%, 0.7 vol%, 1 vol%, 3 vol%, or 5 vol% to 10 vol%, 15 vol%, 20 vol%, 25 vol%, 30 vol%, 35 vol%, 40 vol%, 45 vol%, or 50 vol% water or steam. In other embodiments, the hydrocarbon-containing feed is free of any C2-C 16 Alkanes and any C8-C 16 Based on the total volume of alkylaromatic hydrocarbons, the water or steam may contain ≦50 vol%, ≦45 vol%, ≦40 vol%, ≦35 vol%, ≦30 vol%, ≦25 vol%, ≦20 vol%, or ≦15 vol%. In other embodiments, the hydrocarbon-containing feed may contain ≦50 vol%, ≦45 vol%, ≦40 vol%, ≦35 vol%, ≦30 vol%, ≦25 vol%, ≦20 vol%, or ≦15 vol% water or steam. 16 Alkanes and any C8-C 16 It may comprise at least 1 vol%, at least 3 vol%, at least 5 vol%, at least 10 vol%, at least 15 vol%, at least 20 vol%, at least 25 vol%, or at least 30 vol% water or steam, based on the total volume of alkylaromatic hydrocarbons. As with the diluent, when water or steam is provided to the conversion zone, it may be provided to the conversion zone as a component of the hydrocarbon-containing feed or via one or more separate inlets dedicated to introducing steam into the conversion zone.

[0064] In some embodiments, the hydrocarbon-containing feed may contain sulfur. For example, the hydrocarbon-containing feed may contain sulfur in the range of 0.5 ppm, 1 ppm, 5 ppm, 10 ppm, 20 ppm, 30 ppm, 40 ppm, 50 ppm, 60 ppm, 70 ppm, or 80 ppm to 100 ppm, 150 ppm, 200 ppm, 300 ppm, 400 ppm, or 500 ppm. In other embodiments, the hydrocarbon-containing feed may contain sulfur in the range of 1 ppm to 10 ppm, 10 ppm to 20 ppm, 20 ppm to 50 ppm, 50 ppm to 100 ppm, or 100 ppm to 500 ppm. Sulfur, when present in the hydrocarbon-containing feed, may be or include, but is not limited to, H2S, dimethyl disulfide, one or more mercaptans, or any mixture thereof. In some embodiments, sulfur may be introduced into the conversion zone as a separate feed, as a component of the diluent, if used, and / or as a component of the steam, if used. The hydrocarbon-containing feed may be substantially or completely free of molecular oxygen. In some embodiments, the hydrocarbon-containing feed may contain ≦5 mol%, ≦3 mol%, or ≦1 mol% molecular oxygen (O2). Providing a hydrocarbon-containing feed that is substantially free of molecular oxygen is believed to substantially prevent oxidative coupling reactions that would otherwise consume at least a portion of the alkanes and / or alkyl aromatic hydrocarbons in the hydrocarbon-containing feed.

[0065] Representative Embodiments FIG. 1 shows a system 100 for dehydrogenating a hydrocarbon-containing feed in line 1001 according to one or more embodiments. The system 100 may include a reactor or conversion zone 1010, a separation zone 1015, a direct quench zone 1020, a combustion zone 1025, a reduction zone 1035, a quench zone 1040, a compression zone 1050, and a product recovery zone 1055. In some embodiments, the system 100 may optionally include a hydrocarbon-containing feed pretreatment zone 1005. In some embodiments, the system 100 may optionally include an oxygen flood zone 1030. The hydrocarbon-containing feed via line 1001 or a pretreated hydrocarbon-containing feed via line 1007 may be introduced into the conversion zone 1010, for example, into a fluidized bed reactor, for example, the lower end of a riser reactor or the upper end of a downer reactor. In some embodiments, the hydrocarbon-containing feed in line 1001 and / or the pretreated hydrocarbon-containing feed in line 1007 may include steam. From the reduction zone 1035, regenerated catalyst particles may be conveyed via line 1036 to the conversion zone 1010. A hydrocarbon-containing feed may be connected with the regenerated catalyst particles in the conversion zone 1010 to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed to produce a converted effluent via line 1013 which may contain coked catalyst particles, one or more dehydrogenated hydrocarbons, unreacted hydrocarbon-containing feed, steam, benzene, or any mixture thereof.

[0066] The converted effluent is introduced via line 1013 to separation zone 1015 which can separate the converted effluent into a first particulate stream via line 1017 enriched in coked catalyst particles and a first gaseous stream via line 1019 enriched in one or more dehydrogenated hydrocarbons and containing entrained coked catalyst particles. In some embodiments, the separation zone can include one or more cyclones arranged in series and / or in parallel. The first particle stream via line 1017 may be introduced into a combustion zone 1025. In some embodiments, the first particle stream may include entrained gaseous components, such as one or more dehydrogenated hydrocarbons, unreacted hydrocarbon-containing feed, steam, or mixtures thereof. In such embodiments, at least a portion of the gaseous components in the first particle stream via line 1017 may be stripped before the first particle stream is introduced into the combustion zone 1025. An oxidant via line 1022 and optionally a fuel via line 1024 may be introduced into the combustion zone 1025 and contact at least a portion of the coked catalyst particles in the first particle stream to cause combustion of at least a portion of the coke, and fuel, if present, to produce a combustion effluent comprising coke-lean catalyst particles and combustion or flue gases. The combustion of the coke and fuel, if present, may generate heat to burn coke from the coked catalyst, redisperse the Group 8-10 element(s) on the spent catalyst, and provide heat to the regenerated catalyst particles.

[0067] A second particulate stream rich in catalyst particles, less coke, via line 1026, and a second gaseous stream rich in combustion gases via line 1027 are recovered or otherwise obtained from the combustion zone 1025. The combustion effluent may enter one or more separators to return most of the entrained catalyst to the combustion zone. For the combustion zone, three or more stages of cyclones may also be installed to achieve high solids recovery efficiency from the flue gas. Residual catalyst particles may be further recovered downstream by using filters, electrostatic precipitators, wet gas scrubbers, etc. The operating conditions of the separators and / or cyclones for the conversion zone and the combustion zone may be adjusted to send more or less fines to either the conversion zone or the combustion zone, depending on the level of difficulty of fines collection from the product stream from the conversion zone versus fines collection from the flue gas stream from the combustion zone. As fuel is introduced into the combustion zone via line 1024, the second particle stream via line 1026 and the oxidizing gas via line 1028 may be introduced into the oxygen soaked zone 1030 where they contact to produce conditioned catalyst particles. The conditioned catalyst particles may be recovered from the oxygen soaked zone 1030 via line 1031 and the gas stream via line 1032. In some embodiments, the gas stream in line 1032 and the conditioned catalyst particles in line 1031 may be separated by one or more cyclones. In some embodiments, the same set of cyclones may be used to separate both the conditioned catalyst particles via line 1031 and the gas stream in line 1032, and the second particle stream via line 1026 and the combustion gases via line 1027.

[0068] The conditioned catalyst particles via line 1031, or when fuel is not introduced to the combustion zone via line 1024, a second particle stream via line 1026 and a reducing gas via line 1033 may be introduced to the reduction zone 1035 where they may be contacted to produce regenerated catalyst particles. The regenerated catalyst particles may be recovered via line 1036 and the gas stream via line 1037 from the reduction zone. In some embodiments, the regenerated catalyst particles via line 1036 and the gas stream via line 1037 may be separated by one or more cyclones. In other embodiments, the gas components in the reduction zone may be conveyed along with the regenerated catalyst particles via line 1036 to the conversion zone 1010 rather than being separated from the regenerated catalyst particles. The regenerated catalyst particles via line 1036 may be introduced to the conversion zone 1010 where they may be contacted with additional hydrocarbon-containing feed. In some embodiments, the gas stream in line 1037 may be recycled to the combustion zone such that any remaining reductant, such as H2, may serve as fuel for the combustion zone.

[0069] The first gaseous stream via line 1019 and the first quench medium via line 1018 may be introduced directly into quench zone 1020 where they may contact to produce a cooling gaseous stream. In some embodiments, benzene may be produced during the dehydrogenation of the hydrocarbon-containing feed and may be present in the cooling gaseous stream in line 1021. In some embodiments, benzene may be used as the first quench medium in line 1018. In some embodiments, the first quench medium stream may be in a liquid phase when contacted with the first gaseous stream in the direct quench zone 1020. In some embodiments, the first gaseous stream in line 1019 may be at a temperature >620°C and the cooling gaseous stream may be at a temperature of ≦620°C, ≦610°C, ≦600°C, ≦590°C, or ≦580°C. In some embodiments, the cooling gaseous stream may be at a temperature in the range of ≧550°C and ≦620°C or ≦600°C. Reducing the temperature of the first gaseous stream in line 1019 to below 600° C. may reduce or stop undesirable thermal reactions of the gaseous components. A cooled gaseous stream may be recovered via line 1021. In some embodiments, the direct quench zone 1020 may be replaced by one or more indirect heat conversion zones. In other embodiments, one or more indirect heat exchange zones may be used in conjunction with the direct quench zone 1020, anywhere upstream and / or downstream of the direct quench zone 1020.

[0070] The cooling gas stream via line 1021 and the second quench medium via line 1022 may be introduced into quench zone 1040 where they may contact to produce an overhead or third gas stream via line 1041, a recovered fines-lean second quench medium via line 1042, and a recovered coked catalyst particle stream via line 1043. In some embodiments, quench zone 1040 may include a quench tower. In some embodiments, the cooling gas stream may be introduced via line 1021 to a gas-liquid contacting zone disposed within the quench tower. In some embodiments, as described above, prior to entering the contacting zone, the cooling gas stream via line 1021 may pass through one or more heat exchangers for heat recovery. In the contacting zone disposed within the quench tower, the cooling gas stream may contact the second quench medium introduced into the quench tower via line 1022. The second quench medium in line 1022 may be sprayed downwardly against the cooling gas stream into the contact zone to ensure good contact between the cooling gas stream and the second quench medium. Within the contact zone, most of the catalyst fines and heat in the cooling gas stream may be transferred to the second quench medium to produce a slurry that may include at least a portion of the second quench medium in a liquid phase and at least a portion of the coked catalyst particles. In some embodiments, the slurry may accumulate at the bottom of the quench tower to form a liquid reservoir therein. In some embodiments, the second quench medium in line 1022 may have a higher normal boiling point than the first quench medium 1018. For example, in some embodiments, the first quench medium is benzene and the second quench medium may have a normal boiling point between 150° C. and 580° C.

[0071] In the quench zone 1040, the slurry may be introduced to one or more solid-liquid separation devices to produce a recovered fines-lean second quench medium stream via line 1042 and a recovered coked catalyst particle stream via line 1043. In some embodiments, at least a portion of the recovered coked catalyst particle stream via line 1043 may be introduced to an optional metals reclamation facility 1060. In one or more embodiments, at least a portion of the recovered coked catalyst particle stream via line 1043 may be introduced to the combustion zone 1025. In one or more embodiments, at least a portion of the recovered fines-lean second quench medium via line 1042 may be recycled back to the quench tower in the quench zone 1040. In some embodiments, a first quench medium having a lower normal boiling point than the second quench medium may be withdrawn from the quench tower at a location above the gas-liquid contacting zone within the quench tower, cooled by one or more heat exchangers, and a first portion or amount may be recycled back to the direct contacting zone via line 1018. In some embodiments, the first quench medium may be one of the alkane dehydrogenation products, benzene, such that a second portion or amount of the cooled first quench medium may be withdrawn to form a product stream. In some embodiments, a third portion or amount of the cooled first quench medium may be recycled to the quench tower.

[0072] At a location within the quench tower above the contact zone, any water present in the quench tower may be withdrawn from the quench tower, cooled by one or more heat exchangers, and circulated back to the quench tower. A portion or amount of the cooling water is withdrawn to form a wastewater stream that may be sent for treatment and / or vaporized and used as a co-feed with the hydrocarbon hydrogen-containing feed in line 1001 or the pretreated hydrocarbon-containing feed in line 1007. The third gas stream exiting quench zone 1040 via line 1041 is essentially free of coked catalyst particles and may be further cooled and introduced into compression zone 1050 to produce a compressed gas stream via line 1051. If the third gas stream in line 1041 contains any residual coked catalyst particles, the coked catalyst particles may be removed by one or more electrostatic precipitators, one or more filters, one or more screens, one or more membranes, wet gas scrubbers, contact with an absorbent scavengers, one or more additional quench towers, one or more electrocyclones, one or more hydrocyclones, one or more centrifuges, one or more plates or cones, or any combination thereof to remove at least a portion of the entrained coked catalyst particles from the gas stream.

[0073] The compressed gas stream may be introduced via line 1051 to a product recovery zone 1055 to separate products therefrom. In some embodiments, the products may include, but are not limited to, light gases via line 1056, an unreacted hydrocarbon-containing feed via line 1057, one or more dehydrogenated hydrocarbons via line 1058, and one or more liquid hydrocarbons via line 1059. The one or more light gases may be or include, but are not limited to, hydrogen, methane, ethane, propane, butane, or mixtures thereof. In some embodiments, the one or more light gases via line 1056 may be introduced as an optional fuel via line 1024 to the combustion zone. In some embodiments, at least a portion of the unreacted hydrocarbon-containing feed may be recycled to the conversion zone via line 1057. In some embodiments, the dehydrogenated hydrocarbons in line 1058 may be further processed to produce one or more products, such as polyethylene, polypropylene, and / or other polymer products. In some embodiments, at least a portion of the one or more liquid hydrocarbons in line 1059 may be used as the first and / or second quench medium or may be used as a quench medium elsewhere.

[0074] In some embodiments, a fourth gaseous stream may be introduced into the product recovery zone 1055 via line 1053. The fourth gaseous stream in line 1053 may be in fluid communication with a primary fractionator that receives the steam cracker effluent and separates various hydrocarbon fractions therefrom. For example, the primary fractionator may separate the steam cracker effluent into a tar product, a steam cracker quench oil product, a steam cracker gas oil product, a steam cracker naphtha product, and a steam cracker gas overhead product that may include hydrogen, methane, ethane, ethylene, propane, propylene, butenes, butanes, pentanes, and other volatile hydrocarbons. In some embodiments, the fourth gaseous stream in line 1053 may be compressed. In other embodiments, the fourth gaseous stream via line 1053 may be combined with the third gaseous stream in line 1041 and introduced into the compression zone 1050 to generate a mixed third and fourth compressed gaseous stream in line 1051. EXAMPLES

[0075] Working Example The above discussion can be further illustrated with reference to the following non-limiting examples. Catalyst composition 1: was prepared by mixing CATAPAL® D pseudoboehmite (Sasol) (47 g) and calcined Mg-Al hydrotalcite (PURALOX® MG70) (44 g) containing 70 wt% MgO and 30 wt% Al2O3 in deionized water (524 ml) to prepare a slurry. The slurry was milled and spray dried in a Buchi B-290 mini spray dryer to produce spray-dried particles. The spray-dried particles were calcined in air at 550° C. for 4 hours to produce calcined support particles containing nominally 50 wt% PURALOX® MG70 and 50 wt% Al2O3 derived from CATAPAL® D. The calcined support particles were impregnated with an aqueous solution containing tin(IV) chloride pentahydrate, chloroplatinic acid hexahydrate, and deionized water using incipient wetness impregnation. The impregnated material was calcined at 800° C. in air for 12 hours to produce a catalyst composition containing nominally 0.3 wt % Pt and 1.5 wt % Sn on 50:50 MG70:CATAPAL®D.

[0076] Catalyst composition 2: was prepared by mixing 40 wt% aluminum chlorohydrol solution (ACH) (85 g) and calcined Mg-Al hydrotalcite (PURALOX® MG70) (88 g) in deionized water (596 ml) to prepare a slurry. The slurry was milled and spray dried in a Buchi B-290 mini spray dryer to produce spray-dried particles. The spray-dried particles were calcined in air at 550° C. for 4 hours to produce calcined support particles containing nominally 80 wt% PURALOX® MG70 and 20 wt% Al2O3 derived from ACH. The calcined support particles were impregnated with an aqueous solution containing tin(IV) chloride pentahydrate, chloroplatinic acid hexahydrate, and deionized water using incipient wetness impregnation. The impregnated material was calcined at 800° C. in air for 12 hours to produce a catalyst composition containing nominally 0.3 wt % Pt and 1.5 wt % Sn on 80:20 MG70:ACH.

[0077] Catalyst composition 3: This catalyst was prepared according to the following procedure. 2.3 g of PURALOX® MG70 / 170 (Sasol), a MgO-Al2O3 mixed metal oxide obtained by calcining hydrotalcite, was secured. The mixed metal oxide contained 70 wt% MgO and 30 wt% Al2O3. According to Sasol, the BET surface area was 170 m 2 / g. A solution was made by mixing tin(IV) chloride pentahydrate (0.103 g) (Acros Organics), chloroplatinic acid hexahydrate (0.0184 g) (BioXtra), and deionized water (2.2 mL) in a small glass vial. This solution was impregnated into the PURALOX® MG70 / 170 support. All of the impregnated material was dried in air at 110° C. for 6 hours and calcined at 800° C. for 12 hours. The final product was nominally impregnated with 0.3 wt % Pt and 1.5 wt % Sn.

[0078] Catalyst Composition 4: This catalyst was prepared according to the following procedure. 20 g of PURALOX® MG70 / 170 (Sasol), a MgO-Al2O3 mixed metal oxide obtained by calcining hydrotalcite, was secured. The mixed metal oxide contained 70 wt% MgO and 30 wt% Al2O3. According to Sasol, the BET surface area was 170 m 2 / g. An appropriate amount of tin(II) chloride dehydrate was mixed with deionized water to form a solution. This solution was impregnated onto PURALOX® MG70 / 170 support. The impregnated material was kept in a closed container at room temperature for 1 hour and then dried at 120°C overnight. An appropriate amount of tetraammine platinum(II) nitrate was mixed with deionized water to form a solution. The Sn-impregnated support was further impregnated with the Pt solution. The impregnated material was kept in a closed container at room temperature for 1 hour and then all were dried at 120°C in air overnight and calcined at 800°C for 12 hours. The final product contained nominally 0.3 wt% Pt and 1.5 wt% Sn.

[0079] Catalyst compositions 5 to 18 were prepared according to the following procedure. For each catalyst composition, 80 wt% MgO and 20 wt% Al2O3 were contained, and 150 ml 2 PURALOX® MG80 / 150 (3 grams), a mixed Mg / Al metal oxide with a surface area of ​​1000 g / g (Sasol), was calcined at 550° C. for 3 hours under air to form a support. A solution containing the appropriate amount of tin(IV) chloride pentahydrate when used to make the catalyst composition (Acros Organics) and / or chloroplatinic acid when used to make the catalyst composition (Sigma Aldrich) and 1.8 ml of deionized water was prepared in a small glass vial. For each catalyst composition, a calcined PURALOX® MG80 / 15 support (2.3 grams) was impregnated with the corresponding solution. The impregnated material was equilibrated at room temperature (RT) for 24 hours in a closed vessel, dried at 110° C. for 6 hours, and calcined at 800° C. for 12 hours. Table 1 shows the nominal Pt and Sn content based on the weight of the support for each catalyst composition.

[0080] [Table 1]

[0081] Examples using the above catalysts 1 to 4 The fixed bed experiments were carried out at approximately 100 kPa absolute pressure. A gas chromatograph (GC) was used to measure the composition of the reactor effluent. The concentrations of each component in the reactor effluent were then used to calculate the yield and selectivity of C3H6. The yield and selectivity of C3H6 reported in these examples were calculated on a moles of carbon basis. In each example, 0.3 g of catalyst Mcat was mixed with an appropriate amount of quartz diluent and loaded into a quartz reactor. The amount of diluent was determined so that the catalyst bed (catalyst + diluent) overlapped with the isothermal zone of the quartz reactor and the catalyst bed was mostly isothermal during operation. Quartz chips / rods filled the dead volume of the reactor. The concentration of each component in the reactor effluent was used to calculate the yield and selectivity of C3H6. rxn At the start of t rxn The yield and selectivity of C3H6 at the end of ini , Yend , S ini , and S end and reported in the table below as a percentage.

[0082] The process steps for Examples 1 and 2 were as follows: 1. The system was flushed with inert gas. 2. While the inert gas was being passed through the reaction zone, an oxygen-containing gas (Ogas) was introduced at a flow rate (F regen The reaction zone was then bypassed at a regeneration temperature T regen 3. The oxygen-containing gas is then introduced into the reaction zone for a specific period of time (t regen The catalyst was regenerated by passing it through a t regen Then, while maintaining the flow rate of the oxygen-containing gas, the temperature in the reaction zone is increased to T regen to the reduction temperature (T red 4. The system was flushed with inert gas. 5. While passing the inert gas through the reaction zone, the H2-containing gas (Hgas) was added at a flow rate (F red ) was passed through the reaction zone bypass for a specific time. After this, H2-containing gas was passed through the reaction zone bypass at T red in the reaction zone for a certain time (t red 6. The system was flushed with inert gas. During this process, the temperature of the reaction zone was maintained at T red 7. The reaction temperature was changed from 655°C to 655°C. 8. A hydrocarbon-containing (HCgas) feed containing 81 vol% C3H8, 9 vol% inert (Ar or Kr) and 10 vol% water vapor was fed at a flow rate (F rxn ) through the reaction zone bypass for a specified time. The hydrocarbon-containing feed was then passed through the reaction zone at 655°C for 10 minutes. GC sampling of the reaction effluent was started immediately after the feed was switched from the reaction zone bypass to the reaction zone. The above process steps were repeated periodically until stable performance was obtained. Table 2 shows that both Catalyst 1 and Catalyst 2 were active / selective for propane dehydrogenation. Figure 2 shows that Catalyst 2 was stable for propane dehydrogenation over 60 cycles.

[0083] [Table 2]

[0084] Example 3 - Effect of water vapor during oxidation. The process steps were as follows: 1. The reaction zone was heated to an oxidation temperature T oxi 2. While the inert gas was passing through the reaction zone, oxygen-containing gas (Ogas) was passed at a flow rate (F oxi 3. An oxygen-containing gas is then introduced into the reaction zone for a specific time (t oxi ) to oxidize the catalyst. oxi Then, an inert gas is passed through the reaction zone to raise the temperature in the reaction zone to T oxi to the reduction temperature (T red 5. The system was flushed with inert gas. 6. While the inert gas was being passed through the reaction zone, the H2-containing gas (Hgas) was introduced at a flow rate (F red ) was passed through the reaction zone bypass for a specific time. After this, H2-containing gas was passed through the reaction zone bypass at T red in the reaction zone for a certain time (t red 7. The system was flushed with inert gas. During this process, the temperature of the reaction zone was increased to T red 8. The reaction temperature was changed from 670° C. to 670° C. 9. A hydrocarbon-containing (HCgas) feed containing 81 vol.% C3H8, 9 vol.% inert (Ar or Kr), and 10 vol.% water vapor was added at a flow rate (F rxn ) through the bypass of the reaction zone for a specific time. The hydrocarbon-containing feed was then passed through the reaction zone at 670°C for 10 minutes. GC sampling of the reaction effluent was started as soon as the feed was switched from the reaction zone bypass to the reaction zone. The above process steps were repeated periodically until stable performance was obtained. Table 3 shows that the presence of more than 10 vol% water vapor in the air during oxidation led to a more deactivated catalyst after regeneration (56.8% vs. 61.1% C3H6 yield). The more water vapor present in the air during oxidation, the lower the activity. On the other hand, switching the wet air to dry air after 2 minutes of oxidation efficiently regenerated the catalyst.

[0085] [Table 3]

[0086] Example 4 - Effect of H2 reduction duration. 1. Inert gas was flowed through the system while the reaction zone was heated to an oxidation temperature of 800°C. 2. While the inert gas was passed through the reaction zone, oxygen-containing gas (Ogas) was passed at a flow rate (F oxi 3. An oxygen-containing gas is then introduced into the reaction zone for a specific time (t oxi ) to oxidize the catalyst. 4. An inert gas was passed through the system. During this process, the temperature of the reaction zone was maintained at 800°C. 5. While the inert gas was passed through the reaction zone, H2-containing gas (Hgas) was passed at a flow rate (F red ) into the bypass of the reaction zone for a specific time. After this, H2-containing gas was passed into the reaction zone at 800 °C for a specific time (t red ) over a flow rate (F ). 6. He was passed through the reaction zone. During this process, the temperature of the reaction zone was reduced from 800°C to the reaction temperature of 655°C. 7. While the inert gas was passed through the reaction zone, a hydrocarbon-containing (HCgas) feed containing 81 vol% C3H8, 9 vol% inert (Ar or Kr) and 10 vol% water vapor was passed through the reaction zone at a flow rate (F rxn ) through the bypass of the reaction zone for a specified time. The hydrocarbon-containing feed was then passed through the reaction zone at 655°C for 10 minutes. GC sampling of the reaction effluent was started as soon as the feed was switched from the reaction zone bypass to the reaction zone. The above process steps were repeated periodically until stable performance was obtained. Table 4 shows that without catalyst reduction, the propylene yield of the oxidized catalyst (53.7%) was even lower than that of the deactivated catalyst (61.3%).

[0087] [Table 4]

[0088] Example 5 - Fixed bed experiments were carried out using catalysts 5-18 at approximately 100 kPa absolute pressure. The composition of the reactor effluent was measured using a gas chromatograph (GC). The concentration of each component in the reactor effluent was then used to calculate the yield and selectivity to C3H6. The yield and selectivity to C3H6 reported in these examples were calculated on a moles of carbon basis. For each example, 0.3 g of catalyst composition was mixed with an appropriate amount of quartz diluent and loaded into a quartz reactor. The amount of diluent was determined so that the catalyst bed (catalyst + diluent) overlapped with the isothermal zone of the quartz reactor and the catalyst bed was mostly isothermal during operation. Quartz chips / rods filled the dead volume of the reactor. t rxn At the start of t rxn The yield and selectivity of C3H6 at the end of ini , Y end , S ini , and S end and are reported as percentages in Tables 5 and 6 below for catalyst compositions 5-12.

[0089] The process steps for catalyst compositions 5-12 were as follows: 1. The system was flushed with inert gas. 2. While the inert gas was being passed through the reaction zone, dry air was passed through the bypass of the reaction zone at a flow rate of 83.9 sccm. The reaction zone was heated to a regeneration temperature of 800°C. 3. Dry air was then passed through the reaction zone at a flow rate of 83.9 sccm for 10 minutes to regenerate the catalyst. 4. The system was flushed with inert gas. 5. While the inert gas was being passed through the reaction zone, H2-containing gas (Hgas), which contains 10 vol% H2 and 90 vol% Ar, was passed through the bypass of the reaction zone at a flow rate of 46.6 sccm for a specified time. This was followed by a flow of H2-containing gas into the reaction zone at 800°C for 3 seconds. 6. The system was flushed with inert gas. During this process, the temperature of the reaction zone was changed from 800°C to the reaction temperature of 670°C. 7. A hydrocarbon-containing (HCgas) feed containing 81 vol% C3H8, 9 vol% inert gas (Ar or Kr) and 10 vol% water vapor was passed through the bypass of the reaction zone at a flow rate of 35.2 sccm for a specified time while passing an inert gas through the reaction zone. The hydrocarbon-containing feed was then passed through the reaction zone at 670°C for 10 minutes. GC sampling of the reaction effluent was started as soon as the feed was switched from the bypass of the reaction zone to the reaction zone. The above process steps were repeated periodically until stable performance was obtained. Tables 5 and 6 show that catalyst composition 10 containing only 0.025 wt% Pt and 1 wt% Sn both had similar yields and similar selectivities compared to catalyst composition 5 containing 0.4 wt% Pt and 1 wt% Sn, which was surprising and unexpected. Catalyst composition 12, which did not contain any Pt, did not show any appreciable propylene yield.

[0090] [Table 5]

[0091] [Table 6]

[0092] Catalyst compositions 13-18 were also tested using the same process steps 1-7 as described above for catalysts 5-12. Table 7 shows that for optimal propylene yields for catalyst compositions containing 0.1 wt% Pt based on the mass of the support, the Sn level should not be too low or too high.

[0093] [Table 7]

[0094] Table 8 shows that for optimal propylene yields for catalyst compositions containing 0.0125 wt% Pt based on the weight of the support, the Sn level should not be too high or too low.

[0095] [Table 8]

[0096] Catalyst composition 10, containing only 0.025 wt % Pt and 1 wt % Sn, was also subjected to a life test utilizing the same process steps 1-7 described above for catalyst compositions 5-12, except that a flow rate of 17.6 sccm was used instead of 35.2 sccm in step 7. Figure 3 shows that catalyst composition 10 maintained its performance over 204 cycles (x-axis is time, y-axis is yield of C3H6 and selectivity to C3H6, both in mole % carbon).

[0097] LIST OF EMBODIMENTS The present disclosure may further include the following non-limiting embodiments. A1. A hydrocarbon upgrading process comprising: (I) contacting a hydrocarbon-containing feed with fluidized dehydrogenation catalyst particles in a conversion zone to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed to produce a conversion effluent comprising coked catalyst particles and one or more dehydrogenated hydrocarbons, wherein the hydrocarbon-containing feed is one or more C2-C 16 Linear or branched alkanes, at least one C4-C 16Cyclic alkanes, one or more of C8-C 16 and the hydrocarbon-containing feed comprises any C2-C alkyl aromatic hydrocarbon, or mixtures thereof, 16 Alkanes and any C8-C 16 Based on the mass of aromatic hydrocarbons, 0.1 hours -1 ~1,000 hours -1 In contact with the catalyst particles at a mass hourly space velocity in the range of 16 Alkanes and any C8-C 16 (II) separating from the conversion effluent a first particulate stream enriched in coked catalyst particles and a first gaseous stream enriched in one or more dehydrogenated hydrocarbons; (III) contacting at least a portion of the coked catalyst particles in the first particulate stream with an oxidant in a combustion zone to cause combustion of at least a portion of the coke to produce a combustion effluent comprising reduced coke catalyst particles and combustion gases, wherein a dehydrogenation activity of the reduced coke catalyst particles is lower than a dehydrogenation activity of the coked catalyst particles, and wherein the combustion zone is heated by an electric heater; and (IV) separating from the conversion effluent a first particulate stream enriched in coked catalyst particles and a first gaseous stream enriched in one or more dehydrogenated hydrocarbons, wherein the dehydrogenation activity of the reduced coke catalyst particles is lower than a dehydrogenation activity of the coked catalyst particles, and wherein the combustion zone is heated by an electric heater. (V) contacting at least a portion of the second particulate stream with a reducing gas in a reduction zone to produce regenerated catalyst particles having a higher dehydrogenation activity than the coked catalyst particles; (VI) contacting an additional amount of a hydrocarbon-containing feed with at least a portion of the regenerated catalyst particles in a conversion zone to produce an additional amount of a converted effluent comprising recoked catalyst particles and an additional amount of one or more dehydrogenated hydrocarbons; (VII) cooling the first gas stream to produce a cooled gas stream; (VIII) compressing at least a portion of the cooled gas stream to produce a compressed gas stream; and (IX) separating a plurality of products from the compressed gas stream.

[0098] A2. The process of A1, wherein no supplemental hydrocarbon fuel is introduced into the combustion zone. A3. A process as in A1 or A2, wherein any hydrocarbons present in the combustion zone include entrained hydrocarbons from the conversion effluent. A4. The hydrocarbon-containing feed is any C2-C 16 Alkanes and any C8-C 16 Based on the mass of aromatic hydrocarbons, 0.1 hours -1 ~100 hours -1 , preferably 0.2 hours -1 ~64 hours -1 , or more preferably 0.4 hours -1 ~32 hours -1 The process of any one of A1 to A3, wherein the catalytic converter is contacted with fluidized dehydrogenation catalyst particles at a mass hourly space velocity in the range of. A5. Any C2-C 16 Alkanes and any C8-C 16 The process of any one of A1 to A4, wherein the mass ratio of fluidized dehydrogenation catalyst particles to the total amount of aromatic hydrocarbons is in the range of 5-90, more preferably 10-80. A6. Any one of the processes of A1-A5, wherein the hydrocarbon-containing feed is contacted with the fluidized dehydrogenation catalyst particles for a duration of from 0.1 seconds to 2 minutes, preferably from 1 second to 1 minute, more preferably from 0.5 seconds to 3 seconds. A7. Any one of the processes of A1 to A5, wherein the hydrocarbon-containing feed is contacted with the fluidized dehydrogenation catalyst particles under a total pressure of from 0 kPa gauge to 500 kPa gauge, preferably from 20 kPa gauge to 300 kPa gauge, and more preferably from 40 kPa gauge to 200 kPa gauge. A8. Any one of the processes of A1 to A7, wherein the hydrocarbon-containing feed comprises 0.1 mol % to 15 mol % water steam, preferably 1 mol % to 10 mol % water steam, more preferably 3 mol % to 8 mol % water steam. A9. Any one of the processes of A1-A8, wherein the hydrocarbon-containing feed is at a temperature of ≦620° C. upon initial contact with the fluidized dehydrogenation catalyst particles. A10. Any one of the processes of A1-A9, wherein the second particle stream is contacted with a reducing gas in step (V) at a temperature in the range of from 450°C to 900°C, preferably from 600°C to 900°C, more preferably from 620°C to 800°C. A11. Any one of the processes of A1-A10, wherein the second particle stream is contacted with a reducing gas in step (V) for a duration of from 0.1 seconds to 300 seconds, preferably from 1 second to 100 seconds, and more preferably from 2 seconds to 10 seconds to produce regenerated catalyst particles.

[0099] A12. Any one of the processes of A1-A11, wherein the first gaseous stream enriched in the one or more dehydrogenated hydrocarbons further comprises entrained coking catalyst particles, step (VII) comprises: (VIIa) contacting the first gaseous stream with a first quenching medium to indirectly transfer heat from the first gaseous stream to a first heat transfer medium, or a combination thereof, to produce a cooled gaseous stream; (VIIb) contacting the cooled gaseous stream with a second quenching medium in a quenching tower; and (VIIc) recovering from the quenching tower a third gaseous stream comprising the one or more dehydrogenated hydrocarbons and a slurry stream comprising at least a portion of the second quenching medium in a liquid phase and the entrained coking catalyst particles; and step (VIII) comprises compressing at least a portion of the third gaseous stream to produce a compressed gaseous stream. A13. The process of A12, wherein the conversion effluent further comprises benzene, and the process further comprises the step of: (X) withdrawing a benzene product stream from the quench tower. A14. The process of A12 or A13, wherein step (VIIa) comprises contacting the first gas stream with a first quench medium. A15. Any one of the processes of A1-A11, wherein the first particle stream and the first gaseous stream are separated from the converted effluent in one or more cyclones, and the first gaseous stream is contacted with a first quench medium in at least one plenum of the one or more cyclones in step (VII) to produce a quenched gaseous stream. A16. The process of A15, wherein the residence time of the gaseous component in the first gaseous stream in each of the one or more cyclones is ≦1 second.

[0100] A17. Any one of the processes of A1-A16, wherein the converted effluent has a temperature of ≧620°C and the cooling gas stream has a temperature of ≧500°C and <620°C, preferably ≧550°C to ≦600°C. A18. The process of any one of A1-A17, wherein the dehydrogenation catalyst particles comprise 0.001 wt% to 6 wt% of a Group 8-10 element and optionally up to 10 wt% of a promoter comprising Sn, Cu, Au, Ag, Ga, combinations thereof, or mixtures thereof disposed on a support, where all weight percentages are based on the weight of the support. A19. The process of any one of A1-A18, wherein the dehydrogenation catalyst particles comprise 0.001 wt% to 6 wt% Pt and optionally up to 10 wt% promoter including Sn, Cu, Au, Ag, Ga, combinations or mixtures thereof disposed on a support, where the support contains at least 0.5 wt% Group 2 element, and all mass percentages are based on the weight of the support. A20. Any one of the processes of A1 to A19, wherein the dehydrogenation catalyst particles meet the requirements of Geldart A or Geldart B classification. A21. Any one of the processes of A1-A20, wherein in step (IX), a plurality of products are separated from the compressed gas stream in a product recovery unit that also receives a separated gaseous overhead product from a primary fractionator that receives the pyrolysis effluent from a stream cracker furnace. A22. Any one of the processes of A1-A21, wherein the hydrocarbon-containing feed comprises biomass-derived propane. A23. Any one of the processes of A1 to A22, wherein the hydrocarbon-containing feed comprises liquefied petroleum gas. A24. Any one of the processes of A1-A23, wherein the oxidant used in step (III) comprises ≧95 mol % O2. A25. Any one of the processes of A1-A24, wherein the conversion zone and the combustion zone are located within a modified fluid catalytic cracking reactor-regenerator unit.

[0101] Various terms have been defined above. Unless a term used in the claims is defined above, it should be given the broadest definition that one skilled in the art would give that term as reflected in at least one publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are incorporated by reference in their entirety to the extent that their disclosures are not inconsistent with this application, and for all authorities to which such incorporation is permitted. While the forgoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, the scope of which is determined by the claims that follow.

Claims

1. 1. A hydrocarbon upgrading process comprising: (I) contacting a hydrocarbon-containing feed with fluidized dehydrogenation catalyst particles in a conversion zone to cause dehydrogenation of at least a portion of said hydrocarbon-containing feed and producing a converted effluent comprising coked catalyst particles and one or more dehydrogenated hydrocarbons; The hydrocarbon-containing feed may comprise one or more C 2 -C 16 Linear or branched alkanes, one or more C 4 -C 16 Cyclic alkanes, one or more of C 8 -C 16 alkyl aromatic hydrocarbons, or mixtures thereof; The hydrocarbon-containing feed is a feed containing any C 2 -C 16 Alkanes and any C 8 -C 16 0.1 hours based on the mass of aromatic hydrocarbons -1 ~1,000 hours -1 contacting the catalyst particles at a mass hourly space velocity in the range of Both C 2 -C 16 Alkanes and any C 8 -C 16 The mass ratio of the fluidized dehydrogenation catalyst particles to the total amount of aromatic hydrocarbons is in the range of 3 to 100; and contacting the hydrocarbon-containing feed and the catalyst particles at a temperature in the range of 600°C to 750°C; (II) separating from the converted effluent a first particulate stream enriched in the coked catalyst particles and a first gaseous stream enriched in the one or more dehydrogenated hydrocarbons; (III) contacting at least a portion of the coked catalyst particles in the first particle stream with an oxidant and a fuel in a combustion zone to cause combustion of at least a portion of the coke to produce a combustion effluent comprising coke-lean catalyst particles and combustion gases, wherein the coke-lean catalyst particles have a lower dehydrogenation activity than the coked catalyst particles; (IV) separating the coke-depleted catalyst particle-rich second particulate stream and the combustion gas-rich second gas stream from the combustion effluent; (V) contacting at least a portion of the less-coked catalyst particles in the second particle stream with an oxidizing gas in an oxygen soak zone at an oxidation temperature in the range of 620°C to 1,000°C for a duration of at least 20 seconds to produce conditioned catalyst particles having lower activity than the coked catalyst particles; (VI) contacting at least a portion of the conditioned catalyst particles with a reducing gas in a reduction zone to produce regenerated catalyst particles having a higher dehydrogenation activity than the coked catalyst particles; (VII) contacting an additional amount of said hydrocarbon-containing feed with at least a portion of said regenerated catalyst particles in said conversion zone to produce an additional amount of a converted effluent comprising recoked catalyst particles and an additional amount of said one or more dehydrogenated hydrocarbons; (VIII) cooling the first gas stream to produce a cooled gas stream; (IX) compressing at least a portion of the cooled gas stream to produce a compressed gas stream; (X) separating a plurality of products from the compressed gas stream; The dehydrogenation catalyst particles comprise a support comprising Al in the form of an oxide and a Group 2 element; The process.

2. 10. The process of claim 1, wherein the hydrocarbon-containing feed comprises 0.1 mol % to 15 mol % steam.

3. 3. The process of claim 1 or claim 2, wherein the hydrocarbon-containing feed is at a temperature of ≦620° C. upon initial contact with the fluidized dehydrogenation catalyst particles.

4. 3. The process of claim 1 or claim 2, wherein in step (V), the coke-lean catalyst particles in the second particle stream are contacted with the oxidizing gas for a duration of from 0.5 minutes to 30 minutes.

5. The oxidizing gas of step (V) contains 5% or less H based on the total moles of the oxidizing gas. 2 3. The process of claim 1 or claim 2, comprising O.

6. 3. The process of claim 1 or claim 2, wherein in step (VI), the conditioned catalyst particles are contacted with the reducing gas at a temperature in the range of 450°C to 900°C.

7. 3. The process of claim 1 or claim 2, wherein in step (VI), the conditioned catalyst particles are contacted with the reducing gas for a duration of 0.1 seconds to 300 seconds to produce the regenerated catalyst particles.

8. the first gaseous stream enriched in the one or more dehydrogenated hydrocarbons further comprises entrained coking catalyst particles; Step (VIII) (VIIIa) contacting the first gas stream with a first quench medium to indirectly transfer heat from the first gas stream to a first heat transfer medium, or a combination thereof, to generate the cooled gas stream; (VIIIb) contacting the cooled gas stream with a second quench medium in a quench tower; (VIIIc) recovering from the quench tower a third gaseous stream comprising the one or more dehydrogenated hydrocarbons and a slurry stream comprising at least a portion of the second quenching medium in a liquid phase and the entrained coked catalyst particles; and step (IX) comprising compressing at least a portion of the third gas stream to produce the compressed gas stream; 3. The process of claim 1 or claim 2.

9. 9. The process of claim 8, wherein step (VIIIa) comprises contacting the first gas stream with the first quench medium.

10. 3. The process of claim 1 or claim 2, wherein the first particle stream and the first gaseous stream are separated from the converted effluent in one or more cyclones, and the first gaseous stream is contacted with a first quench medium in at least one plenum of the one or more cyclones in step (VIII) to produce the quenched gaseous stream.

11. 11. The process of claim 10, wherein the residence time of gaseous components in the first gas stream in each of the one or more cyclones is ≦1 second.

12. 3. The process of claim 1 or claim 2, wherein the converted effluent is at a temperature of ≥ 620°C and the cooling gas stream is at a temperature of ≥ 500°C and < 620°C.

13. 3. The process of claim 1 or claim 2, wherein the dehydrogenation catalyst particles comprise 0.001 wt % to 6 wt % of a Group 8-10 element and optionally up to 10 wt % of a promoter comprising Sn, Cu, Au, Ag, Ga, combinations thereof, or mixtures thereof disposed on a support, wherein all weight percentages are based on the weight of the support.

14. 3. The process of claim 1 or claim 2, wherein the dehydrogenation catalyst particles comprise 0.001 wt % to 6 wt % Pt and optionally up to 10 wt % promoter comprising Sn, Cu, Au, Ag, Ga, combinations thereof, or mixtures thereof disposed on a support, wherein the support comprises at least 0.5 wt % Group 2 element, and all weight percentages are based on the weight of the support.

15. 3. The process of claim 1 or claim 2, wherein the dehydrogenation catalyst particles meet the requirements of Geldart A or Geldart B classification.

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