CN117794886A

CN117794886A - Process for dehydrogenating alkanes and alkylaromatic hydrocarbons

Info

Publication number: CN117794886A
Application number: CN202280054987.8A
Authority: CN
Inventors: S·S·马杜斯卡尔; 鲍筱颖; K·H·库克莱尔
Original assignee: ExxonMobil Chemical Patents Inc
Current assignee: ExxonMobil Chemical Patents Inc
Priority date: 2021-08-13
Filing date: 2022-07-22
Publication date: 2024-03-29

Abstract

The hydrocarbon feed may be contacted with the dehydrogenation catalyst particles to produce a conversion effluent comprising coked catalyst particles and dehydrogenated hydrocarbon(s). Coked catalyst particles can be contacted with an oxidant and a fuel, thereby producing a combustion effluent that can include coke-depleted catalyst particles and combustion gases. The char-depleted catalyst particles may be contacted with the oxidizing gas at the oxidation temperature for a duration of at least 30 seconds, thereby producing conditioned catalyst particles that may have activity that may be less than coked catalyst particles. The conditioned catalyst particles may be contacted with a reducing gas to produce regenerated catalyst particles that may have dehydrogenation activity that may be greater than coked catalyst particles. The dehydrogenated hydrocarbon(s) can be cooled, compressed, and various products can be separated from the compressed gas stream.

Description

Process for dehydrogenating alkanes and alkylaromatic hydrocarbons

Cross Reference to Related Applications

The present application claims priority and benefit from U.S. provisional application number 63/232,959, at day 2021, 8, 13 and U.S. provisional application number 63/328,971, at day 2022, 4, 8, the disclosures of both of which are incorporated herein by reference in their entirety.

Technical Field

The present disclosure relates to a process for dehydrogenating one or more alkanes and/or alkylaromatic hydrocarbons. More specifically, the present disclosure relates to a process for dehydrogenating 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

Catalytic dehydrogenation of alkanes and/or alkylaromatic hydrocarbons is an industrially important chemical conversion process that is endothermic and equilibrium limited. Alkanes such as C can be achieved by a variety of different supported catalyst particle systems such as Pt-based, cr-based, ga-based, V-based, zr-based, in-based, W-based, mo-based, zn-based and Fe-based systems ₂ -C ₁₆ Dehydrogenation of alkanes and/or alkylaromatic hydrocarbons such as ethylbenzene. Among existing propane dehydrogenation processes, certain processes use an alumina-supported chromia catalyst that provides one of the highest propylene yields of about 50% (55% propane conversion at 90% propylene selectivity) obtained at temperatures of about 560 ℃ to 650 ℃ and at low pressures of 20 kPa-absolute to 50 kPa-absolute. It is desirable to increase propylene yield without having to operate at such low pressures to increase the efficiency of the dehydrogenation process.

Increasing the temperature of the dehydrogenation process according to the thermodynamics of the process is one way to increase the conversion of the process. For example, the equilibrium propylene yield was estimated to be about 74% by simulation at 670 ℃, 100 kPa-absolute, in the absence of any inert/diluent. However, at such high temperatures, the catalyst particles deactivate very rapidly and/or the propylene selectivity becomes uneconomically low. The rapid deactivation of the catalyst particles is believed to be caused by coke deposition onto the catalyst particles and/or aggregation of the active phase. Coke can be removed by combustion using an oxygen-containing gas, however, aggregation 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.

Disclosure of Invention

A process for upgrading alkanes and/or alkylaromatic hydrocarbons is provided. In some embodiments, a process for upgrading hydrocarbons 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 include C ₂ -C ₁₆ One or more of linear or branched alkanes, C ₄ -C ₁₆ One or more of the cyclic alkanes, C ₈ -C ₁₆ One or more of the alkylaromatic hydrocarbons, or mixtures thereof. The hydrocarbon-containing feed may be at least 0.1hr ^-1 -1,000hr ^-1 Weight hourly space velocity in the range contacting the catalyst particles based on any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Weight of aromatic hydrocarbons. Fluidized dehydrogenation catalyst particles with any C ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ The weight ratio of the total amount of aromatic hydrocarbons may be in the range of 3 to 100. The hydrocarbon-containing feed and the catalyst particles may be contacted at a temperature in the range 600 ℃ to 750 ℃. The process may further include (II) separating the first particle stream enriched in coked catalyst particles from the conversion effluent anda first gas stream enriched in one or more dehydrogenated hydrocarbons. The method may further include (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 effect combustion of at least a portion of the coke, thereby producing a combustion effluent that may include coke-depleted catalyst particles and combustion gases. The dehydrogenation activity of the coke-depleted catalyst particles can be less than the dehydrogenation activity of the coked catalyst particles. The method may further Include (IV) separating a second particulate stream enriched in catalyst particles depleted in char and a second gas stream enriched in combustion gas from the combustion effluent. The method may further include (V) contacting at least a portion of the coke-depleted catalyst particles in the second particulate stream with an oxidizing gas at an oxidation temperature in the range of 620 ℃ to 1,000 ℃ in an oxygen soak zone for a duration of at least 30 seconds, thereby producing conditioned catalyst particles having an activity that may be less than coked catalyst particles. The method may further include (VI) contacting at least a portion of the conditioned catalyst particles with a reducing gas in a reduction zone, thereby producing regenerated catalyst particles having dehydrogenation activity that may be greater than coked catalyst particles. The process may further include (VII) contacting an additional amount of the hydrocarbon-containing feed with at least a portion of the regenerated catalyst particles in the conversion zone, thereby producing an additional amount of conversion effluent that may include re-coked catalyst particles and an additional amount of one or more dehydrogenated hydrocarbons. The method may further include (VIII) cooling the first gas stream to produce a cooled gas stream. The method can further Include (IX) compressing at least a portion of the cooled gas stream to produce a compressed gas stream. The method may further comprise (X) separating the plurality of products from the compressed gas stream.

Brief description of the drawings

FIG. 1 depicts a system for dehydrogenating a hydrocarbon-containing feed in accordance with one or more described embodiments.

Figure 2 shows that the catalyst composition is stable over 60 cycles for propane dehydrogenation.

Figure 3 shows that the catalyst composition (catalyst 10) maintains its performance for 204 cycles.

Detailed description of the preferred embodiments

Various specific embodiments, variations and examples of the invention will now be described, including preferred embodiments and definitions employed herein for the purpose of understanding the claimed invention. While the following detailed description presents specific preferred embodiments, those skilled in the art will appreciate that these embodiments are exemplary only, and that the invention may be practiced in other ways. For purposes of determining infringement, the scope of the invention will refer to any one or more of the appended claims, including their equivalents, as well as 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 inventions defined by the claims.

In this disclosure, a method is described as comprising at least one "step". It should be understood that each step is an action or operation that may be performed one or more times in a continuous or discontinuous manner in the method. The steps in a method may be performed sequentially as their listed order, with or without overlapping one or more other steps, or in any other order, as appropriate, unless specified to the contrary or the context clearly indicates otherwise. In addition, one or more or even all steps may be performed simultaneously for the same or different batches of material. For example, in a continuous process, while the first step in the process may be performed with respect to the feedstock just fed to the beginning of the process, the second step may be performed simultaneously with respect to intermediate material resulting from the treatment of the feedstock fed to the process at an earlier time in the first step. Preferably, the steps are performed in the order described.

Unless otherwise indicated, all numbers expressing quantities in this disclosure are to be understood as being modified in all instances by the term "about". It should also be understood that the precise numerical values used in the specification and claims constitute specific embodiments. Efforts have been made to ensure accuracy in the data in the examples. However, it should be appreciated that any measured data inherently contains certain levels of error due to limitations of the techniques and/or equipment used to obtain the measurement results.

Certain embodiments and features are described herein using a set of upper numerical limits and a set of lower numerical limits. It will be appreciated that ranges including any two values, such as any lower value in combination with any upper value, any combination of two lower values, and/or any combination of two upper values, are contemplated unless otherwise indicated.

As used herein, the indefinite article "a" or "an" means "at least one" unless specified to the contrary or the context clearly indicates otherwise. Thus, unless specified to the contrary or the context clearly indicates that only one reactor or conversion zone is used, embodiments using "reactors" or "conversion zones" include embodiments using one, two, or more reactors or conversion zones.

The terms "upper" and "lower," upward "and" downward, "" upper "and" lower, "" upwardly "and" downwardly, "upper" and "lower," and other similar terms as used herein, refer to relative positions to one another and are not intended to represent a particular spatial orientation, as the apparatus and method of using the apparatus may be equally effective at various angles or orientations.

The term "hydrocarbon" means (i) any compound consisting of hydrogen and carbon atoms or (ii) any mixture of two or more such compounds in (i). The term "Cn hydrocarbon", where n is a positive integer, means (i) any hydrocarbon compound containing carbon atom(s) in its molecule in total n, or (ii) any mixture of two or more such hydrocarbon compounds in (i). Thus, the C2 hydrocarbon may be ethane, ethylene, acetylene, or a mixture of at least two of these compounds in any ratio. "Cm to Cn hydrocarbons" or "Cm-Cn hydrocarbons", 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 thereof. Thus, a "C2 to C3 hydrocarbon" or "C2-C3 hydrocarbon" may be any of ethane, ethylene, acetylene, propane, propylene, propyne, propadiene, cyclopropane, and any mixture of two or more thereof in any ratio between the components. The "saturated C2-C3 hydrocarbon" may be ethane, propane, cyclopropane, or any mixture of two or more thereof in any ratio. "Cn+ hydrocarbons" means (i) any hydrocarbon compound containing carbon atom(s) in its molecule in a total of at least n, or (ii) any mixture of two or more such hydrocarbon compounds in (i). "Cn-hydrocarbon" means (i) any hydrocarbon compound containing carbon atoms in its molecule in a total number of up to n, or (ii) any mixture of two or more such hydrocarbon compounds in (i). By "Cm hydrocarbon stream" is meant a hydrocarbon stream consisting essentially of Cm hydrocarbon(s). By "Cm-Cn hydrocarbon stream" is meant a hydrocarbon stream consisting essentially of Cm-Cn hydrocarbon(s).

For the purposes of this disclosure, the nomenclature of the elements is according to the version of the periodic table of the elements (according to the new notation) as described in Hawley' sCondensed Chemical Dictionary, 16 th edition, john Wiley & Sons, inc., (2016), appendix V. For example, the group 8 element includes Fe, the group 9 element includes Co, and the group 10 element includes Ni. The term "metalloid" as used herein refers to the following elements: B. si, ge, as, sb, te and At. In the present disclosure, when a given element is indicated as being present, it may be present in elemental state or as any compound thereof, unless otherwise specified or clear from context.

The term "alkane" means a saturated hydrocarbon. The term "cyclic alkane" means a saturated hydrocarbon containing a cyclic carbocyclic ring in the molecular structure. Alkanes may be linear, 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.

The term "enriched" when used in a phrase such as "enriched in X" or "enriched in X" means that the stream comprises a higher concentration of material X than in feed material fed to the same device from which the stream originates, in terms of the output stream obtained from the device (e.g., conversion zone). The term "lean" when used in a phrase such as "lean X" or "lean X" means that the stream contains a lower concentration of material X than the concentration of material X in feed material fed to the same device from which the stream originates, in terms of an output stream obtained from the device such as a conversion zone.

The term "mixed metal oxide" refers to a composition comprising oxygen atoms and at least two different metal atoms mixed on an atomic scale. For example, "mixed Mg/Al metal oxide" has O, mg and Al atoms mixed on an atomic scale and is substantially the same or identical to the composition obtained by calcining Mg/Al hydrotalcite having the general chemical formulaWherein A is a counter anion having a negative charge n, x ranges from > 0 to < e1, and m is ≡0. From nm-sized MgO particles and nm-sized Al mixed together ₂ O ₃ The material of the particle composition is not a mixed metal oxide, since Mg and Al atoms are not mixed on an atomic scale but instead on a nm scale.

The term "selectivity" refers to the productivity (based on moles of carbon) of a given compound in a catalytic reaction. By way of example, the phrase "alkane hydrocarbon conversion reaction has 100% selectivity to alkene" means that 100% of the alkane (on a carbon mole basis) converted in the reaction is converted to alkene. The term "conversion" when used in connection with a given reactant means the amount of reactant consumed in the reaction. For example, when the reactant is specified to be propane, 100% conversion means 100% of the propane is consumed in the reaction. Yield (on a carbon mole basis) is conversion times selectivity.

The term "distribution chamber" means the area of the reactor or separator that facilitates fluid communication between the piping or tubes (duct) carrying the hot product stream from the reactor or separator to the outlet. The reactor or separator may have a plurality of distribution chambers, such as a first distribution chamber and a second distribution chamber, and the term distribution chamber will refer to any of the plurality of distribution chambers unless otherwise indicated.

The term "slurry" means any liquid stream containing fines or solids in an amount of up to 20 wt.% based on the weight of the slurry. The term "sludge" means any liquid stream containing fines or solids in the range of from > 20 wt% to 40 wt%, based on the weight of the slurry. The term "mudcake" means any liquid stream containing fines or solids in an amount of > 40 wt.% based on the weight of the slurry.

Overview of the invention

The hydrocarbon-containing feed may be contacted with fluidized dehydrogenation catalyst particles in any suitable 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 include C ₂ -C ₁₆ One or more of linear or branched alkanes, C ₄ -C ₁₆ One or more of the cyclic alkanes, C ₈ -C ₁₆ One or more of the alkylaromatic hydrocarbons, or mixtures thereof. In some embodiments, the one or more dehydrogenated hydrocarbons may be or include ethylene, propylene, one or more butenes, one or more pentenes, or any mixture thereof. In some embodiments, the conversion effluent may also include benzene.

The hydrocarbon-containing feed may be at least 0.1hr ^-1 -1,000hr ^-1 Weight hourly space velocity in the range contacting the catalyst particles based on any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Weight of aromatic hydrocarbons. Fluidized dehydrogenation catalyst particles with any C ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ The weight ratio of the total amount of aromatic hydrocarbons may be in the range of 3 to 100. The hydrocarbon-containing feed and the catalyst particles may be contacted at a temperature in the range 600 ℃ to 750 ℃.

A first particulate stream enriched in coked catalyst particles and a first gas stream enriched in one or more dehydrogenated hydrocarbons may be separated or otherwise obtained from the conversion effluent. In some embodiments, the first particulate stream and the first gas stream may be separated from the conversion effluent within one or more separation devices or gas/solid separators. In some embodiments, the first particulate stream and the first gas stream may be separated from the conversion effluent via one or more cyclones. In some embodiments, the first particulate stream and the first gas stream may be separated from the conversion effluent in a primary separation device and a secondary separation device (e.g., a primary cyclone and a secondary cyclone) downstream of and in fluid communication with the primary separation device. In some embodiments, the first particulate stream and the first gas stream may be separated from the conversion effluent in a primary separation device.

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 effect combustion of at least a portion of the coke, thereby producing a combustion effluent that may include coke-depleted catalyst particles and combustion gases. In such embodiments, a portion of the heat required to produce coke-depleted catalyst particles is provided by 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 effect combustion of at least a portion of the coke, thereby producing a combustion effluent that may include coke-depleted catalyst particles and combustion gases. In such embodiments, any hydrocarbons present in the combustion zone may be from hydrocarbons entrained from the conversion effluent. In other words, in such embodiments, no supplemental fuel is introduced into the combustion zone. More specifically, a portion of the heat required to produce coke-depleted catalyst particles may be provided by an electric heater or other heating device. In both embodiments using fuel or an electric heater, respectively, the dehydrogenation activity of the coke-depleted catalyst particles may be less than the dehydrogenation activity of coked catalyst particles in order to provide a portion of the heat required to produce the coke-depleted catalyst particles.

A second particulate stream enriched in catalyst particles depleted in char and a second gas stream enriched in combustion gas may be separated from the combustion effluent. In some embodiments, the second particulate stream and the second gas stream may be separated from the combustion effluent within one or more separation devices or gas/solid separators. In some embodiments, the second particulate stream and the second gas stream may be separated from the combustion effluent via one or more cyclones, e.g., one, two, three, four, or more cyclones connected in series. In some embodiments, the second particulate stream and the second gas stream may be separated from the combustion effluent in a primary separation device and a secondary separation device (e.g., a primary cyclone and a secondary cyclone) downstream of and in fluid communication with the primary separation device. In some embodiments, the second particulate stream and the second (first) gas stream may be separated from the combustion effluent in a primary separation device. In some embodiments, the combustion zone may comprise a dense fluidized bed operating in a bubbling regime, a turbulent regime, or a fast fluidization regime. In such embodiments, a second particulate stream enriched in catalyst particles depleted in coke may be withdrawn from the dense bed.

In some embodiments, when fuel is introduced into the combustion zone, at least a portion of the coke-depleted catalyst particles in the second particle stream may be contacted with the oxidizing gas in the oxygen soak zone for a duration or period of time to produce conditioned catalyst particles that may have a dehydrogenation activity that is less than the dehydrogenation activity of coked catalyst particles. In some embodiments, when fuel is introduced into the combustion zone, at least a portion of the coke-depleted catalyst particles in the second particle stream may be contacted with the oxidizing gas in the oxygen soak zone at an oxidation temperature in the range of 620 ℃ to 1,000 ℃ for a duration of at least 30 seconds, thereby producing conditioned catalyst particles. In some embodiments, the coke-depleted catalyst particles in the second particle stream may avoid contact with the oxidizing gas in the oxygen-soak zone when supplemental fuel is not introduced into the combustion zone and heat is provided thereto using an electric heater.

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 dehydrogenation activity greater than coked catalyst particles. In other embodiments, when supplemental fuel is not introduced into the combustion zone and heat is provided thereto using an electric heater, at least a portion of the coke-depleted catalyst particles in the second particulate stream may be contacted with a reducing gas in the reduction zone, thereby producing regenerated catalyst particles having a dehydrogenation activity greater than that of coked catalyst particles. It has been found that the catalyst particles disclosed herein exhibit improved activity and selectivity after undergoing a reduction step prior to re-contacting with an additional amount of a hydrocarbon-containing feed. In addition, the reduced catalyst particles may maintain improved activity and selectivity for 10 minutes or more in the presence of the hydrocarbon-containing feed.

In some embodiments, the first gas stream enriched in dehydrogenated hydrocarbon(s) can be cooled to produce a cooled gas stream. At least a portion of the cooled gas stream can be compressed to produce a compressed gas stream. A variety of products can be separated from the compressed gas stream.

Hydrocarbon dehydrogenation process

The hydrocarbon-containing feed may be contacted with the dehydrogenation catalyst particles in any suitable 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. In some embodiments, the conversion effluent may also include benzene. In some embodiments, the dehydrogenation catalyst particles can include a group 8-10 element disposed on a support. In some embodiments, the hydrocarbon-containing feed and dehydrogenation catalyst particles may be contacted in a conversion zone disposed within a continuous type of process commonly used in fluidized bed reactors. In some embodiments, the conversion zone may be disposed within a riser reactor. In other embodiments, the conversion zone may be disposed within a downgoing reactor. In still other embodiments, the conversion zone may be disposed within a vortex reactor. In other embodiments, the conversion zone may be disposed within the reactor and may allow the fluidized dehydrogenation catalyst particles to form a relatively dense turbulent or fast fluidized bed therein during contact with the hydrocarbon-containing feed. By relatively dense turbulent or fast fluidized bed is meant a fluidized bed that is at an superficial gas velocity that is greater than the transition velocity designated as critical velocity between bubbling and transition of the turbulent bed, but less than the transport velocity of the nominal dehydrogenation catalyst particles, such as the pneumatically transported state in a riser reactor. In other embodiments, the conversion zone may be provided with a dehydrogenation reactor comprising a lower section operating as a fast fluidization or turbulent bed and an upper section operating as a riser, wherein the average catalyst flow and the average gas flow are simultaneously upward. In other embodiments, the conversion zone and the combustion zone may be located within a modified fluid catalytic cracking reactor-regenerator unit. The modified fluid catalytic cracking reactor-regenerator apparatus may have been previously used to perform a fluid catalytic cracking process, which has been modified for use in the dehydrogenation process described herein. For example, an oxygen soak zone and a reduction zone may be incorporated into a fluid catalyst cracking reactor-regenerator to provide a suitable improved fluid catalytic cracker.

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. If two or more reactors are used, the reactors may operate under the same conditions and/or different conditions and may receive the same hydrocarbon-containing feed or different hydrocarbon-containing feeds. If two or more reactors are used, the reactors may be arranged in series, parallel or in combination with each other. In some embodiments, suitable reactors may be or may include, but are not limited to, high gas velocity riser reactors, high gas velocity downflow reactors, vortex reactors, reactors having a relatively dense fluidized catalyst bed at a first end or bottom end and a relatively less dense fluidized catalyst within a riser at a second end or top end, multiple riser reactors and/or downflow reactors operating in series and/or parallel with respect to each other operating under the same or different conditions, or combinations thereof.

In some embodiments, the dehydrogenation catalyst particles can be pneumatically moved through the reaction system, such as via a carrier fluid or transport fluid to the conversion zone, to the combustion zone, to the oxygen soak zone (if such a step is desired), to the reduction zone, transported through a conduit connecting two or more locations, and the like. The carrier fluid may be or include, but is not limited to, a diluent, one or more reactants in gaseous form, i.e., one or more C ₂ -C ₁₆ Alkanes, one or more C ₈ -C ₁₆ An alkylaromatic hydrocarbon, one or more dehydrogenated hydrocarbons, or mixtures 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, steam, and the like. The amount of transport fluid may be sufficient to maintain the dehydrogenation catalyst particles in a fluidized state and to transport the dehydrogenation catalyst particles from one location (e.g., combustion zone) to a second location (e.g., conversion zone). In some embodiments, the weight ratio of dehydrogenation catalyst particles to carrier fluid can range from 5, 10, 15, or 20 to 50, 60, 80, 90, or 100. Injection points of the transport fluid, such as may be injected at multiple points along any one or more transfer lines connecting any two zones or other locations (e.g., combustion zone and reforming zone).

The hydrocarbon-containing feed and dehydrogenation catalyst particles may be contacted at a temperature in the range of from 300 ℃, 350 ℃, 400 ℃, 450 ℃, 500 ℃, 550 ℃, 600 ℃, 620 ℃, 630 ℃, 640 ℃, 650 ℃, 660 ℃, 670 ℃, 680 ℃, 690 ℃, or 700 ℃ to 725 ℃, 750 ℃, 760 ℃, 780 ℃, 800 ℃, 825 ℃, 850 ℃, 875 ℃, or 900 ℃. In some embodiments, the hydrocarbon-containing feed and dehydrogenation catalyst particles can be contacted at a temperature of at least 620 ℃, at least 630 ℃, at least 640 ℃, at least 650 ℃, at least 660 ℃, at least 670 ℃, at least 680 ℃, at least 690 ℃, or at least 700 ℃ to 725 ℃, 750 ℃, 760 ℃, 780 ℃, 800 ℃, 825 ℃, 850 ℃, 875 ℃, or 900 ℃.

In some embodiments, the hydrocarbon-containing feed may be introduced into the conversion zone and contacted with the dehydrogenation catalyst particles therein for a duration or period of time of less than or equal to 5 hours, less than or equal to 4 hours, less than or equal to 3 hours, less than or equal to 1 hour, less than or equal to 0.5 hours, less than or equal to 0.1 hours, less than or equal to 3 minutes, less than or equal to 1 minute, less than or equal to 30 seconds, or less than or equal to 0.1 seconds. In other embodiments, the hydrocarbon-containing feed may be introduced into the conversion zone and contacted with the dehydrogenation catalyst particles therein for a period of 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 can be 7 minutes or less, 6 minutes or less, 5 minutes or less, 4 minutes or less, 3 minutes or less, 2 minutes or less, 1.5 minutes or less, 1 minute or less, 45 seconds or less, 30 seconds or less, 20 seconds or less, 15 seconds or less, 10 seconds or less, 7 seconds or less, 5 seconds or less, 3 seconds or less, 2 seconds or less, or 1 second or less. In some embodiments, the average residence time of the dehydrogenation catalyst particles in the conversion zone can be greater than the average residence time of the gaseous components, such as the hydrocarbon-containing feed and the conversion effluent obtained thereby in the conversion zone.

The hydrocarbon-containing feed and the dehydrogenation catalyst particles can be contacted at a hydrocarbon partial pressure of at least 20 kPa-absolute, where the hydrocarbon partial pressure is any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Total partial pressure of alkylaromatic hydrocarbons. In some embodiments, the hydrocarbon partial pressure during the contacting of the hydrocarbon-containing feed and the dehydrogenation catalyst particles may be in the range from 20 kPa-absolute, 50 kPa-absolute, 100 kPa-absolute, 150kPa, 200kPa, 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, where the hydrocarbon partial pressure is any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Total partial pressure of alkyl aromatic hydrocarbon.

In some embodiments, the hydrocarbon-containing feed may include at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90%, at least 95%, or at least 99% by volume of a single C ₂ -C ₁₆ Alkanes, such as propane, are based on the total volume of the hydrocarbon-containing feed. In some embodiments, the hydrocarbon-containing feed and the dehydrogenation catalyst particles can be in a single C 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 to 300 kPa-absolute, 400 kPa-absolute, 500 kPa-absolute, or 1,000 kPa-absolute ₂ -C ₁₆ Alkane (e.g., propane) is contacted under pressure.

The hydrocarbon-containing feed may be contacted with the dehydrogenation catalyst particles in the conversion zone at any Weight Hourly Space Velocity (WHSV) effective for carrying out the dehydrogenation process. In some embodiments, the WHSV may be 0.1hr ^-1 、0.2hr ^-1 、0.4hr ^-1 、0.8hr ^-1 、2hr ^-1 、4hr ^-1 Or 8hr ^-1 For 16hr ^-1 、32hr ^-1 、64hr ^-1 、100hr ^-1 、250hr ^-1 、500hr ^-1 、750hr ^-1 Or 1,000hr ^-1 . In some embodiments, the dehydrogenation catalyst particles are mixed with any C ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ The ratio of the total amount of alkylaromatic hydrocarbons may 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 weight by weight basis.

In some embodiments, at least a portion of the fluidized dehydrogenation catalyst particles within the conversion zone can be removed, fed to a heat input device that can heat the dehydrogenation catalyst particles, and the heated catalyst particles can be fed to the reforming zone. Since the reaction occurring in the conversion zone is endothermic, it is advantageous to remove a portion of the fluidized dehydrogenation catalyst particles therefrom after some contact with the hydrocarbon-containing feed to further increase the temperature. Heat may be indirectly transferred from any suitable heat transfer medium, provided by an electric heater or any other suitable heater commonly used to indirectly heat catalyst particles. In another embodiment, heat may be applied directly within the conversion zone.

In some embodiments, the hydrocarbon-containing feed may optionally be subjected to one or more pretreatment processes prior to introduction into the conversion zone. In some embodiments, the hydrocarbonaceous feed can be preheated to a temperature of up to +.620 ℃ and introduced into the conversion zone at or near the preheating temperature. In some embodiments, the hydrocarbon-containing feed may be treated to remove at least a portion of any sulfur compounds, at least a portion of any nitrogen compounds, at least a portion of any methane, any C ₂ At least a portion of the hydrocarbons, any C ₄₊ At least a portion of the hydrocarbons, or any combination thereof, to produceA pretreated hydrocarbonaceous feed to the conversion zone can be introduced. 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 pretreated hydrocarbon-containing feed that may be introduced into the conversion zone.

The first particulate stream enriched in coked catalyst particles and depleted in one or more dehydrogenated hydrocarbons and the first gas stream enriched in one or more dehydrogenated hydrocarbons may be separated or otherwise obtained from the conversion effluent via any suitable means. In some embodiments, the first particulate stream and the first gas stream may be obtained from the conversion effluent via one or more solid-gas impingement separators, such as one or more cyclones. In some embodiments, the cyclone separator may be or may include a two-stage or "coupled" configuration, including positive and negative pressure configurations. In some embodiments, suitable cyclones may be included in U.S. patent No. 4,502,947;4,985,136 and 5,248,411. In other embodiments, the first particle stream and the first gas stream may be obtained from the conversion effluent via a "T" shaped conduit that may cause a majority of the coked catalyst particles to flow in one direction and the gaseous component to flow in the other direction via gravity.

In some embodiments, the first gas stream enriched in one or more dehydrogenated hydrocarbons may further comprise entrained coked catalyst particles. In such embodiments, the first particle stream enriched in coked catalyst particles and depleted in one or more dehydrogenated hydrocarbons can comprise > 95%, > 96%, > 97%, > 98%, or > 99%, >99.9%, >99.99% of the dehydrogenation catalyst particles in the conversion effluent. As such, in some embodiments, the first gas stream enriched in one or more dehydrogenated hydrocarbons can include entrained coked catalyst particles in an amount >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.

In some embodiments, at least a portion of the coked catalyst particles in the first particle stream may be contacted with one or more oxidants and optionally one or more hydrocarbon fuels in a combustion zone to effect combustion of at least a portion of the coke and, if present, the fuel, thereby producing a combustion effluent that may include coke-depleted catalyst particles and combustion gases. In other embodiments, at least a portion of the coked catalyst particles in the first particle stream may be contacted with one or more oxidants in the combustion zone without any supplemental fuel to effect combustion of at least a portion of the coke, thereby producing a combustion effluent that may include coke-depleted catalyst particles and combustion gases. In some embodiments, when supplemental fuel is not introduced into the combustion zone, an electric heater or other heating device may be used to provide heat to the combustion zone. When fuel is used, in some embodiments, the combustion zone may include a riser in which the average catalyst flow and average gas flow may be simultaneously upward. In some embodiments, the combustion zone may include a lower section that operates as a fast fluidization, turbulent, or bubbling bed and an upper section that operates as a riser, wherein the average catalyst flow and average gas flow may be simultaneously upward. In some embodiments, the combustion zone may comprise a fast fluidized, turbulent, or bubbling bed, wherein the average catalyst flow may be downward and the average gas flow may be upward. The soak zone may occur in a fast fluidized, turbulent, or bubbling bed reactor, where the average catalyst flow may be downward and the average gas flow may be upward. The separation of the coke-depleted catalyst particles entrained in the upwardly moving combustion gas and the separation of the conditioned catalyst particles entrained in the upwardly moving oxidizing gas can be performed in the same separation unit. The combustion zone may also function as the oxygen soak zone described above when no fuel is used. In some embodiments, the arrangement of the oxygen soak and burn zones relative to each other may be the same or similar to the arrangement of the oxygen soak and burn zones described in U.S. patent nos. 10,647,634 and 10,688,477 and WO 2020/263544.

The oxidizing agent may be or include, but is not limited to, molecular oxygen, ozone, carbon dioxide, steam, or mixtures thereof. In some embodiments, an amount of oxidant that is greater than 100% of the coke on the burned coked catalyst particles may be used to increase the rate of coke removal from the catalyst particles, such that the time required for coke removal may be reduced and result in increased yields of upgraded products produced over a given period of 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.

The coked catalyst particles and oxidant and, if present, fuel may be contacted with each other at a temperature in the range of from 500 ℃, 550 ℃, 600 ℃, 650 ℃, 700 ℃, 750 ℃, or 800 ℃ to 900 ℃, 950 ℃,1,000 ℃,1,050 ℃, or 1,100 ℃ to produce a combustion effluent. In some embodiments, coked catalyst particles and oxidant and, if present, fuel can be contacted with each other at a temperature in the range of 500 ℃ to 1,100 ℃, 600 ℃ to 1,000 ℃, 650 ℃ to 950 ℃, 700 ℃ to 900 ℃, or 750 ℃ to 850 ℃ to produce a combustion effluent. Coked catalyst particles and oxidant and, if present, fuel may be contacted with each other at an oxidant partial pressure in the range of 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 oxidant and, if present, fuel may be contacted with each other for a period of 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, coked catalyst particles and oxidant and (if present) fuel may be contacted with each other for a period of time ranging from 0.5 seconds to 50 minutes, 55 minutes, or 60 minutes. In some embodiments, coked catalyst particles and oxidant and, if present, fuel may be contacted for a period of time greater than or equal to 50 wt.%, greater than or equal to 75 wt.%, or greater than or equal to 90 wt.%, or greater than 99% sufficient to remove any coke disposed on the catalyst particles.

In some embodiments, the period of time that coked catalyst particles and oxidant and (if present) fuel are in contact with each other may be greater than the period of time that catalyst particles are in contact with the hydrocarbon-containing feed to produce a conversion effluent. For example, the period of time that coked catalyst particles and oxidant and (if present) 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 at least 4,140,000% greater than the period of time that catalyst particles are in contact with hydrocarbon-containing feed to produce a conversion effluent.

Without wishing to be bound by theory, it is believed that at least a portion of the metallic elements, such as group 8-10 elements, e.g., pt, disposed on the support in the coked catalyst particles may agglomerate as compared to the catalyst particles prior to contact with the hydrocarbon-containing feed. It is believed that at least a portion of the metallic elements, such as group 8-10 elements, may redisperse around the support during combustion of at least a portion of the coke on the coked catalyst particles. Redispersion of at least a portion of any aggregated metallic elements, such as group 8-10 elements, may increase dehydrogenation activity and improve the stability of the catalyst particles over many cycles.

In some embodiments, at least a portion of the coke-depleted catalyst particles in the second particle stream may be contacted with an oxidizing gas in an oxygen soak zone to produce conditioned catalyst particles. Preferably, the coke-depleted catalyst particles in the second particle stream may be contacted with the oxidizing gas in the oxygen soak zone when fuel is introduced into the combustion zone. When fuel is not introduced into the combustion zone and electrical or other heating means are used to provide heat thereto, the coke-depleted catalyst particles in the second particulate stream may be directly sent to the reduction zone, discussed in more detail below, and as such do not need to be contacted with oxidizing gas. However, it should be understood that when no fuel is introduced into the combustion zone, the coke-depleted catalyst particles in the second particle stream may also be contacted with the oxidizing gas in the oxygen soak zone if desired. It should also be appreciated that when no fuel is introduced into the combustion zone, the combustion zone and the oxygen soak zone may be combined into a single zone for both coke combustion and oxygen soak, and a single oxidizing gas may be used for both coke combustion and oxygen soak. In such embodiments, the terms "coke-depleted catalyst particles" and "conditioned catalyst particles" refer to the same stream of catalyst particles.

In some embodiments, the coke-depleted catalyst particles in the second particulate stream may be contacted with an oxidizing gas at an oxidation temperature ranging from 620 ℃, 650 ℃, 675 ℃, 700 ℃, or 750 ℃ to 800 ℃, 850 ℃, 900 ℃, 950 ℃, or 1,000 ℃ to produce conditioned catalyst particles. In some embodiments, the char-depleted catalyst particles in the second particle stream may be contacted with the oxidizing gas for a duration or period of 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, thereby producing conditioned catalyst particles. The conditioned catalyst particles may have a dehydrogenation activity that is less than the dehydrogenation activity of coked catalyst particles. In some embodiments, the oxidizing gas introduced into the oxygen-immersed region may include 5mol% or less, 3mol% or less, 1mol% or less, 0.5mol% or less, or 0.1mol% or less of H ₂ O. The contact between the oxidizing gas and the coke-depleted catalyst particles in the second particle stream may also be referred to as "dry air soak". It should be understood that the oxidizing gas and any other gas components within the oxygen soak zone include 5mol% or less, 3mol% or less, 1mol% or less, 0.5mol% or less, or 0.1mol% or less of H ₂ O。

It has been surprisingly and unexpectedly found that contacting coke-depleted catalyst particles produced in the presence of an optional fuel with a catalyst comprising no more than 5mol% H ₂ The oxidation gas contact of O may significantly improve the activity and/or selectivity of the regenerated catalyst produced via contact with a reducing gas, discussed in more detail below. Does not takeWithout wishing to be bound by theory, it is believed that H is present in the oxidizing gas or produced as a combustion product ₂ O can significantly reduce the effectiveness of redispersion of group 8-10 elements such as Pt and thus reduce the effectiveness of the regenerated catalyst.

In some embodiments, at least a portion of the coke-depleted catalyst particles in the second particle stream may be contacted with a reducing gas in the reduction zone to produce regenerated catalyst particles when fuel is not introduced into the combustion zone, or at least a portion of the conditioned catalyst particles may be contacted with a reducing gas in the reduction zone when fuel is introduced into the combustion zone. Suitable reducing gases (reducing agents) 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 metallic elements (e.g., group 8-10 elements) in the regenerated catalyst particles can be reduced to a lower oxidation state, such as an elemental state, than the metallic elements (e.g., group 8-10 elements) in the coke-depleted catalyst particles in the second particle stream (when no fuel is introduced to the combustion zone), and than the metallic elements in the conditioned catalyst particles.

In some embodiments, the char-depleted catalyst particles or conditioned catalyst particles and the reducing gas in the second particulate stream may be contacted at a temperature in the range from 400 ℃, 450 ℃, 500 ℃, 550 ℃, 600 ℃, 620 ℃, 650 ℃, or 670 ℃ to 720 ℃, 750 ℃,800 ℃, or 900 ℃. The char-depleted catalyst particles or conditioned catalyst particles in the second particulate stream and the reducing gas may be contacted for a duration or period of time in the range 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-depleted catalyst particles or conditioned catalyst particles in the second particulate stream and the reducing gas may be contacted at a partial pressure of the reducing gas in the range 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.

In some embodiments, a first portion of the coked catalyst particles in a first particle stream rich in coked catalyst particles can be fed to a combustion zone to burn coke disposed thereon, and a second portion of the coked catalyst particles in the first particle stream can be recycled directly back to the conversion zone. In some embodiments, a first portion of the coked catalyst particles in the first particle stream enriched in coked catalyst particles can be fed to a combustion zone to burn coke disposed thereon, and a second portion of the coked catalyst particles can be fed to a reduction zone. In other embodiments, a first portion of the coked catalyst particles in the first particle stream enriched in coked catalyst particles can be fed to the combustion zone to burn coke disposed thereon, a second portion of the coked catalyst particles can be recycled directly back to the conversion zone, and a third portion of the coked catalyst particles can be fed to the reduction zone. In other embodiments, a first portion of the coked catalyst particles in the first particle stream enriched in coked catalyst particles can be fed to the combustion zone to burn coke disposed thereon, a second portion of the coked catalyst particles can be recycled directly back to the conversion zone, a third portion of the coked catalyst particles can be fed to the oxygen soak zone, and a fourth portion of the coked catalyst particles can be fed to the 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 on a continuous basis or on a batch basis, and new or make-up catalyst particles may be introduced to the process. Removal of catalyst particles may occur when catalyst particle size is disrupted, deactivated, and/or hydrocarbon-containing feed conversion begins at an undesirable conversion rate. In some embodiments, at least a portion of any removed catalyst particles may be transferred to a metal recovery apparatus for metal recovery therein.

At least a portion of the coked catalyst particles, at least a portion of the coke-depleted 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, new or make-up catalyst particles, or any mixture thereof, may be contacted with additional amounts of hydrocarbon-containing feed in the conversion zone to produce additional conversion effluent and re-coked 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 catalyst may be 5 hours, 4 hours, 3 hours, 2 hours, 70 minutes, 60 minutes, 45 minutes, or 30 minutes, such as 1 minute to 70 minutes or 5 minutes to 45 minutes.

In some embodiments, one or more additional feeds, such as one or more stripping fluids, may be used to remove at least a portion of any entrained gaseous components from the catalyst particles. In some embodiments, coked catalyst particles can be contacted with a stripping fluid prior to contact with the oxidant to remove at least a portion of any entrained upgraded hydrocarbons and/or molecular hydrogen and/or other gaseous components. Similarly, the char-depleted catalyst particles, conditioned catalyst particles, and/or regenerated catalyst particles in the second particulate stream may be contacted with a stripping gas to remove at least a portion of any entrained combustion, oxidation, or reduction gases therefrom. In some embodiments, the stripping gas may be inactive under 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 mixed with coked, regenerated, and/or regenerated and reduced catalyst particles at about 0.1m ³ To 10m ³ Is contacted with a volume ratio of stripping gas per cubic meter of catalyst particles.

As noted above, the first cycle begins when the catalyst particles are contacted with a hydrocarbon-containing feed, then contacts 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. If any sweep fluid is used, such as to remove residual hydrocarbons from coked catalyst particles, the period of time during which such sweep fluid is used will be included in the cycle time.

In one embodiment, a riser configuration may be implemented wherein the hydrocarbon-containing feed may be mixed with a diluent gas and contacted with heated and fluidized catalyst particles within the riser. The diluent gas may be or include, but is not limited to, molecular nitrogen, methane, steam, molecular hydrogen, or mixtures thereof. The combined gases may convect or otherwise transport the fluidized catalyst particles through the riser while contacting and reacting as the mixture flows through the riser, thereby producing a conversion effluent comprising 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 the desired conversion of the hydrocarbon-containing feed to one or more dehydrogenated hydrocarbons. The specific design, including fabrication and size, of the riser may depend at least in part on the intended chemistry, but generally may require speeds in excess of 4.5m/s at average gas composition.

Systems suitable for conducting dehydrogenation of a hydrocarbon-containing feed may include systems known in the art, such as those described 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 No. 2004/0082824;2008/0194891 and WO publication No. WO2001/85872; the fluidized reactors disclosed in WO2004/029178 and WO 2005/077867.

The first gas stream can be cooled to produce a cooled gas stream. In some embodiments, the first gas stream may be cooled via indirect heat exchange in one or more heat exchangers, by transferring heat from the first gas stream to a heat transfer medium, by direct contact with a quench medium, or a combination thereof. In some embodiments, the first gas stream may be cooled via indirect heat exchange only to produce a cooled gas stream. In other embodiments, the first gas stream may be cooled via direct contact with the quench medium only. In other embodiments, the first gas stream may be cooled via indirect heat exchange and by direct contact with a quench medium in any order or sequence.

In some embodiments, the first gas stream may be cooled indirectly by indirectly transferring heat to any suitable heat transfer medium. Suitable heat transfer media may be or include, but are not limited to, hydrocarbon-containing feeds that produce preheated hydrocarbon-containing feeds that can be introduced into the conversion zone, water, steam, other hydrocarbon streams, or any combination thereof. Any suitable heat exchanger may be used to indirectly transfer heat from the first gas stream to the heat transfer medium.

In some embodiments, the first gas stream may be contacted with a first quench medium to produce a cooled gas stream. For example, when the separation device or gas/solid separator is a cyclone, the first gas stream may be contacted with the first quench medium within a distribution chamber of the cyclone. When multiple cyclones are used in series, the first gas stream can be contacted with the first quench medium at any point between or after the multiple cyclones. In other embodiments, the first gas stream may be contacted in a transfer line in fluid communication with the separation device or the gas/drum separator and the outlet of the quench tower.

In some embodiments, the first quench medium may be in the gas phase, liquid phase, or a mixture of gas and liquid phases when contacted with the first gas stream. In some embodiments, the first quench medium may be in a liquid phase when contacted with the first gas stream and may be in a gas phase entirely after contacting the first gas stream.

In some embodiments, the first gas stream may be at a temperature of ∈600 ℃, > 620 ℃, > 630 ℃, > 640 ℃, > 650 ℃, > 660 ℃, > 670 ℃, > 680 ℃, or > 700 ℃ when initially contacted with the first quench medium and/or when introduced into a heat exchanger to indirectly transfer heat to the heat transfer medium. In some embodiments, the cooled gas stream may be at a temperature at least 10 ℃, at least 20 ℃, at least 30 ℃, at least 60 ℃, 80 ℃, or at least 100 ℃ lower than the temperature of the first gas stream prior to contact with the first quench medium or prior to introduction into the heat exchanger. In some embodiments, the cooled gas stream may be at a temperature in the range from 500 ℃, 515 ℃, 530 ℃, 550 ℃, or 560 ℃ to 575 ℃, 590 ℃, 600 ℃, 610 ℃, or 620 ℃. In some embodiments, the cooled gas stream may be at a temperature of ≡500 ℃ or ≡550 ℃ to < 620 ℃.

In some embodiments, the cooled gas stream may be contacted with a second quench medium disposed in a contact zone within the quench tower. In some embodiments, the second quench medium may be countercurrently contacted with the cooled gas stream within the quench tower. For example, the cooled gas stream may be introduced into the quench tower below the second quench medium and flow upwardly within the quench tower, and the second quench medium may flow downwardly within the quench tower. In some embodiments, the second quench medium may be introduced into the quench tower via one or more nozzles.

As noted above, in some embodiments, the first gas stream can include coked catalyst particles entrained therein. In such embodiments, a third gas stream comprising one or more dehydrogenated hydrocarbons substantially free of or free of entrained coked catalyst particles can be recovered from the quench tower as a top product, and a slurry stream that can comprise at least a portion of the second quench medium and entrained coked catalyst particles can be recovered from the quench tower as a bottom product. In some embodiments, if the second quench medium remains a liquid, entrained coked catalyst particles may interact more strongly with the liquid, and thus entrained coked catalyst particles may be entrained in the second quench medium. In some embodiments, the third gas stream that is substantially free of entrained coked catalyst particles may include < 10 wt%, < 5 wt%, < 3 wt%, < 1 wt%, < 0.5 wt%, < 0.1 wt%, < 0.01 wt%, or < 0.001 wt% of any entrained coked catalyst particles. In some embodiments, the gas stream may be at a temperature in the range from 50 ℃, 100 ℃, or 150 ℃ to 200 ℃, 250 ℃, or 300 ℃.

When the first gas stream is in direct contact with the first quench medium, the condensed first quench medium stream can be recovered as a side draw from the quench tower and at least a portion of the condensed first quench medium can be recycled to contact an additional amount of the first gas stream. In some embodiments, the condensed first quench medium recovered from the quench tower may be at a temperature in the range of from 50 ℃, 60 ℃, or 70 ℃ to 80 ℃, 100 ℃, or 120 ℃.

When the first gas stream includes entrained catalyst particles, a slurry stream, which may include at least a portion of the second quench medium and entrained coked catalyst particles, may be recovered from the quench tower as a bottoms stream. In some embodiments, the bottom region of the quench tower may contain a stock of slurry stream such that the slurry stream recovered from the quench tower may be withdrawn from the stock. The slurry stream when recovered from the quench tower may be at a temperature in the range of from 150 ℃, 200 ℃, or 250 ℃ to 300 ℃, 400 ℃, or 500 ℃.

In some embodiments, the quench tower may include one or more internal structures that may facilitate separation of the cooled gas stream into a third gas stream, a first quench medium stream (when used), and a slurry stream. Illustrative internals may include, but are not limited to, trays, grids, packing, or any combination thereof. Illustrative trays may include, but are not limited to, fixed valve trays, jet tab trays (jet tray), sieve trays, dual stream trays, baffle trays, angle iron trays, extraction trays, deck trays (shed tray), disk trays, ring trays, side-by-side splash trays, or any combination thereof. Suitable fixed valve trays, screen trays, dual flow trays and grids may include those disclosed in Distillation Design, henry Z.Kister, mcGraw-Hill inc.,1992, pages 262-265 and pages 464-466. Suitable jet baffle trays may include those disclosed in WO publication No. WO 2011/014345.

In some embodiments, if the process conditions within the quench tower are such that entrained coked catalyst particles can remain in the third gas stream recovered from the quench tower as a overhead, the third gas stream can be subjected to further processing. In some embodiments, if the third gas stream recovered from the quench tower as a top comprises 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 scavenger, one or more additional quench towers, one or more cyclones, 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 therefrom.

In some embodiments, if the hydrocarbon-containing feed includes water and/or water is produced during the dehydrogenation reaction such that the conversion effluent contains water, a water stream may be recovered from the quench tower as a second side draw. In such embodiments, the water stream may be removed from the process, a portion of the water stream may be recycled to the upper section of the quench tower, thereby further promoting separation of entrained coked catalyst fines, the first quench medium, and the second quench medium from (with) the cooled gas stream within the quench tower, or a combination thereof. In some embodiments, at least a portion of the water stream may also be vaporized and recycled to the inlet of the conversion zone as a co-feed to the hydrocarbon-containing feed.

The first quench medium and the second quench medium may be, or may include, independently, but are not limited to, one or more aromatic hydrocarbons, water, or mixtures thereof. In some embodiments, the aromatic hydrocarbon may be or may include benzene, one or more monosubstituted benzenes, one or more disubstituted benzenes, one or more polysubstituted benzenes, and/or one or more polycyclic aromatic hydrocarbons having a normal boiling point of < 580 ℃. In some embodiments, the polycyclic aromatic hydrocarbon may have a normal boiling point of < 580 ℃, < 550 ℃, < 500 ℃, < 400 ℃, < 300 ℃, <200 ℃, or < 100 ℃. Suitable aromatic hydrocarbons may be or include, but are not limited to, benzene, toluene, cumene, ethylbenzene, xylene, methylethylbenzene, trimethylbenzene, methylnaphthalene, A-100 solvent mixtures, A-150 solvent mixtures, A-200 solvent mixtures, A-250 solvent mixtures, middle distillates, ultra low sulfur diesel, heavy gas oils, or any mixtures thereof.

In some embodiments, the second quench medium may have a 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, an A-100 solvent mixture, an A-150 solvent mixture, an A-200 solvent mixture, an A-250 solvent mixture, a middle distillate, ultra low sulfur diesel, heavy gas oil, or any mixture thereof.

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 of the same components and one or more different components such that a portion of the composition of the first and second quench media is the same and a portion of the composition of the first and second quench media is different. In some embodiments, the second quench medium can have a normal boiling point that is greater than the normal boiling point of the first quench medium. In some embodiments, the second quench medium can have a normal boiling point that is lower than the normal boiling point of the first quench medium. In some embodiments, the first quench medium may be or may 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 weight ratio of the first quench medium to the first gas stream can range from 0.01, 0.05, or 0.08 to 0.1, 0.2, or 0.3. In some embodiments, the weight ratio of the second quench medium to the cooled gas stream can range from 0.01, 0.1, or 0.3 to 0.5, 1, 2, or 5. In some embodiments, the weight ratio of the first quench medium to the second quench medium can range from 0.002, 0.02, or 0.2 to 1, 5, or 10.

When the first gas stream includes entrained coked catalyst particles, at least a portion of the entrained coked catalyst particles can be separated from the slurry, thereby providing a recovered second quench medium depleted of or without any entrained coked catalyst particles and a recovered entrained coked catalyst particle stream. In some embodiments, at least a portion of the recovered second quench medium can be recycled to the quench tower to contact an additional amount of the first cooled gas stream therein.

In some embodiments, entrained coked catalyst particles can be separated from the slurry via 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 such that 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 back flush mode, thereby removing collected coked catalyst particles. The filtration and backwash modes may alternate periodically. In some embodiments, when two or more filters are used to separate entrained coked catalyst particles from the slurry, the backwash mode may include at least one pulse of compressed gas passing through at least one filter in the backwash mode in a countercurrent direction, thereby removing separated coked catalyst particles. In some embodiments, the combustion or flue gas removed from the combustion zone may be used as a gas for backwashing the filter. In some embodiments, the liquid stream may be used to backwash a filter. In some embodiments, suitable methods of recovering entrained coked catalyst particles from a slurry can include the methods disclosed in U.S. patent No. 7,375,143.

In some embodiments, at least a portion of the cooled first gas stream (e.g., a third gas stream) that can be recovered from the quench tower can be compressed to produce a compressed gas stream. At least a portion of the cooled first gas stream (foam) may be compressed in one or more compressors or compression stages to produce a compressed gas stream. A variety of products can be separated from the compressed gas stream. The compressed gas stream can be introduced into a product recovery zone or apparatus from which a plurality of products can be separated. The product recovery device may be or include, but is not limited to, any one or more of the following: distillation column, membrane separation, adsorption bed, low temperature separation.

In some embodiments, the compressed gas stream may be separated into a light gas stream, a feed stream containing unreacted hydrocarbons, a dehydrogenated hydrocarbon stream, and a liquid stream within 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 feed containing unreacted hydrocarbons, 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 such as polyethylene, polypropylene, or other polymers. The liquid stream, or at least a portion thereof, may be used as the first quench medium, the second quench medium, or a combination thereof. In some embodiments, the recovered olefin, such as propylene, may be used to produce a polymer, e.g., the recovered propylene may be polymerized to produce a polymer having segments or units derived from the recovered propylene, e.g., polypropylene, ethylene-propylene copolymers, and the like. Recovered isobutene may be used, for example, for the production of one or more of the following: oxygenates such as methyl tertiary butyl ether, fuel additives such as diisobutylene, synthetic elastomeric polymers such as butyl rubber, and the like. In some embodiments, recovered olefins such as propylene, isobutylene may be sent to an alkylation unit.

In some embodiments, the process recovery unit may also receive a fourth gas stream, which may be recovered as an overhead product from a primary fractionator that receives a steam cracker effluent produced in a steam cracker and separates various products therefrom. For example, the primary fractionator may separate the steam cracker effluent into tar products, steam cracker quench oil products, steam cracker gas oil products, steam cracker naphtha products, and steam cracker gas overhead products, which may include hydrogen, methane, ethane, ethylene, propane, propylene, butenes, butanes, pentanes, and other gas products.

In some embodiments, the fourth gas stream may already be compressed. In other embodiments, the fourth gas stream can be combined with the third gas stream and the combined gas stream can be compressed to produce a combined third and fourth compressed gas stream, which can be introduced into the product recovery zone.

In some embodiments, at least a portion of the coked catalyst particles in the recovered entrained coked catalyst particle stream can be transferred to a metal recovery unit. In such embodiments, at least a portion of the metallic element, e.g., group 8-10 element(s), may be recovered from coked catalyst particles in the recovered entrained catalyst particle stream. In some embodiments, at least a portion of the coked catalyst particles transferred to the metal recovery unit may be performed in the form of sludge or cake. In some embodiments, the liquid in the sludge or mudcake may comprise a portion of the second quench medium. In other embodiments, entrained coked catalyst particles can be substantially separated from the second quench medium and conveyed in the form of fluidized particles. In still other embodiments, entrained coked catalyst particles can be substantially separated from the second quench medium and mixed with another liquid medium, forming another slurry, sludge, or cake that can be transferred to a metal recovery plant. The recovered group 8-10 element(s) may be reused to prepare new catalyst particles, purified and sold, for example, as a commodity, or for any other desired purpose.

In some embodiments, the electricity used in the combustion zone may be from renewable resources such as solar energy, wind energy, geothermal, hydroelectric, and the like. In some embodiments, pure O may be used in the combustion zone ₂ So that CO generated during combustion can be promoted ₂ Is provided. In some embodiments, the feed may be a feed comprising C ₃ And C ₄ Liquefied petroleum gas of both paraffinic molecules. In some embodiments, the feed may be one or more components of liquefied natural gas (often referred to as NGL). In some embodiments, the feed may be from a renewable source such as biomass fermentation or conversion.

In some embodiments, at least a portion of the group 8-10 element(s) may be recovered from the coked catalyst particles via any suitable method or combination of methods. Suitable methods for recovering at least a portion of the group 8-10 element(s) may include, but are not limited to, U.S. patent 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. CN104831071 a.

Dehydrogenation catalyst particles

The dehydrogenation catalyst particles can 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%, 0.05 wt%, 0.055 wt%, 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 disposed on the support, e.g., based on the support. In some embodiments, the catalyst particles may include 5.5 wt.% or less, 4.5 wt.% or less, 3.5 wt.% or less, 2.5 wt.% or less, 1.5 wt.% or less, 1 wt.% or less, 0.9 wt.% or less, 0.8 wt.% or less, 0.7 wt.% or less, 0.6 wt.% or less, 0.5 wt.% or less, 0.4 wt.% or less, 0.3 wt.% or less, 0.2 wt.% or less, 0.15 wt.% or less, 0.1 wt.% or less, 0.09 wt.% or less, 0.08 wt.% or less, 0.07 wt.% or less, 0.06 wt.% or less, 0.05 wt.% or less, 0.04 wt.% or less, 0.03 wt.% or less, 0.02 wt.% or less, 0.01 wt.% or less, 0.009 wt.%, or less, 0.008 wt.% or less, 0.006 wt.% or less, 0.003 wt.% or less, 0.002 wt.% of a group of the carrier, or no, 0.002 wt.% or less, based on the carrier. In some embodiments, the catalyst particles may include >0.001, >0.003, >0.005, >0.007, >0.009, >0.01, >0.02, >0.04, >0.06, >0.08, >0.1, >0.13, >0.15, >0.17, >0.2, >0.23, >0.25, >0.27, > or >0.3 and <0.5, <1, <2, <3, <4, <5, <6,% by weight of the group 8-10 elements disposed on the support, based on the support. In some embodiments, the group 8-10 element may be or include, but is not limited to Fe, co, ni, ru, pd, os, ir, pt, combinations thereof, or mixtures thereof. In at least one embodiment, the group 8-10 element may be or may include Pt.

In some embodiments, the catalyst particles may optionally include two or more group 8-10 elements, such as Pt and Ni and/or Pd. If two or more group 8-10 elements are disposed on the 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%, 0.05 wt%, 0.055 wt%, 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 the total group 8-10 elements disposed on the support. In some embodiments, the active component of the catalyst particles that may be capable of effecting dehydrogenation of the hydrocarbon feed may include a group 8-10 element(s).

In some embodiments, the catalyst particles may optionally include a promoter disposed on the support in an amount of up to 10 wt%, based on the weight of the support. The accelerator (if present) may be or include, but is not limited to Sn, ga, zn, ge, in, re, ag, au, cu, combinations thereof or mixtures thereof. In at least one embodiment, the promoter may be or may include Sn. In some embodiments, promoters may be associated with group 8-10 elements. For example, the promoter and Pt disposed on the support may form Pt-promoter clusters that are dispersible on the support. The promoters may improve the selectivity/activity/lifetime of the catalyst particles for a given upgraded hydrocarbon. In some embodiments, the promoter may improve propylene selectivity of the catalyst particles when the hydrocarbon-containing feed comprises propane. The catalyst particles may include an accelerator in an amount of 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.

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 element, if present, may be or include, but is not limited to Li, na, K, rb, cs, combinations thereof, or mixtures thereof. In at least one embodiment, the alkali metal element may be or may include K and/or Cs. In at least some embodiments, the alkali metal element may be or may include K and/or Cs. In some embodiments, the alkali metal element (if present) may improve the selectivity of the catalyst particles for a given upgraded hydrocarbon. The catalyst particles may include an alkali metal element in an amount of 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.

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, halite, sulfate, sulfide, borate, nitride, carbide, aluminate, aluminosilicate, silicate, carbonate, metaphosphate, selenide, tungstate, molybdate, chromite, chromate, dichromate, or silicide. In some embodiments, a mixture of any two or more compounds comprising a group 2 element may exist in different forms. For example, the first compound may be an oxide and the second compound may be an aluminate, wherein the first compound and the second compound include the same or different group 2 elements relative to each other.

The carrier may include 0.5 wt% or more, 1 wt% or more, 2 wt% or more, 3 wt% or more, 4 wt% or more, 5 wt% or more, 6 wt% or more, 7 wt% or more, 8 wt% or more, 9 wt% or more, 10 wt% or more, 11 wt% or more, 12 wt% or more, 13 wt% or more, 14 wt% or more, 15 wt% or more, 16 wt% or more, 17 wt% or more, 18 wt% or more, 19 wt% or more, 20 wt% or more, 21 wt% or more, 22 wt% or more, 23 wt% or more, 24 wt% or more, 25 wt% or more, 26 wt% or more, 27 wt% or more, 28 wt% or more, 29 wt% or more, 30 wt% or more, 35 wt% or more, 40 wt% or more, 45 wt% or more, 50 wt% or more, 55 wt% or more, 60 wt% or more, 85 wt% or more, or 75 wt% or more, of the carrier. In some embodiments, the carrier may include a group 2 element in a range from 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 carrier. In some embodiments, the molar ratio of group 2 element to group 8-10 element(s) present may range from 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, 15,000, 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, 500,500,000, 500,000, 600,000, 700,000, or 900,000.

In some embodiments, the support may include a group 2 element and Al and may be in the form of a mixed group 2 element/Al metal oxide having O, mg and Al atoms mixed on an atomic scale. In some embodiments, the support may be or may include a group 2 element and Al in an oxide or one or more oxides of a group 2 element and Al that may be mixed on the nm scale ₂ O ₃ In the form of (a). In some embodiments, the support may be or may include oxides of group 2 elements such as MgO and Al mixed on the nm scale ₂ O ₃ 。

In some embodiments, the support may be or may include a first amount of a group 2 element and Al in the form of a mixed group 2 element/Al metal oxide and a second amount of a group 2 element in the form of an oxide of the group 2 element. In such embodiments, the mixed group 2 element/Al metal oxide and the oxide of the group 2 element may be mixed on the nm scale and the group 2 element and Al in the mixed group 2 element/Al metal oxide may be mixed on the atomic scale.

In other embodiments, the support may be or may include a first amount of a 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 a group 2 element in the form of an oxide of a group 2 element, and an amount of Al in the form of an oxide of a group 2 element ₂ O ₃ A second amount of Al in form. In such embodiments, the mixed group 2 element/Al metal oxide, group 2 element oxide and Al ₂ O ₃ The group 2 element and Al in the group 2 element/Al metal oxide which can be mixed on the nm scale and mixed can be mixed on the atomic scale。

In some embodiments, when the support includes a group 2 element and Al, the weight ratio of the 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 of _w Al ₂ O _3+w Wherein w is a positive number; ca (Ca) _x Al ₂ O _3+x Wherein x is a positive number; sr (Sr) _y Al ₂ O _3+y Wherein y is a positive number; ba (Ba) _z Al ₂ O _3+z Wherein z is a positive number; beO; mgO; caO; baO; srO; beCO ₃ ；MgCO ₃ ；CaCO ₃ ；SrCO ₃ 、BaCO ₃ ；CaZrO ₃ ；Ca ₇ ZrAl ₆ O ₁₈ ；CaTiO ₃ ；Ca ₇ Al ₆ O ₁₈ ；Ca ₇ HfAl ₆ O ₁₈ ；BaCeO ₃ The method comprises the steps of carrying out a first treatment on the surface of the 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 may include Mg and at least a portion of the group 2 element may be in the form of MgO or a mixed oxide including MgO. In some embodiments, the support may be or may include, but is not limited to, mgO-Al ₂ O ₃ Mixed metal oxides. In some embodiments, when the support is MgO-Al ₂ O ₃ When mixed metal oxides, the support may have a molecular weight equal to 20, 10, 5, 2, 1 to 0.5, 0.1Or 0.01 Mg to Al molar ratio.

Mg _w Al ₂ O _3+w Where w is a positive number, may have a molar ratio of Mg to Al in the range from 0.5, 1, 2, 3, 4 or 5 to 6, 7, 8, 9 or 10 if present as support or as a component of a support. In some embodiments, mg _w Al ₂ O _3+w May include MgAl ₂ O ₄ 、Mg ₂ Al ₂ O ₅ Or mixtures thereof. Ca (Ca) _x Al ₂ O _3+x Where x is a positive number, if present as a carrier or as a component of a carrier, may have a molar ratio of Ca to Al in the range from 1:12, 1:4, 1:2, 2:3, 5:6, 1:1, 12:14, or 1.5:1. In some embodiments, ca _x Al ₂ O _3+x May include tricalcium aluminate, dodecacalcium heptaluminate, monocalcium aluminate, monocalcium dialuminate, monocalcium hexaaluminate, dicalcium aluminate, pentacalcium trialuminate, tetracalcium trialuminate, or any mixtures thereof. Sr (Sr) _y Al ₂ O _3+y Where y is a positive number, and if present as a support or as a component of a support, may have a mole ratio of Sr to Al in the range from 0.05, 0.3 or 0.6 to 0.9, 1.5 or 3. Ba (Ba) _z Al ₂ O _3+z Where z is a positive number, it may have a molar ratio of Ba to Al of 0.05, 0.3 or 0.6 to 0.9, 1.5 or 3, if present as support or as a component of a support.

In some embodiments, the carrier may further include, but is not limited to, at least one metal element and/or at least one metalloid element and/or at least one compound thereof selected from groups other than groups 2 and 10, 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. If the support further comprises a compound comprising a metal element and/or metalloid element selected from groups other than groups 2 and 10, wherein 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 compound may be present in the support as an oxide, phosphate, halide, sulfate, sulfide, borate, nitride, carbide, aluminate, aluminosilicate, silicate, carbonate, metaphosphate, selenide, tungstate, molybdate, chromite, chromate, dichromate or silicide. In some embodiments, at least one metallic element and/or at least one metalloid element and/or at least one compound thereof selected from groups other than groups 2 and 10 (wherein the at least one metallic element and/or the at least one metalloid element is not Li, na, K, rb, cs, sn, cu, au, ag or Ga) may be or may include, but are not limited to, one or more rare earth elements, i.e., elements having atomic numbers 21, 39, or 57 to 71.

If the support comprises at least one metallic element and/or at least one metalloid element and/or at least one compound thereof selected from groups other than groups 2 and 10, 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, then in some embodiments the at least one metallic element and/or at least one metalloid element may act as a binder and may be referred to as a "binder". Whether or not at least one metal element and/or at least one metalloid element selected from the 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, the at least one metal element and/or at least one metalloid element selected from the groups other than groups 2 and 10 will be further described herein as a "binder" for clarity and convenience of description. It is known in the literature that some of the compounds referred to herein as "binders" may also be referred to as fillers, matrices, additives, and the like. In some embodiments, the carrier may include an adhesive in a range 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%, based on the weight of the carrier.

In some embodiments, suitable compounds including binders may be or may include, but are not limited to, toOne or more of the following: b (B) ₂ O ₃ 、AlBO ₃ 、Al ₂ O ₃ 、SiO ₂ 、ZrO ₂ 、TiO ₂ 、SiC、Si ₃ N ₄ Aluminum silicate, zinc aluminate, znO, VO, V ₂ O ₃ 、VO ₂ 、V ₂ O ₅ 、Ga _s O _t 、In _u O _v 、Mn ₂ O ₃ 、Mn ₃ O ₄ MnO, one or more molybdenum oxides, one or more tungsten oxides, one or more zeolites, where s, t, u, and v are positive numbers, and mixtures and combinations thereof.

The catalyst particles may have a median particle size in the range 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 particle size of from 0.3g/cm 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 To 1.1g/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 2g/cm ³ Apparent bulk density within the range, as measured according to modified ASTM D7481-18, modified by replacing a 100 or 250mL graduated cylinder with a 10, 25 or 50mL graduated cylinder. In some embodiments, the catalyst particles may have a one hour after wear loss of +.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% as measured according to ASTM D5757-11 (2017). The morphology of the particles is largely spherical, making them suitable for operation in a fluidized bed reactor. In some embodiments, the catalyst particles may have a size and density that meets the definition of Geldart a or Geldart B for fluidizable solids.

In some embodiments, the catalyst particles may have a particle size of from 0.1m 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 Surface area in the range of/g. The surface area of the catalyst particles can be measured according to the Brunauer-Emmett-Teller (BET) method using nitrogen adsorption-desorption (temperature of liquid nitrogen, 77K), after degassing the powder for 4 hours at 350℃using Micromeritics 3flex instrument. Further information about this approach can be found, for example, in "Characterization of Porous Solids and Powders:surface Area, pore Size and Density", S.Lowell et al Springer,2004.

The preparation of the support may be accomplished by any known method. For brevity and convenience of description, preparation of mixed oxide (Mg (Al) O or MgO/Al) including magnesium and aluminum will be described in more detail ₂ O ₃ ) Suitable carriers for the carrier. Catalyst synthesis techniques are well known and the following description is for illustrative purposes and is not to be taken as limiting the synthesis of the support or catalyst particles. In some embodiments, to make MgO/Al ₂ O ₃ Mixed oxide supports, mg and Al precursors such as Mg (NO ₃ ) ₂ And Al (NO) ₃ ) ₃ Mixed together, e.g., ball milled, and then calcined to produce the support. In another embodiment, both precursors may be dissolved in H ₂ In O, stirring until dry (with optional application of heat), followed by calcination to yield the support. In another embodiment, both precursors may be dissolved in H ₂ In O, alkali and carbonate such as NaOH/Na are added later ₂ CO ₃ To produce hydrotalcite, followed by calcination to produce the support. In another embodiment, commercially available MgO and Al may be mixed and ball milled ₂ O ₃ . In another embodiment, mg (NO ₃ ) ₂ The precursor is dissolved in H ₂ O, and impregnating the solution into an existing support such as Al ₂ O ₃ On the support, it may be dried and calcined to produce the support. In another embodiment, the ion adsorption may be used to adsorb ions from Mg (NO ₃ ) ₂ Mg loading to existing Al ₂ O ₃ On a carrier, followed by liquid-solid separation and dryingAnd calcining to produce the support. Without wishing to be bound by theory, it is believed that the support produced via any 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).

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, tetraamineplatinum nitrate and/or tetraamineplatinum hydroxide, one or more promoter precursors (if used) such as salts such as SnCl ₄ And/or AgNO ₃ And one or more alkali metal element precursors (if used) such as KNO ₃ KCl and/or NaCl, soluble in water. The solution may be impregnated onto a support, followed by drying and calcination. In some embodiments, the group 8-10 element precursor and optional 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 calcining step. In other embodiments, the group 8-10 element and optional promoters and/or alkali metal elements may be loaded onto the support by chemical vapor deposition, wherein the precursor is vaporized and deposited onto the support, followed by calcination. In other embodiments, the group 8-10 element precursor and optional promoter precursor and/or alkali metal precursor may be loaded onto the support by ion adsorption, followed by liquid-solid separation, drying and calcination. Optionally, the catalyst particles may also be synthesized using a one-pot synthesis process wherein the precursor of the support, the group 8-10 metal active phase and the promoter are all wet or dry mixed together, with or without any other additives to aid synthesis, followed by drying and calcination.

In some embodiments, the catalyst particles may be formulated into Geldart type a or B particles by known spray drying methods. Spray dried catalyst particles having an average cross-sectional area in the range from 20 μm, 40 μm or 50 μm to 80 μm, 90 μm or 100 μm are typically used in FCC fluid bed reactors. To prepare the spray-dried catalyst particles, the support, group 8-10 element, and any additional components such as promoters and/or alkali metals may be slurried prior to spray-drying and calcining, with the binder/additive being included in the slurry. Alternatively, the group 8-10 element and any additional components, such as promoters and/or alkali metals, may be added to the formulated support to produce formulated catalyst particles.

Suitable methods that can be used to prepare the catalyst particles disclosed herein can include those described in U.S. patent No. 4,788,371;4,962,265;5,922,925;8,653,317; EP patent No. EP0098622; journal of Catalysis 94 (1985), pages 547-557; and/or Applied Catalysis 54 (1989), pages 79-90.

Hydrocarbon-containing feed

C ₂ -C ₁₆ The 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-dimethylbutane, n-heptane, 2-methylhexane, 2, 3-trimethylbutane, cyclopentane, cyclohexane, methylcyclopentane, ethylcyclopentane, n-propylcyclopentane, 1, 3-dimethylcyclohexane, or mixtures thereof. For example, the hydrocarbon-containing feed may include propane that may be dehydrogenated to produce propylene, and/or isobutane that may be dehydrogenated to produce isobutylene. In another example, the hydrocarbon-containing feed may include liquefied petroleum gas (LP gas), which may be in the gas phase when contacted with the catalyst particles. In some embodiments, the hydrocarbons in the hydrocarbon-containing feed may consist essentially of a single alkane, such as propane. In some embodiments, the hydrocarbonaceous feed can include greater than or equal to 50 mole percent, greater than or equal to 75 mole percent, greater than or equal to 95 mole percent, greater than or equal to 98 mole percent, or greater than or equal to 99 mole percent of a single C ₂ -C ₁₆ Alkanes, such as propane, are based on the total weight of all hydrocarbons in the hydrocarbon-containing feed. In some embodiments, the hydrocarbon-containing feed may include at least 50%, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90%, at least 95%, at least 97%, or at least 99% by volume of a single C ₂ -C ₁₆ Alkanes, such as propane, are based on the total volume of the hydrocarbon-containing feed.

C ₈ -C ₁₆ The alkylaromatic hydrocarbon may be or include, but is not limited to, ethylbenzene, propylbenzene, butylbenzene, one or more ethyltoluene, or mixtures thereof. In some embodiments, the hydrocarbonaceous feed can include greater than or equal to 50 mole percent, greater than or equal to 75 mole percent, greater than or equal to 95 mole percent, greater than or equal to 98 mole percent, or greater than or equal to 99 mole percent of a single C ₈ -C ₁₆ Alkylaromatic hydrocarbons such as ethylbenzene are based on the total weight of all hydrocarbons in the hydrocarbon-containing feed. In some embodiments, ethylbenzene may be dehydrogenated to produce styrene. As such, in some embodiments, the methods disclosed herein can include propane dehydrogenation, butane dehydrogenation, isobutane dehydrogenation, pentane dehydrocyclization to cyclopentadiene, naphtha reforming, ethylbenzene dehydrogenation, ethyltoluene dehydrogenation, and the like.

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. If the hydrocarbonaceous feed includes a diluent, the hydrocarbonaceous feed can include 0.1, 0.5, 1, or 2 to 3, 8, 16, or 32% by volume of diluent, based on any C in the hydrocarbonaceous feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Total volume of alkylaromatic hydrocarbons. When the diluent includes molecular hydrogen, molecular hydrogen and any C ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ The molar ratio of the total amount of alkylaromatic hydrocarbons may be in the 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, if a diluent is used, the diluent may be mixed with the hydrocarbon-containing feed and/or introduced as a separate feed or otherwise fed into the conversion zone via one or more inlets dedicated to feeding the diluent into the conversion zone. Similarly, the hydrocarbonaceous feed can also be introduced into the conversion zone via one or more inlets dedicated to feeding hydrocarbonaceous feed into the conversion zone.

In some embodiments, the hydrocarbon-containing feed may be substantially free of any water or steam, e.g<0.1% by volumeWater or steam, based on any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Total volume of alkylaromatic hydrocarbons. In other embodiments, the hydrocarbon-containing feed may include steam. For example, the hydrocarbon-containing feed may include 0.1, 0.3, 0.5, 0.7, 1, 3, or 5 to 10, 15, 20, 25, 30, 35, 40, 45, or 50% water or steam by volume, based on any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Total volume of alkylaromatic hydrocarbons. In other embodiments, the hydrocarbonaceous feed can include 50 vol.% or less, 45 vol.% or less, 40 vol.% or less, 35 vol.% or less, 30 vol.% or less, 25 vol.% or less, 20 vol.% or 15 vol.% water or steam, based on any C in the hydrocarbonaceous feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Total volume of alkylaromatic hydrocarbons. In other embodiments, the hydrocarbon-containing feed may include at least 1 volume%, at least 3 volume%, at least 5 volume%, at least 10 volume%, at least 15 volume%, at least 20 volume%, at least 25 volume%, or at least 30 volume% water or steam, based on any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Total volume of alkylaromatic hydrocarbons. Like the diluent, if water or steam is fed into the conversion zone, the water or steam may be fed into the conversion zone as a component of the hydrocarbon-containing feed or through one or more separate inlets dedicated to the introduction of steam into the conversion zone.

In some embodiments, the hydrocarbon-containing feed may include sulfur. For example, the hydrocarbon-containing feed may include sulfur in the range from 0.5ppm, 1ppm, 5ppm, 10ppm, 20ppm 30ppm, 40ppm, 50ppm, 60ppm, 70ppm, or 80ppm to 100ppm, 150ppm, 200ppm, 300ppm, 400ppm, or 500 ppm. In other embodiments, the hydrocarbon-containing feed may include sulfur in the range of 1ppm to 10ppm, 10ppm to 20ppm, 20ppm to 50ppm, 50ppm to 100ppm, or 100ppm to 500 ppm. Sulfur, if present in the hydrocarbon-containing feed, may be or include, but is not limited to, H ₂ S, dimethyl disulfide as oneOr a plurality of thiols, 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 free of molecular oxygen. In some embodiments, the hydrocarbonaceous feed can include 5mol% or less, 3mol% or less, or 1mol% or less of molecular oxygen (O ₂ ). It is believed that providing a hydrocarbon-containing feed that is substantially free of molecular oxygen substantially prevents oxidative coupling reactions that would otherwise consume at least a portion of the alkanes and/or alkylaromatic hydrocarbons in the hydrocarbon-containing feed.

Exemplary embodiments

Fig. 1 depicts a system 100 for hydrocarbon-containing feed in a dehydrogenation line 1001 in accordance with one or more embodiments. The system 100 can 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 can optionally include a hydrocarbon-containing feed pretreatment zone 1005. In some embodiments, the system 100 may optionally include an oxygen soak zone 1030. The hydrocarbon-containing feed may be introduced via line 1001 or the pretreated hydrocarbon-containing feed may be introduced via line 1007 into the conversion zone 1010, such as at the bottom end of a fluidized bed reactor, such as a riser reactor, or at 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 can comprise steam. Regenerated catalyst particles can be transferred from reduction zone 1035 to conversion zone 1010 via line 1036. The hydrocarbon-containing feed can be contacted with regenerated catalyst particles in conversion zone 1010 to effect dehydrogenation of at least a portion of the hydrocarbon-containing feed to produce a conversion effluent via line 1013, which can include coked catalyst particles, one or more dehydrogenated hydrocarbons, unreacted hydrocarbon-containing feed, steam, benzene, or any mixture thereof.

The conversion effluent can be introduced via line 1013 to a separation zone 1015 which can separate the conversion effluent into a first particulate stream via 1017 that is enriched in coked catalyst particles and a first gas stream via line 1019 that is enriched in one or more dehydrogenated hydrocarbons and includes entrained coked catalyst particles. In some embodiments, the separation zone may include one or more cyclones arranged in series and/or parallel.

The first particulate stream may be introduced into combustion zone 1025 via line 1017. In some embodiments, the first particulate 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 gas component in the first particulate stream in line 1017 may be stripped prior to introducing the first particulate stream into combustion zone 1025. The oxidant and optionally the fuel via line 1022 can be introduced into a combustion zone 1025, which can contact at least a portion of the coked catalyst particles in the first particulate stream, via line 1024, thereby effecting combustion of at least a portion of the coke and, if present, the fuel to produce a combustion effluent comprising coke-depleted catalyst particles and combustion gas or flue gas. The combustion of the coke and, if present, the fuel may generate heat to burn off the coke from the coked catalyst, redisperse the group 8-10 element(s) on the spent catalyst and add heat to the regenerated catalyst particles.

A second particulate stream enriched in catalyst particles depleted in char via line 1026 and a second gas stream enriched in combustion gas via line 1027 can be recovered or otherwise obtained from combustion zone 1025. The combustion effluent may enter one or more separation devices to return a substantial portion of the entrained catalyst to the combustion zone. For the combustion zone, three or more cyclone separators may sometimes be installed to achieve higher solids recovery efficiency from the flue gas. The residual catalyst particles may be further recovered downstream by using filters, electrostatic precipitators, wet gas scrubbers, or the like. The separation means and/or operating conditions of the cyclones on the reforming and combustion zone can be adjusted to transfer higher or lower amounts of fines from the reforming or combustion zone depending on the level of fines collection difficulty of the product stream from the reforming zone relative to the flue gas stream from the combustion zone.

When fuel is introduced into the combustion zone via line 1024, a second particle stream can be introduced via line 1026 and an oxidizing gas can be introduced into and contacted in the oxygen soak zone 1030 via line 1028 to produce conditioned catalyst particles. Conditioned catalyst particles can be recovered from the oxygen soak zone 1030 via line 1031 and a gas stream via line 1032. In some embodiments, the gas stream in line 1032 and the conditioned catalyst particles in line 1031 can be separated via one or more cyclones. In some embodiments, the same set of cyclones can be used to separate conditioned catalyst particles via line 1031 from the gas stream via line 1032 and the second particle stream via line 1026 and combustion gas via line 1027.

The conditioned catalyst particles can be introduced via line 1031 or when no fuel is introduced to the combustion zone via line 1024, a second particle stream via line 1026 and a reducing gas via line 1033 are introduced to and contacted in the reduction zone 1035 to produce regenerated catalyst particles. Regenerated catalyst particles can be recovered from the reduction zone via line 1036 and a gas stream via line 1037. In some embodiments, the regenerated catalyst particles in line 1036 and the gas stream in line 1037 can be separated via one or more cyclones. In other embodiments, the gaseous components within the reduction zone can be conveyed to the conversion zone 1010 along with (rather than separately from) the regenerated catalyst particles via line 1036. Regenerated catalyst particles can be introduced to conversion zone 1010 via line 1036 and contacted with additional hydrocarbon-containing feed therein. In some embodiments, the gas stream in line 1037 can be recycled to the combustion zone such that any residual reducing gas, such as H ₂ Can serve as fuel for the combustion zone.

The first gas stream can be introduced via line 1019 and the first quench medium can be introduced via line 1018 into and contacted in a direct quench zone 1020 to produce a cooled gas stream. In some embodiments, benzene may be produced during dehydrogenation of the hydrocarbon-containing feed and may be present in the cooled gas 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 the liquid phase when contacted with the first gas stream in the direct quench zone 1020. In some embodiments, the first gas stream in line 1019 can be at a temperature > 620 ℃ and the cooled gas stream can be at a temperature of less than or equal to 620 ℃, less than or equal to 610 ℃, less than or equal to 600 ℃, less than or equal to 590 ℃, or less than or equal to 580 ℃. In some embodiments, the cooled gas stream may be at a temperature in the range of 550 ℃ or greater and 620 ℃ or less or 600 ℃ or less. Lowering the temperature of the first gas stream in line 1019 to less than 600 ℃ can reduce or stop undesirable thermal reactions of the gas components. The cooled gas stream may be recovered via line 1021. In some embodiments, one or more indirect heat exchange areas direct quench area 1020 may be substituted. In other embodiments, one or more indirect heat exchange zones may be used in conjunction with the direct quench zone 1020 upstream and/or downstream of the direct quench zone 1020.

The cooled gas stream via line 1021 and the second quench medium via line 1022 can be introduced into and contacted in quench zone 1040 to produce a top or third gas stream via line 1041, a recovered fines-depleted second quench medium via line 1042, and a recovered coked catalyst particle stream via line 1043. In some embodiments, quench zone 1040 may comprise a quench tower. In some embodiments, the cooled gas stream can be introduced via line 1021 to a gas-liquid contact zone disposed within the quench tower. In some embodiments, as noted above, the cooled gas stream via line 1021 can also be passed through one or more heat exchangers for heat recovery prior to entering the contact zone. In a contact zone disposed within the quench tower, the cooled gas stream can contact a second quench medium that is introduced into the quench tower via line 1022. The second quench medium in line 1022 can be injected downwardly into the contact zone countercurrent to the cooled gas stream to ensure good contact between the cooled gas stream and the second quench medium. A substantial portion of the catalyst fines and heat in the cooled gas stream in the contact zone may be transferred to the second quench medium, thereby producing a slurry that may include at least a portion of the second quench medium in the 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 can have a normal boiling point greater than that of first quench medium 1018. For example, in some embodiments, the first quench medium can be benzene and the second quench medium can have a normal boiling point of 150 ℃ to 580 ℃.

In quench zone 1040, the slurry can be introduced to one or more solid-liquid separation devices to produce a recovered fines-depleted 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 can be introduced to an optional metal recovery device 1060. In one or more embodiments, at least a portion of the recovered coked catalyst particle stream via line 1043 can be introduced to the combustion zone 1025. In one or more embodiments, at least a portion of the recovered fines-depleted second quench medium via line 1042 can be recycled back to the quench tower within quench zone 1040.

In some embodiments, a first quench medium (having a normal boiling point less than that of the second quench medium) can be withdrawn from the quench tower at a location in the quench tower above the gas-liquid contact zone, cooled via one or more heat exchangers, and a first portion or amount can be recycled back to the direct contact zone via line 1018. In some embodiments, a second portion or amount of the cooled first quench medium can be withdrawn to form a product stream, as the first quench medium can be one of the products of alkane dehydrogenation, benzene. In some embodiments, a third portion or amount of the cooled first quench medium can be recycled to the quench tower.

Any water present in the quench tower may be withdrawn from the quench tower at a location above the contact area in the quench tower, cooled down by one or more heat exchangers, and recycled back to the quench tower. A portion or amount of the cooled water can be withdrawn to form a wastewater stream that can be sent for treatment and/or evaporation and used as co-feed with the hydrocarbon-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 can be substantially free of coked catalyst particles and can then be further cooled to be introduced into compression zone 1050, thereby producing a compressed gas stream via line 1051. If the third gas stream in line 1041 contains any remaining coked catalyst particles, such coked catalyst particles can be removed via one or more electrostatic precipitators, one or more filters, one or more screens, one or more membranes, a wet gas scrubber, contact with an absorbent scavenger, one or more additional quench towers, one or more cyclones, one or more hydrocyclones, one or more centrifuges, one or more plates or cones, or any combination thereof, thereby removing at least a portion of the entrained coked catalyst particles therefrom.

The compressed gas stream can be introduced via line 1051 to a product recovery zone 1055 to separate a product therefrom. In some embodiments, the products can include, but are not limited to, light gases via line 1056, unreacted hydrocarbonaceous 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 any mixture thereof. In some embodiments, one or more of the light gases via line 1056 can be introduced to the combustion zone via line 1024 as an optional fuel. In some embodiments, at least a portion of the unreacted hydrocarbonaceous feed can be recycled to the conversion zone via line 1057. In some embodiments, the dehydrogenated hydrocarbon in line 1058 can 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 can be used as the first and/or second quench medium or elsewhere as the quench medium.

In some embodiments, a fourth gas stream can also be introduced via line 1053 to the product recovery region 1055. The fourth gas stream in line 1053 can 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 tar products, steam cracker quench oil products, steam cracker gas oil products, steam cracker naphtha products, and steam cracker gas overhead products, which may include hydrogen, methane, ethane, ethylene, propane, propylene, butenes, butanes, pentanes, and other volatile hydrocarbons. In some embodiments, the fourth gas stream in line 1053 can be compressed. In other embodiments, the fourth gas stream via line 1053 can be combined with the third gas stream in line 1041 and introduced into the compression zone 1050 to produce a combined third and fourth compressed gas stream in line 1051.

Examples:

the foregoing discussion may be further described with reference to the following non-limiting examples.

Catalyst composition 1: prepared as follows: mix in deionized water (524 ml)D pseudo-boehmite (Sasol) (47 g) and containing 70% by weight MgO and 30% by weight Al ₂ O ₃ Calcined Mg-Al hydrotalcite (+)>MG 70) (44 g) to prepare a slurry. The slurry was milled and spray dried on a Buchi B-290 mini spray dryer to produce spray dried particles. Calcining the spray dried granules in air at 550 ℃ for 4 hours to produce a powder containing nominally 50 wt%/->MG70 and 50 wt% are derived from +.>Al of D ₂ O ₃ Is used for calcining the carrier particles. The calcined support particles were impregnated with an aqueous solution comprising tin (IV) chloride pentahydrate, chloroplatinic acid hexahydrate, and deionized water using incipient wetness. Calcining the impregnated material in air at 800 ℃ for 12 hours to produce a catalyst at 50:50MG70:>d a catalyst composition containing nominally 0.3 wt% Pt and 1.5 wt% Sn.

Catalyst composition 2: prepared as follows: 40 wt% aluminum chlorohydrate (aluminum chlorohydrol) solution (ACH) (85 g) and calcined Mg-Al hydrotalcite [. Sup.MG 70) (88 g) to prepare a slurry. The slurry was milled and spray dried on a Buchi B-290 mini spray dryer to produce spray dried particles. Calcination of the spray dried granules in air at 550 ℃ for 4 hours to yield a powder containing nominally 80 wt.%MG70 and 20 wt% of Al derived from ACH ₂ O ₃ Is used for calcining the carrier particles. The calcined support particles were impregnated with an aqueous solution comprising tin (IV) chloride pentahydrate, chloroplatinic acid hexahydrate, and deionized water using incipient wetness. The impregnated material was calcined in air at 800 ℃ for 12 hours to produce a catalyst composition containing nominally 0.3 wt.% Pt and 1.5 wt.% Sn on an 80:20mg 70:ach.

Catalyst composition 3: the catalyst was prepared according to the following procedure: leave 2.3gMG 70/170 (Sasol), which is MgO-Al obtained by calcining hydrotalcite ₂ O ₃ And (3) mixing metal oxides. The mixed metal oxide contains 70 wt% MgO and 30 wt% Al ₂ O ₃ . BET surface area170m according to Sasol ² And/g. Tin (IV) chloride pentahydrate (0.103 g) (Acros Organics), chloroplatinic acid hexahydrate (0.0184 g) (BioXtra) and deionized water (2.2 mL) were mixed in a vial to prepare a solution. Soaking->MG 70/170 vector. The impregnated material was dried at 110 ℃ for 6 hours and calcined at 800 ℃ for 12 hours, all in air. The final product contained nominally 0.3 wt% Pt and 1.5 wt% Sn.

Catalyst composition 4: the catalyst was prepared according to the following procedure: leave 20gMG 70/170 (Sasol), which is MgO-Al obtained by calcining hydrotalcite ₂ O ₃ And (3) mixing metal oxides. The mixed metal oxide contains 70 wt% MgO and 30 wt% Al ₂ O ₃ . BET surface area of 170m according to Sasol ² And/g. The appropriate equivalent of tin (II) chloride dihydrate and deionized water are mixed to form a solution. Soaking->MG 70/170 vector. The impregnated material was stored in a closed vessel at room temperature for 1h and then dried overnight at 120 ℃. The appropriate equivalent of tetraamineplatinum (II) nitrate and deionized water are mixed to form a solution. The Sn-impregnated support was further impregnated with a Pt solution. The impregnated material was allowed to stand in a closed vessel at room temperature for 1h, then dried overnight at 120 ℃ and calcined at 800 ℃ for 12 h, all in air. The final product contained nominally 0.3 wt% Pt and 1.5 wt% Sn.

Catalyst compositions 5-18 were prepared according to the following procedure. Calcination in air at 550℃for each catalyst compositionMG 80/150 (3 g) (Sasol) for 3 hours, which is a catalyst containing 80% by weight MgO and 20% by weight Al ₂ O ₃ And has 150m ² Mixed Mg/Al metal oxide of surface area per gram to form a support. Solutions containing the appropriate amounts of tin (IV) chloride pentahydrate (Acros Organics) and/or chloroplatinic acid (Sigma Aldrich) when used to prepare the catalyst composition and 1.8ml of deionized water were prepared in a vial. Impregnating the calcined ++with the corresponding solution for each catalyst composition>MG 80/150 support (2.3 g). The impregnated material was equilibrated in a closed vessel at Room Temperature (RT) for 24 hours, dried at 110 ℃ for 6 hours and calcined at 800 ℃ for 12 hours. Table 1 shows nominal Pt and Sn content of each catalyst composition based on the weight of the support.

Examples of catalysts are described above.

The fixed bed experiments were carried out at-100 kPa-absolute. Gas Chromatography (GC) was used to measure the composition of the reactor effluent. The concentration of each component in the reactor effluent was then used to calculate C ₃ H ₆ Yield and selectivity. Calculation of C based on carbon moles as reported in these examples ₃ H ₆ Yield and selectivity.

In each example, 0.3g of catalyst Mcat was mixed with the appropriate amount of quartz diluent and loaded into a quartz reactor. The amount of diluent is determined such that the catalyst bed (catalyst + diluent) overlaps the isothermal zone of the quartz reactor and such that the catalyst bed is largely isothermal during operation. The dead volume of the reactor was filled with quartz chips/rods.

Using the concentration of each component in the reactor effluentCalculation C ₃ H ₆ Yield and selectivity. t is t _rxn At the beginning and t _rxn C at the end ₃ H ₆ Yield and selectivity are respectively expressed as Y _ini 、Y _end 、S _ini And S is _end And reported as a percentage in the table below.

The method steps of examples 1 and 2 are as follows: 1. the system was purged with inert gas. 2. Oxygen-containing gas (O gas) at a flow rate (F _regen ) Through the bypass of the reaction zone, while an inert gas (insert) is passed through the reaction zone. Heating the reaction zone to a regeneration temperature T _regen .3. The oxygen-containing gas is then passed through the reaction zone for a period of time (t _regen ) To regenerate the catalyst. At t _regen Thereafter, the temperature in the reaction zone is from T _regen Change to reduction temperature (T) _red ) While maintaining the flow of oxygen-containing gas. 4. The system was purged with inert gas. 5. Containing H ₂ The gas (H gas) is at a flow rate (F _red ) The bypass through the reaction zone is continued for a period of time while inert gas is passed through the reaction zone. This is then followed by T _red The following is H-containing ₂ The gas flows through the reaction zone for a certain period of time (t _red ). 6. The system was purged with inert gas. During this process, the temperature of the reaction zone is varied from T _red The reaction temperature was changed to 655 ℃.7. Comprises 81% by volume of C ₃ H ₈ Hydrocarbon (HC) containing feed of 9 vol% inert gas (Ar or Kr) and 10 vol% steam at flow rate (F _rxn ) The bypass through the reaction zone is continued for a period of time while inert gas is passed through the reaction zone. The hydrocarbonaceous feed was then passed through the reaction zone at 655 ℃ for 10min. 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 method steps are cyclically repeated until stable performance is obtained. Table 2 shows that both catalysts 1 and 2 are active/selective for propane dehydrogenation. Figure 2 shows that catalyst 2 is stable for propane dehydrogenation over 60 cycles.

Example 3-effect of steam during oxidation. The method comprises the following steps: 1. purging the system with an inert gas while heating the reaction zone to an oxidation temperature T _oxi .2. Oxygen-containing gas (O gas) at a flow rate (F _oxi ) Through the bypass of the reaction zone while inert gas is passed through the reaction zone. 3. The oxygen-containing gas is then passed through the reaction zone for a period of time (t _oxi ) To oxidize the catalyst. 4. At t _oxi Thereafter, an inert gas is passed through the reaction zone and the temperature in the reaction zone is adjusted from T _oxi Change to reduction temperature (T) _red ). 5. The system was purged with inert gas. 6. Containing H ₂ The gas (H gas) is at a flow rate (F _red ) The bypass through the reaction zone is continued for a period of time while inert gas is passed through the reaction zone. This is then followed by T _red The following is H-containing ₂ The gas flows through the reaction zone for a certain period of time (t _red ). 7. The system was purged with inert gas. During this process, the temperature of the reaction zone is varied from T _red The reaction temperature was changed to 670 ℃.8. Comprises 81% by volume of C ₃ H ₈ Hydrocarbon (HC) containing feed of 9 vol% inert gas (Ar or Kr) and 10 vol% steam at flow rate (F _rxn ) The bypass through the reaction zone is continued for a period of time while inert gas is passed through the reaction zone. The hydrocarbonaceous feed was then passed through the reaction zone at 670 ℃ for 10min. 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 method steps are cyclically repeated until stable performance is obtained. Table 3 shows that the presence of more than 10% by volume of steam in the air during oxidation produces even more deactivated catalyst (C) ₃ H ₆ Yield 56.8% versus 61.1%). The more steam is present in the air during oxidation, the lower the activity. On the other hand, if the humid air is switched to dry air after 2min of oxidation, the catalyst is effectively regenerated.

Example 4-H ₂ Effect of duration of reduction. 1. Flushing with inert gasThe system was washed while heating the reaction zone to an oxidation temperature of 800 ℃.2. Oxygen-containing gas (O gas) at a flow rate (F _oxi ) Through the bypass of the reaction zone while inert gas is passed through the reaction zone. 3. The oxygen-containing gas is then passed through the reaction zone for a period of time (t _oxi ) To oxidize the catalyst. 4. The system was purged with inert gas. During this process, the temperature of the reaction zone was maintained at 800 ℃.5. Containing H ₂ The gas (H gas) is at a flow rate (F _red ) The bypass through the reaction zone is continued for a period of time while inert gas is passed through the reaction zone. This is then followed by bringing the H-containing phase to 800 ℃ ₂ The gas flows through the reaction zone for a certain period of time (t _red ). 6. The reaction zone is vented with He. During this process, the temperature of the reaction zone was reduced from 800 ℃ to a reaction temperature of 655 ℃.7. Comprises 81% by volume of C ₃ H ₈ Hydrocarbon (HC) containing feed of 9 vol% inert gas (Ar or Kr) and 10 vol% steam at flow rate (F _rxn ) The bypass through the reaction zone is continued for a period of time while inert gas is passed through the reaction zone. The hydrocarbonaceous feed was then passed through the reaction zone at 655 ℃ for 10min. 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 method steps are cyclically repeated until stable performance is obtained. Table 4 shows that without catalyst reduction, the propylene yield of the oxidation catalyst (53.7%) was even lower than that of the deactivated catalyst (61.3%).

Example 5-fixed bed experiments with catalysts 5-18 were carried out at about 100 kPa-absolute. Gas Chromatography (GC) was used to measure the composition of the reactor effluent. The concentration of each component in the reactor effluent was then used to calculate C ₃ H ₆ Yield and selectivity. Calculation of C based on carbon moles as reported in these examples ₃ H ₆ Yield and selectivity.

In each example, 0.3g of the catalyst composition was mixed with an appropriate amount of quartz diluent and loaded into a quartz reactor. The amount of diluent is determined such that the catalyst bed (catalyst + diluent) overlaps the isothermal zone of the quartz reactor and such that the catalyst bed is largely isothermal during operation. The dead volume of the reactor was filled with quartz chips/rods.

t _rxn At the beginning and t _rxn C at the end ₃ H ₆ Yield and selectivity are respectively expressed as Y _ini 、Y _end 、S _ini And S is _end And are reported as percentages in tables 5 and 6 below for catalyst compositions 5-12.

The method steps of catalyst compositions 5-12 are as follows: 1. the system was purged with inert gas. 2. Dry air was bypassed through the reaction zone at a flow rate of 83.9sccm while inert gas was passed through the reaction zone. The reaction zone was heated to a regeneration temperature of 800 ℃.3. The catalyst was regenerated by passing dry air through the reaction zone at a flow rate of 83.9sccm for 10 min. 4. The system was purged with inert gas. 5. With 10% H by volume ₂ And 90% by volume Ar of H-containing ₂ The gas was bypassed through the reaction zone at a flow rate of 46.6sccm for a period of time while the inert gas was passed through the reaction zone. This is then followed by bringing the H-containing phase to 800 ℃ ₂ The gas flowed through the reaction zone for 3 seconds. 6. The system was purged with inert gas. During this process, the temperature of the reaction zone was changed from 800 ℃ to a reaction temperature of 670 ℃.7. Comprises 81% by volume of C ₃ H ₈ A Hydrocarbon (HC) containing feed of 9% by volume inert gas (Ar or Kr) and 10% by volume steam was bypassed through the reaction zone at a flow rate of 35.2sccm for a period of time while inert gas was passed through the reaction zone. The hydrocarbonaceous feed was then passed through the reaction zone at 670 ℃ for 10min. 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 method steps are cyclically repeated until stable performance is obtained. Tables 5 and 6 show that catalyst composition 10 containing only 0.025 wt% Pt and 1 wt% Sn has similar yields and similar selectivities as compared to catalyst composition 5 containing 0.4 wt% Pt and 1 wt% Sn, which is surprising and unexpected. Catalyst composition 12, which does not include any Pt, does not show Apparent propylene yield.

Catalyst compositions 13-18 were also tested using the same method steps 1-7 described above with respect to catalysts 5-12. Table 7 shows that for a catalyst composition comprising 0.1 wt% Pt based on the weight of the support, the Sn level should not be too low or too high in order to achieve optimal propylene yields.

Table 8 shows that for a catalyst composition comprising 0.0125 wt% Pt based on the weight of the support, the level of Sn should not be too high or too low in order to achieve optimal propylene yields.

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Catalyst composition 10 containing only 0.025 wt% Pt and 1 wt% Sn was also subjected to life testing using the same method steps 1-7 described above with respect to catalyst compositions 5-12 except that a flow rate of 17.6sccm was used instead of 35.2sccm in step 7. FIG. 3 shows that the catalyst composition 10 maintains performance for 204 cycles (x-axis is time, y-axis is C ₃ H ₆ Yield and C ₃ H ₆ Selectivity, all in mole% carbon).

List of embodiments

The present disclosure may further include the following non-limiting embodiments:

A1. a method of upgrading hydrocarbons comprising: (I) Contacting the 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 comprising coked catalyst particles and one or more dehydrogenated hydrocarbons, wherein: the hydrocarbon-containing feed comprises C ₂ -C ₁₆ One or more of linear or branched alkanes, C ₄ -C ₁₆ One or more of the cyclic alkanes, C ₈ -C ₁₆ One or more of the alkylaromatic hydrocarbons, or mixtures thereof, the hydrocarbon-containing feed being at a rate of 0.1hr ^-1 -1,000hr ^-1 Weight hourly space velocity in the range contacting the catalyst particles based on any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Weight of aromatic hydrocarbons, fluidized dehydrogenation catalyst particles and any C ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ The weight ratio of the total amount of aromatic hydrocarbons is in the range of 3 to 100, and the hydrocarbon-containing feed and the catalyst particles are contacted at a temperature in the range of 600 ℃ to 750 ℃; (II) separating from the conversion effluent a first particulate stream enriched in coked catalyst particles and a first gas 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 effect combustion of at least a portion of the coke to produce a combustion effluent comprising coke-depleted catalyst particles and combustion gas, wherein the dehydrogenation activity of the coke-depleted catalyst particles is less than the dehydrogenation activity of the coked catalyst particles, and wherein the combustion zone is heated by an electric heater; (IV) separating a second particulate stream enriched in catalyst particles depleted in char and a second gas stream enriched in combustion gas from the combustion effluent; (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 dehydrogenation activity greater than coked catalyst particles; (VI) contacting an additional amount of the hydrocarbon-containing feed with at least a portion of the regenerated catalyst particles in the conversion zone to produce catalyst particles comprising re-coking An additional amount of conversion effluent of the pellet 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 the plurality of products from the compressed gas stream.

A2.A1, wherein no supplemental hydrocarbon fuel is introduced into the combustion zone.

A3.A1 or A2 process wherein any hydrocarbons present in the combustion zone comprise entrained hydrocarbons from the conversion effluent.

The process of any one of A4.A1 to A3, wherein the hydrocarbon-containing feed is fed at a rate of 0.1hr ^-1 -100hr ^-1 Preferably 0.2hr ^-1 -64hr ^-1 Or more preferably 0.4hr ^-1 -32hr ^-1 Weight hourly space velocity in the range contacts fluidized dehydrogenation catalyst particles based on any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Weight of aromatic hydrocarbons.

The process of any one of a5.a1 to A4 wherein the fluidized dehydrogenation catalyst particles are mixed with any C ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ The weight ratio of the total amount of aromatic hydrocarbons is in the range of 5 to 90, or more preferably 10 to 80.

The process of any one of a6.a1 to 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.

The process of any one of a7.a1 to A6, wherein the hydrocarbon-containing feed is contacted with the fluidized dehydrogenation catalyst particles at a total pressure in the range of from 0 kPa-gauge to 500 kPa-gauge, preferably from 20 kPa-gauge to 300 kPa-gauge, or more preferably from 40 kPa-gauge to 200 kPa-gauge.

The process of any one of a8 a1 to A7, wherein the hydrocarbon-containing feed comprises 0.1 to 15mol% steam, preferably 1 to 10mol% steam, or more preferably 3 to 8mol% steam.

The process of any one of a9 a1 to A8, wherein the hydrocarbon-containing feed is at a temperature of less than or equal to 620 ℃ when initially contacted with the fluidized dehydrogenation catalyst particles.

The process of any one of a10 a1 to A9, wherein in step (V) the second particle stream is contacted with a reducing gas at a temperature in the range 450 ℃ to 900 ℃, preferably 600 ℃ to 900 ℃, more preferably 620 ℃ to 800 ℃.

The process of any one of a11.A1 to a10, wherein in step (V) the second particle stream is contacted with the reducing gas for a duration of 0.1 seconds to 300 seconds, preferably 1 second to 100 seconds, more preferably 2 seconds to 10 seconds, thereby producing regenerated catalyst particles.

The method of any one of a12 A1 to a11, wherein: the first gas stream enriched in one or more dehydrogenated hydrocarbons further comprises entrained coked catalyst particles, step (VII) comprising: (VIIa) contacting the first gas stream with a first quench medium, indirectly transferring heat from the first gas stream to the first heat transfer medium, or a combination thereof, thereby producing a cooled gas stream, and (VIIb) contacting the cooled gas stream with a second quench medium within a quench tower, (VIIc) recovering from the quench tower a third gas stream comprising one or more dehydrogenated hydrocarbons and a slurry stream comprising at least a portion of the second quench medium in the liquid phase and entrained coked catalyst particles, and step (VIII) comprises compressing at least a portion of the third gas stream thereby producing a compressed gas stream.

A process of a13.a12 wherein the conversion effluent further comprises benzene, the process further comprising (X) withdrawing a benzene product stream from the quench tower.

A process of a14, a12 or a13, wherein step (VIIa) comprises contacting a first gas stream with a first quench medium.

The process of any one of a15 A1 to a11, wherein the first particulate stream and the first gas stream are separated from the conversion effluent in one or more cyclones, and wherein the first gas stream is contacted with a first quench medium in step (VII) in at least one distribution chamber of the one or more cyclones to produce a cooled gas stream.

The process of a16.a15 wherein the residence time of the gas component in the first gas stream in each of the one or more cyclones is less than or equal to 1 second.

The process of any one of a17.a1 to a16, wherein the conversion effluent is at a temperature of ≡620 ℃ and the cooled gas stream is at a temperature of ≡500 ℃ and < 620 ℃, preferably ≡550 ℃ to ≡600 ℃.

The process of any one of a18 A1 to a17, wherein the dehydrogenation catalyst particles comprise from 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, a combination thereof, or a mixture thereof disposed on the support, and wherein all weight percent values are based on the weight of the support.

The process of any one of a19.a1 to a18, wherein the dehydrogenation catalyst particles comprise from 0.001 wt.% to 6 wt.% Pt and optionally up to 10 wt.% promoter disposed on a support, the promoter comprising Sn, cu, au, ag, ga, a combination thereof, or a mixture thereof, wherein the support comprises at least 0.5 wt.% of a group 2 element, and wherein all weight percent values are based on the weight of the support.

The method of any one of a20 A1 to a19, wherein the dehydrogenation catalyst particles meet the requirements of the GeldartA or Geldart B classification.

The process of any one of a21 a1 to 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 gaseous overhead product separated from a primary fractionator that receives pyrolysis effluent from a steam cracker furnace.

The process of any one of a22 a1 to a21, wherein the hydrocarbon-containing feed comprises propane derived from biomass.

The process of any one of a23 a1 to a22, wherein the hydrocarbon-containing feed comprises liquefied petroleum gas.

The process of any one of A24A 1 to A23, wherein the oxidant used in step (III) comprises ≡95mol% O ₂ 。

The process of any one of a25 a1 to a24, wherein the conversion zone and the combustion zone are located within a modified fluid catalytic cracking reactor-regenerator unit.

Various terms are defined above. Where a term is used in a claim without the above definition, that term should be given to the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference for all jurisdictions in which such incorporation is permitted, so long as such disclosure is not inconsistent with this application.

While the foregoing 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, and the scope thereof is determined by the claims that follow.

Claims

1. A method of upgrading hydrocarbons comprising:

(I) Contacting the 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 comprising coked catalyst particles and one or more dehydrogenated hydrocarbons, wherein:

The hydrocarbon-containing feed comprises C ₂ -C ₁₆ One or more of linear or branched alkanes, C ₄ -C ₁₆ One or more of the cyclic alkanes, C ₈ -C ₁₆ One or more of the alkylaromatic hydrocarbons, or mixtures thereof,

hydrocarbon-containing feed at 0.1hr ^-1 -1,000hr ^-1 Weight hourly space velocity in the range contacting the catalyst particles based on any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ The weight of the aromatic hydrocarbon is calculated,

fluidized dehydrogenation catalyst particles with any C ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ The weight ratio of 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 600 ℃ to 750 ℃;

(II) separating from the conversion effluent a first particulate stream enriched in coked catalyst particles and a first gas 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 and a fuel in a combustion zone to effect combustion of at least a portion of the coke to produce a combustion effluent comprising coke-depleted catalyst particles and combustion gas, wherein the dehydrogenation activity of the coke-depleted catalyst particles is less than the dehydrogenation activity of the coked catalyst particles;

(IV) separating a second particulate stream enriched in catalyst particles depleted in char and a second gas stream enriched in combustion gas from the combustion effluent;

(V) contacting at least a portion of the coke-depleted catalyst particles in the second particle stream with an oxidizing gas at an oxidation temperature in the range of 620 ℃ to 1,000 ℃ in an oxygen soak zone for a duration of at least 20 seconds, thereby producing conditioned catalyst particles having an activity less than coked catalyst particles;

(VI) contacting at least a portion of the conditioned catalyst particles with a reducing gas in a reduction zone, thereby producing regenerated catalyst particles having dehydrogenation activity greater than coked catalyst particles;

(VII) contacting an additional amount of hydrocarbon-containing feed with at least a portion of the regenerated catalyst particles in the conversion zone, thereby producing an additional amount of conversion effluent comprising re-coked catalyst particles and an additional amount of 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; and

(X) separating the plurality of products from the compressed gas stream.

2. The process of claim 1 wherein the hydrocarbon-containing feed is fed at a rate of 0.1hr ^-1 -100hr ^-1 Preferably 0.2hr ^-1 -64hr ^-1 Or more preferably 0.4hr ^-1 -32hr ^-1 Weight hourly space velocity in the range contacts fluidized dehydrogenation catalyst particles based on any C in the hydrocarbon-containing feed ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ Weight of aromatic hydrocarbons.

3. The process of claim 1 or claim 2, wherein the fluidized dehydrogenation catalyst particles are mixed with any C ₂ -C ₁₆ Alkanes and any C ₈ -C ₁₆ The weight ratio of the total amount of aromatic hydrocarbons is in the range of 5 to 90, or more preferably 10 to 80.

4. A process according to any one of claims 1 to 3, 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.

5. The process of any of claims 1 to 4, wherein the hydrocarbon-containing feed is contacted with the fluidized dehydrogenation catalyst particles at a total pressure in the range of from 0 kPa-gauge to 500 kPa-gauge, preferably from 20 kPa-gauge to 300 kPa-gauge, or more preferably from 40 kPa-gauge to 200 kPa-gauge.

6. The process according to any one of claims 1 to 5, wherein the hydrocarbon-containing feed comprises 0.1 to 15mol% steam, preferably 1 to 10mol% steam, or more preferably 3 to 8mol% steam.

7. The process of any of claims 1-6, wherein the hydrocarbon-containing feed is at a temperature of less than or equal to 620 ℃ when initially contacted with the fluidized dehydrogenation catalyst particles.

8. The process of any one of claims 1 to 7, wherein the coke-depleted catalyst particles in the second particle stream are contacted with the reducing gas in step (V) for a duration of 0.5 minutes to 30 minutes, preferably 2 minutes to 20 minutes, or more preferably 3 minutes to 10 minutes, thereby producing conditioned catalyst particles.

9. The method of any one of claims 1 to 8, wherein the oxidizing gas in step (V) comprises no more than 5% h2o, based on the total moles in the oxidizing gas.

10. The process according to any one of claims 1 to 9, wherein the catalyst particles conditioned in step (VI) are contacted with a reducing gas at a temperature in the range 450 ℃ to 900 ℃, preferably 600 ℃ to 900 ℃, more preferably 620 ℃ to 800 ℃.

11. The process according to any one of claims 1 to 10, wherein the conditioned catalyst particles in step (VI) are contacted with the reducing gas for a duration of 0.1 to 300 seconds, preferably 1 to 100 seconds, more preferably 2 to 10 seconds, thereby producing regenerated catalyst particles.

12. The method of any one of claims 1 to 11, wherein:

the first gas stream enriched in one or more dehydrogenated hydrocarbons further comprises entrained coked catalyst particles,

step (VIII) comprises:

(VIIIa) contacting the first gas stream with a first quench medium, indirectly transferring heat from the first gas stream to the first heat transfer medium, or a combination thereof, thereby producing a cooled gas stream, and

(VIIIb) contacting the cooled gas stream with a second quench medium in a quench tower,

(VIIIc) recovering from the quench tower a third gas stream comprising one or more dehydrogenated hydrocarbons and a slurry stream comprising at least a portion of the second quench medium in the liquid phase and entrained coked catalyst particles, an

Step (IX) includes compressing at least a portion of the third gas stream to produce a compressed gas stream.

13. The process of claim 12, wherein the conversion effluent further comprises benzene, the process further comprising (XI) withdrawing a benzene product stream from the quench tower.

14. A process according to claim 12 or claim 13, wherein step (VIIIa) comprises contacting the first gas stream with a first quench medium.

15. The process of any one of claims 1 to 11, wherein the first particulate stream and the first gas stream are separated from the conversion effluent within one or more cyclones, and wherein the first gas stream is contacted with the first quench medium in step (VIII) in at least one distribution chamber of the one or more cyclones to produce a cooled gas stream.

16. The method of claim 15, wherein a residence time of the gas component in the first gas stream within each of the one or more cyclones is less than or equal to 1 second.

17. The process of any one of claims 1 to 16, wherein the conversion effluent is at a temperature of ≡620 ℃ and the cooled gas stream is at a temperature of ≡500 ℃ and < 620 ℃, preferably ≡550 ℃ to ≡600 ℃.

18. The process of any one of claims 1 to 17, wherein the dehydrogenation catalyst particles comprise from 0.001 wt.% to 6 wt.% of the group 8-10 element and optionally up to 10 wt.% of a promoter comprising Sn, cu, au, ag, ga, a combination thereof, or a mixture thereof disposed on the support, and wherein all weight percent values are based on the weight of the support.

19. The process of any one of claims 1 to 18, wherein the dehydrogenation catalyst particles comprise from 0.001 wt.% to 6 wt.% Pt and optionally up to 10 wt.% promoter disposed on a support, the promoter comprising Sn, cu, au, ag, ga, a combination thereof, or a mixture thereof, wherein the support comprises at least 0.5 wt.% group 2 element, and wherein all weight percent values are based on the weight of the support.

20. The process of any one of claims 1 to 19, wherein the dehydrogenation catalyst particles meet the requirements of the Geldart a or Geldart B classification.

21. The process of any one of claims 1 to 20, wherein in step (X) a plurality of products are separated from the compressed gas stream in a product recovery unit that also receives a gaseous overhead product separated from a primary fractionator that receives pyrolysis effluent from a steam cracker furnace.

22. The process of any one of claims 1 to 21, wherein the hydrocarbon-containing feed comprises propane derived from biomass.

23. The method of any one of claims 1 to 22, wherein the hydrocarbon-containing feed comprises liquefied petroleum gas.

24. The process according to any one of claims 1 to 23, wherein the oxidant used in step (III) comprises ≡95mol% O ₂ 。

25. The process of any one of claims 1 to 24, wherein the conversion zone and the combustion zone are located within a modified fluid catalytic cracking reactor-regenerator unit.