Dehydrogenation process of alkanes and alkyl aromatic hydrocarbons

Abstract

The hydrocarbons may be contacted with the dehydrogenation catalyst particles to produce an effluent that may include coked catalyst particles and dehydrogenated hydrocarbons. A first stream rich in the coked catalyst particles and a second stream rich in the dehydrogenated hydrocarbons and containing entrained catalyst particles may be separated from the effluent. The second stream may be contacted with a first quenching medium to produce a cooled stream. The cooled stream may be contacted with a second quenching medium in a quench tower. A gaseous stream containing the dehydrogenated hydrocarbons, a first quenching medium stream, and a slurry stream containing the second quenching medium and the entrained catalyst particles may be separated from the tower. The first quenching medium may be recycled. The entrained catalyst particles may be separated from the slurry to provide a recovered second quenching medium and recovered entrained catalyst particles. The recovered second quenching medium may be recycled.

Description

[Technical Field]

[0001] Cross-reference of related applications This application claims priority and benefits of U.S. Provisional Application No. 63 / 231,939, filed August 11, 2021, and U.S. Provisional Application No. 63 / 328,935, filed April 8, 2022, which are incorporated herein by reference in their entirety.

[0002] field This disclosure relates to a dehydrogenation process for one or more alkanes and / or alkyl aromatic hydrocarbons. More specifically, this disclosure relates to a process for dehydrogenating one or more alkanes and / or one or more alkyl aromatic hydrocarbons in the presence of fluid catalyst particles to produce an effluent containing one or more olefins. [Background technology]

[0003] background Dehydrogenation of alkane and / or alkyl aromatic hydrocarbon feeds provides olefin slates for the production of various commodity products (construction, packaging, etc.). In particular, dehydrogenation of propane produces propylene, which is an important intermediate in the production of polypropylene. The hydrocarbon feed is introduced into a reactor and contacted with fluid dehydrogenation catalyst particles at high temperatures that enable dehydrogenation of the hydrocarbon feed, producing a conversion effluent. The dehydrogenation process is designed to recover the catalyst particles using one or more cyclones. However, catalyst particles that are not collected may need to be returned to the reactor for recycling or recovered for metal recycling, etc. One way to improve the separation of catalyst particles from conversion effluent is to increase the number of cyclones through which the conversion effluent passes. However, with respect to the composition of the conversion effluent, the use of two or more cyclone stages is undesirable because it increases the residence time of the conversion effluent at high temperatures, potentially causing further thermal reactions in the product and unreacted hydrocarbon feed components, thus lowering the yield of the desired product. On the other hand, insufficient separation is also undesirable because any catalyst particles left in the gaseous product stream may cause reverse dehydrogenation when the product stream is quenched, and a large amount of catalyst recovered at low temperatures downstream is undesirable because it requires more heat to be introduced into the process due to the increased amount of catalyst that must be reheated to the reaction temperature. Therefore, an improved process is needed to dehydrogenate alkanes and / or alkyl aromatic hydrocarbons to produce conversion effluents and to recover catalyst particles from these effluents. This disclosure satisfies this need and other needs. [Overview of the Initiative]

[0004] summary An upgrade process for alkanes and / or alkyl aromatic hydrocarbons is provided. In some embodiments, the hydrocarbon upgrade process may include the step of (I) contacting a hydrocarbon-containing feed with fluid dehydrogenation catalyst particles in a conversion zone to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed to produce a conversion effluent which may contain coking catalyst particles and one or more dehydrogenated hydrocarbons. The process may also include the step of (II) separating from the conversion effluent a first stream rich in coking catalyst particles and low in one or more dehydrogenated hydrocarbons and a second stream rich in one or more dehydrogenated hydrocarbons and containing encompassed coking catalyst particles. The process may also include the step of (III) contacting the second stream with a first quench medium to produce a cooled second stream. The process may also include the step of (IV) contacting the cooled second stream with a second quench medium in a quench tower. The process may also include the step of (V) recovering from the quench tower a gas stream which may contain one or more dehydrogenated hydrocarbons, a condensed first quench medium stream, and a slurry stream which may contain at least a portion of the liquid phase second quench medium and encompassed coking catalyst particles. The process may also include the step of (VI) recirculating at least a portion of the condensed first quench medium to step (III). The process may also include the step of (VII) separating at least a portion of the encompassed coking catalyst particles from the slurry stream to give a recovered second quench medium stream and a recovered encompassed coking catalyst particle stream. The process may also include the step of (VIII) recirculating at least a portion of the recovered second quench medium stream to step (IV). [Brief explanation of the drawing]

[0005] [Figure 1] A system for dehydrogenating a hydrocarbon-containing feed, comprising a reactor or conversion zone, a regenerator or combustion zone, and a quench tower, is shown according to one or more of the described embodiments. [Figure 2]Another system for dehydrogenating a hydrocarbon-containing feed, comprising a reactor or conversion zone, a regenerator or combustion zone, and a quench tower, is shown according to one or more of the described embodiments. [Figure 3] This demonstrates that the catalyst composition remained stable for more than 60 cycles against propane dehydrogenation. [Figure 4] This indicates that catalyst composition 8 maintained its performance over 204 cycles. [Modes for carrying out the invention]

[0006] Detailed explanation The following describes various specific embodiments, versions, and examples of the present invention, including preferred embodiments and definitions adopted herein for the purpose of understanding the claimed invention. While the following detailed description provides specific preferred embodiments, those skilled in the art will understand that these embodiments are merely illustrative and that the present invention can be carried out in other ways. For the purpose of determining infringement, the scope of the present invention refers to any one or more of the appended claims and includes their equivalents, elements, or limitations that are equivalent to those listed. Any reference to “invention” may mean one or more of the present invention as defined by the claims, but not necessarily all of them. This disclosure describes a process that includes at least one “step.” It should be understood that each step is an action or operation that may be performed once or multiple times in a continuous or discontinuous manner within the process. Unless otherwise specified or the context makes it clear that there is another meaning, the steps of the process may be performed sequentially in the order described, with or without overlap with one or more other steps, or in any other order. Furthermore, one or more, or even all, steps may be performed simultaneously with respect to the same or different batches of material. For example, in a continuous process, the first step of the process may be performed with respect to the raw material that was just supplied at the beginning of the process, while the second step is performed simultaneously with respect to intermediate material resulting from the processing of raw material supplied to the process earlier than the first step. Preferably, the steps are performed in the order described.

[0007] Unless otherwise indicated, all numbers indicating quantities in this disclosure should be understood to be modified in all cases by the term “approximately.” Furthermore, the exact numerical values ​​used herein and in the claims should be understood to constitute a particular embodiment. Efforts have been made to ensure the accuracy of the data in the examples. However, it should be understood that all measurement data inherently contain a certain level of error due to the limitations of the techniques and / or equipment used to perform the measurements. This specification uses a set of upper and lower bounds to describe specific embodiments and features. Unless otherwise indicated, it should be understood that the ranges constrained include any combination of any two values, for example, any combination of any lower and any upper bound, any combination of any two lower bounds, and / or any combination of any two upper bounds. As used herein, the indefinite articles "a" or "an" mean "at least one" unless otherwise specified or the context makes it clear that they mean something else. Accordingly, embodiments using "a reactor" or "a conversion zone" include embodiments using one, two, or three or more reactors or conversion zones, unless otherwise specified or the context clearly indicates the use of only one reactor or conversion zone. The terms “up” and “down,” “upward” and “downward,” “upper” and “lower,” “upward” and “downward,” and other similar terms used herein refer to relative positions, and are not intended to represent specific spatial locations, as devices and methods using the same terms may be equally effective at various angles or positions.

[0008] The term "hydrocarbon" means (i) any compound consisting of hydrogen atoms and carbon atoms or (ii) any mixture of two or more of such compounds of (i). The term "Cn hydrocarbon" (where n is a positive integer) means (i) any hydrocarbon compound containing a total of n carbon atoms in its molecule or (ii) any mixture of two or more of such hydrocarbon compounds of (i). Thus, C2 hydrocarbons can be ethane, ethylene, acetylene, or any mixture in any ratio of at least two of these compounds. "Cm~Cn hydrocarbon" or "Cm-Cn hydrocarbon" (where m and n are positive integers and m < n) means any one of Cm, Cm+1, Cm+2,..., Cn-1, Cn hydrocarbons or any mixture of two or more of these. Thus, "C2~C3 hydrocarbon" or "C2-C3 hydrocarbon" can be any one of ethane, ethylene, acetylene, propane, propene, propyne, propadiene, cyclopropane, and any mixture in any ratio between any two or more of these components. "Saturated C2-C3 hydrocarbon" can be ethane, propane, cyclopropane, or any mixture in any ratio of two or more of these. "Cn+ hydrocarbon" means (i) any hydrocarbon compound containing at least n carbon atoms in total in its molecule or (ii) any mixture of two or more of such hydrocarbon compounds of (i). "Cn- hydrocarbon" means (i) any hydrocarbon compound containing at most n carbon atoms in total in its molecule or (ii) any mixture of two or more of such hydrocarbons of (i). "Cm hydrocarbon stream" means a hydrocarbon stream consisting essentially of Cm hydrocarbons. "Cm-Cn hydrocarbon stream" means a hydrocarbon stream consisting essentially of Cm-Cn hydrocarbons.

[0009] For the purposes of this disclosure, the nomenclature of elements is as in Hawley's Condensed Chemical Dictionary, 16 thThis disclosure conforms to the version of the periodic table (under the new notation) provided in Ed., John Wiley & Sons, Inc., (2016), Appendix V. For example, Group 8 elements include Fe, Group 9 elements include Co, and Group 10 elements include Ni. As used herein, the term “metalloid” refers to the following elements: B, Si, Ge, As, Sb, Te, and At. In this disclosure, when a given element is indicated to exist, unless otherwise specified or the context makes it clear that it exists in a different sense, it may exist in its elemental state or as any compound thereof. The term "alkane" refers to a saturated hydrocarbon. The term "cyclic alkane" refers to a saturated hydrocarbon that contains a cyclic carbon ring in its molecular structure. Alkanes can be linear, branched, or cyclic. The term "aromatic" should be understood in accordance with the scope approved in the relevant art, and includes alkyl-substituted and unsubstituted mononuclear and polynuclear compounds. When used in relation to a device, for example, an outgoing stream coming out of a conversion zone, the term "rich" means that the material X is present in a higher concentration in the feed material supplied to the device from which the stream is extracted. When used in relation to a device, for example, an outgoing stream coming out of a conversion zone, the term "lean" means that the material X is present in a lower concentration in the feed material supplied to the device from which the stream is extracted.

[0010] The term "mixed metal oxide" refers to a composition containing oxygen atoms and at least two different metal atoms, which are mixed together on an atomic scale. For example, "mixed Mg / Al metal oxide" is substantially identical to a composition obtained by calcining Mg / Al hydrotalcite having atomically mixed O, Mg, and Al atoms and having the following general formula. [ka] In the formula, A is a counter anion with negative charge n, x is in the range of >0 to <1, and m is ≥0. A material consisting of mixed nm-sized MgO particles and nm-sized Al2O3 particles is not a mixed metal oxide because the Mg atoms and Al atoms are mixed on an nm scale, not on an atomic scale.

[0011] The term "selectivity" refers to the rate of formation of a specific compound in a catalytic reaction (based on molar carbon). For example, the statement "the alkane hydrocarbon conversion reaction has 100% selectivity for olefin hydrocarbons" means that 100% (based on molar carbon) of the alkane hydrocarbons converted in the reaction are converted to olefin hydrocarbons. When used in relation to specific reactants, the term "conversion rate" refers to the amount of reactant consumed in the reaction. For example, when the specific reactant is propane, a 100% conversion rate means that 100% of the propane is consumed in the reaction. The yield (based on molar carbon) is calculated as conversion rate × selectivity. The term "plenum" refers to the region of a reactor or separator that facilitates fluid communication between pipes or ducts that carry a hot product stream from the reactor or separator to the outlet. A reactor or separator may have multiple plenums, for example, a first plenum and a second plenum, and unless otherwise specified, the term "plenum" refers to any of the multiple plenums. The term "slurry" refers to any liquid stream containing fine particles or solids in amounts up to 20 wt%, based on the mass of the slurry. The term "sludge" refers to any liquid stream containing fine particles or solids in amounts ranging from >20 wt% to 40 wt%, based on the mass of the slurry. The term "cake" refers to any liquid stream containing fine particles or solids in amounts up to 40 wt%, based on the mass of the slurry.

[0012] overview A hydrocarbon-containing feed can be brought into contact with fluidized dehydrogenation catalyst particles within any suitable conversion zone to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed, thereby producing a conversion effluent that may contain coking catalyst particles and one or more dehydrogenated hydrocarbons. In some embodiments, the one or more dehydrogenated hydrocarbons may be ethylene, propylene, one or more butenes, one or more pentenes, or any mixture thereof, or may contain these. In some embodiments, the conversion effluent may also contain benzene. The dehydrogenation catalyst particles may contain one or more Group 8-10 elements, such as Pt, arranged on a carrier. From the conversion effluent, a first stream rich in coking catalyst particles and low in one or more dehydrogenated hydrocarbons, and a second stream rich in one or more dehydrogenated hydrocarbons and containing entrained coking catalyst particles are separated or obtained by other means. In some embodiments, the first and second streams may be separated from the conversion effluent in one or more separators or gas-solid separators. In some embodiments, the first and second streams may be separated from the conversion effluent by one or more cyclones. In some embodiments, the first and second streams may be separated from the conversion effluent in a primary separator and a secondary separator located downstream of the primary separator and in fluid communication with the primary separator, such as a primary cyclone and a secondary cyclone. In some embodiments, the first and second streams may be separated from the conversion effluent in a primary separator. In some embodiments, multiple primary separators may be arranged in parallel. In some embodiments, multiple secondary separators may be arranged in parallel. In some embodiments, multiple primary separators may be arranged in parallel, and multiple secondary separators may be arranged in parallel, with the multiple secondary separators arranged in parallel being located downstream of the multiple primary separators arranged in parallel.

[0013] The second stream may be contacted with the first quench medium to generate a cooling second stream. For example, when the separator or gas-solid separator is a cyclone, the second stream may be contacted with the first quench medium in the cyclone's plenum or in a transfer line fluidly connected to the plenum to generate a cooling second stream. The cooling second stream may be contacted with the second quench medium in the quench tower. A gas stream containing one or more dehydrogenated hydrocarbons and substantially or completely free of encompassed coking catalyst particles may be recovered from the quench tower as overhead. A condensed first quench medium stream may be recovered from the quench tower as a side draw, and at least a portion of the condensed first quench medium may be recirculated and contacted with an additional amount of the second stream to generate an additional amount of cooling second stream. A slurry stream, which may contain at least a portion of the second quench medium and encompassed coking catalyst particles, may be recovered from the quench tower as a bottom stream. In some embodiments, the lower zone within the quench tower may contain a slurry stream inventory, and as a result, the slurry stream recovered from the quench tower may be taken from this inventory. In some embodiments, the second stream may be contacted with the first quench medium immediately after the second stream leaves the primary separator or immediately before the second stream enters the secondary separator to generate a cooled second stream. The cooled second stream may then enter one or more secondary separators before being contacted with the second quench medium within the quench tower.

[0014] At least a portion of the encompassed coking catalyst particles may be separated from the slurry to provide a recovered second quench medium and a recovered encompassed coking catalyst particle stream that contains little to no encompassed coking catalyst particles. In some embodiments, at least a portion of the recovered second quench medium may be recycled to a quench tower and come into contact with an additional amount of the second cooling stream within the quench tower. In some embodiments, the catalyst particles disclosed herein may exhibit improved activity and selectivity after undergoing an additional reduction step prior to re-contact with an additional amount of hydrocarbon-containing feed. Furthermore, the post-reduction catalyst particles may maintain improved activity and selectivity for 10 minutes or more in the presence of the hydrocarbon-containing feed. Accordingly, in some embodiments, the process may optionally include a step of contacting at least a portion of the regenerated catalyst particles with a reducing gas to produce regenerated reduced catalyst particles. In this embodiment, an additional amount of hydrocarbon-containing feed may be contacted with at least a portion of the regenerated reduced catalyst particles to produce additional conversion effluents. In other embodiments, the process may include a step of contacting at least a portion of the regenerated catalyst particles and at least a portion of the regenerated reduced catalyst particles with an additional amount of hydrocarbon-containing feed to produce additional conversion effluents. In yet another embodiment, the process may include a step of contacting at least a portion of the regenerated catalyst particles, at least a portion of the regenerated reduced catalyst particles, and / or new or replenished catalyst particles to produce additional conversion effluents.

[0015] Hydrocarbon dehydrogenation process A hydrocarbon-containing feed can be brought into contact with dehydrogenation catalyst particles within any suitable conversion zone to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed, thereby producing a conversion effluent that may contain coking catalyst particles and one or more dehydrogenated hydrocarbons. The hydrocarbon-containing feed may, but is not limited to, one or more alkanes, e.g., C2-C 16 Straight-chain or branched alkanes and / or C4-C 16 Cyclic alkanes and / or one or more alkyl aromatic hydrocarbons, e.g., C8-C 16The hydrocarbons are or may contain alkyl aromatic hydrocarbons. In some embodiments, the hydrocarbon-containing feed and the dehydrogenation catalyst particles may be in contact within a conversion zone located in a continuous process, which is commonly used in fluidized bed reactors. In some embodiments, the conversion zone may be located in a riser reactor. In other embodiments, the conversion zone may be located in a downer reactor. In yet another embodiment, the conversion zone may be located in a vortex reactor. In yet another embodiment, the conversion zone may be located in a reactor, allowing the fluidized dehydrogenation catalyst particles to form a relatively high-density turbulent fluidized bed during contact with the hydrocarbon-containing feed. A relatively high-density turbulent fluidized bed refers to a fluidized bed at a gas-empty velocity that is greater than the transition velocity, expressed as the critical velocity between bubbling and the transition of the turbulent bed, but less than the transport velocity that defines the rapid fluidization or pneumatic transport regime in which the dehydrogenation catalyst particles are carried, as in a riser reactor. In another embodiment, the conversion zone may be located with a dehydrogenation reactor that includes a lower section that operates as a high-speed fluidized or turbulent bed and an upper section that operates as a riser, where the mean catalyst flow and mean gas flow are simultaneously upward.

[0016] Any number of reactors can be operated in series and / or in parallel. Any two or more types of reactors can be used in combination with each other. When two or more reactors are used, the reactors can be operated under the same and / or different conditions and can receive the same or different hydrocarbon-containing feeds. When two or more reactors are used, the reactors can be arranged in series, in parallel, or in combination thereof. In some embodiments, suitable reactors may include, but are not limited to, high gas rate riser reactors, high gas rate downer reactors, vortex reactors, reactors having a relatively high-density fluid catalyst bed at the first or lower end and a relatively low-density fluid catalyst in a riser located at the second or upper end, multiple riser reactors and / or downer reactors operated in parallel and / or sequentially and operating under the same or different conditions, or combinations thereof.

[0017] In some embodiments, dehydrogenation catalyst particles may be moved through the reaction system by air action. For example, they may be supplied to the conversion zone, supplied to the combustion zone, and transported through conduits connecting two or more locations by a carrier fluid or transport fluid. The transport fluid may, but is not limited to, a diluent, one or more reactants in gaseous form, i.e., one or more C2-C 16 Alkanes, one or more C8-C 16 The transport fluid may be an alkyl aromatic hydrocarbon, one or more dehydrogenated hydrocarbons, or a mixture thereof. Suitable transport fluids may be, but are not limited to, molecular nitrogen and volatile hydrocarbons such as methane, ethane, and / or propane, argon, carbon monoxide, carbon dioxide, water vapor, etc., or may include these. The amount of transport fluid may be sufficient to maintain the dehydrogenation catalyst particles in a fluid state and to transport them from one location, for example, a combustion zone, to a second location, for example, a conversion zone. In some embodiments, the mass ratio of dehydrogenation catalyst particles to transport fluid may range from 5, 10, 15, or 20 to 50, 60, 80, 90, or 100. Suitable injection points for the transport fluid may be formed at multiple points along any one or more transport lines connecting any two zones, such as a combustion zone and a conversion zone, or other locations.

[0018] The hydrocarbon-containing feed and dehydrogenation catalyst particles may be brought into contact at temperatures ranging from 300°C, 350°C, 400°C, 450°C, 500°C, 550°C, 600°C, 620°C, 630°C, 640°C, 650°C, 660°C, 670°C, 680°C, 690°C, or from 700°C to 725°C, 750°C, 760°C, 780°C, 800°C, 825°C, 850°C, 875°C, or 900°C. In some embodiments, the hydrocarbon-containing feed and the dehydrogenation catalyst particles may be in contact at temperatures of at least 620°C, at least 630°C, at least 640°C, at least 650°C, at least 660°C, at least 670°C, at least 680°C, at least 690°C, or at least 700°C up to 725°C, 750°C, 760°C, 780°C, 800°C, 825°C, 850°C, 875°C, or 900°C. In some embodiments, the hydrocarbon-containing feed may be introduced into a conversion zone where it may be in contact with the dehydrogenation catalyst particles for a period of time of ≤5 hours, ≤4 hours, or ≤3 hours, ≤1 hour, ≤0.5 hours, ≤0.1 hours, ≤3 minutes, ≤1 minute, ≤30 seconds, or ≤0.1 seconds. In other embodiments, a hydrocarbon-containing feed is introduced into a conversion zone where it may come into contact with dehydrogenation catalyst particles for periods ranging from 0.1 seconds, 1 second, 1.5 seconds, 2 seconds, or 3 seconds to 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 dehydrogenation catalyst particles in the conversion zone may be ≤7 minutes, ≤6 minutes, ≤5 minutes, ≤4 minutes, ≤3 minutes, ≤2 minutes, ≤1.5 minutes, ≤1 minute, ≤45 seconds, ≤30 seconds, ≤20 seconds, ≤15 seconds, ≤10 seconds, ≤7 seconds, ≤5 seconds, ≤3 seconds, ≤2 seconds, or ≤1 second. In some embodiments, the average residence time of dehydrogenation catalyst particles in the conversion zone may be longer than the average residence time of gaseous components in the conversion zone, such as the hydrocarbon-containing feed and the conversion effluent obtained therefrom. The hydrocarbon-containing feed and the dehydrogenation catalyst particles can be brought into contact under a hydrocarbon partial pressure of at least 20 kPa absolute pressure. This hydrocarbon partial pressure is the pressure of any C2-C molecules in the hydrocarbon-containing feed. 16 Alkane and both C8-C 16It is the total partial pressure of alkyl aromatic hydrocarbons. In some embodiments, the hydrocarbon partial pressure during contact of the hydrocarbon-containing feed with the dehydrogenation catalyst particles is from 20 kPa absolute, 50 kPa absolute, 100 kPa absolute, 150 kPa, 200 kPa, 300 kPa absolute, 500 kPa absolute, 750 kPa absolute, or 1,000 kPa absolute to 1,500 kPa absolute, 2,500 kPa absolute, 4,000 kPa absolute, 5,000 kPa absolute, 7,000 kPa absolute, 8,500 kPa absolute, or 10,000 kPa absolute. This hydrocarbon partial pressure is for any C2-C 16 alkane and any C8-C 16 It is the total partial pressure of alkyl aromatic hydrocarbons.

[0019] In some embodiments, the hydrocarbon-containing feed contains at least 60 vol%, at least 65 vol%, at least 70 vol%, at least 75 vol%, at least 80 vol%, at least 85 vol%, at least 90 vol%, at least 95 vol%, or at least 99 vol% of a single C2-C 16 alkane, such as propane, based on the total volume of the hydrocarbon-containing feed. The hydrocarbon-containing feed and the dehydrogenation catalyst particles can be contacted under a pressure of at least 20 kPa absolute, at least 50 kPa absolute, at least 70 kPa absolute, at least 100 kPa absolute, at least 150 kPa absolute, or at least 250 kPa absolute to 300 kPa absolute, 400 kPa absolute, 500 kPa absolute, or 1,000 kPa absolute of a single C2-C 16 alkane, such as propane. The hydrocarbon-containing feed can be contacted with the dehydrogenation catalyst particles at any weight hourly space velocity (WHSV) effective to carry out the dehydrogenation process within the conversion zone. In some embodiments, the WHSV is 0.1 h -1 , 0.2 h -1 , 0.4 h -1 , 0.8 h -1 , 2 h -1 , 4 h -1 , or 8 h -1 to 16 h-1 , 32 hours -1 , 64 hours -1 , or 100 hours -1 It may go up to. In some embodiments, both the dehydrogenation catalyst particles and the C2-C 16 Alkane and both C8-C 16 The ratio of the total amount of alkyl aromatic hydrocarbons may range from 1, 3, 5, 10, 15, 20, 25, 30, or 40 on a mass-to-mass basis to 50, 60, 70, 80, 90, 100, 110, 125, or 150.

[0020] In some embodiments, at least a portion of the fluidized dehydrogenation catalyst particles in the conversion zone may be removed and supplied to a heat input device in which the dehydrogenation catalyst particles can be heated, and the heated catalyst particles may be supplied back to the conversion zone. Since the reaction occurring in the conversion zone is endothermic, it may be beneficial to remove a portion of the fluidized dehydrogenation catalyst particles and further increase the temperature after some contact with the hydrocarbon-containing feed. Heat may be transferred indirectly from any suitable heat transfer medium supplied by an electric heater or any other suitable heater typically used to indirectly heat the catalyst particles. In another embodiment, heat may be directly applied to the conversion zone. A first stream rich in coking catalyst particles and low in one or more dehydrogenated hydrocarbons, and a second stream rich in one or more dehydrogenated hydrocarbons and containing entrained coking catalyst particles, can be separated from the conversion effluent by any suitable apparatus or obtained by other means. In some embodiments, the first and second streams can be obtained from the conversion effluent by one or more solid-gas impingement separators, such as one or more cyclone separators. In some embodiments, the cyclone separator may be or include a two-stage or “linked” configuration including both positive and negative pressure configurations. In some embodiments, suitable cyclone separators may include those disclosed in U.S. Patents 4,502,947; 4,985,136; and 5,248,411. In other embodiments, the first and second streams are obtained from the conversion effluent via a “T” conduit that allows the majority of the coking catalyst particles to flow in one direction by gravity and the gaseous components to flow in the other direction.

[0021] In some embodiments, a first stream rich in coking catalyst particles and low in one or more dehydrogenated hydrocarbons may contain >95%, >96%, >97%, >98%, or >99%, >99.9%, >99.99%, or >99.999% dehydrogenated catalyst particles in the conversion effluent. As a result, in some embodiments, a second stream rich in one or more dehydrogenated hydrocarbons and containing entrained coking catalyst particles may contain dehydrogenated catalyst particles in the conversion effluent ranging from >0.001%, >0.005%, >0.01%, >0.05%, >0.1%, >0.5%, >1%, or >1.5% to 3%, 4%, or 5%. A second stream may be in contact with the first quench medium to generate a cooling second stream. For example, when the separator or gas-solid separator is a cyclone, the second stream may be in contact with the first quench medium within the plenum of the cyclone. When multiple cyclones are used in series, the second stream may be in contact within the plenum that is in fluid communication with the last cyclone of the multiple cyclones. In other embodiments, the second stream may be in contact within a transfer line that is in fluid communication with the outlet of the separator or gas-solid separator and the quench tower. In some embodiments, the first quench medium may be in the gas phase, liquid phase, or a gas-liquid mixture when in contact with the second stream. In some embodiments, the first quench medium may be in the liquid phase when in contact with the second stream and then entirely in the gas phase after contact with the second stream.

[0022] In some embodiments, the second stream may be at a temperature of ≥600°C, ≥620°C, ≥630°C, ≥640°C, ≥650°C, ≥660°C, ≥670°C, ≥680°C, or ≥700°C upon initial contact with the first quench medium. In some embodiments, the cooling second stream may be at a temperature at least 10°C, at least 20°C, at least 30°C, at least 60°C, 80°C, or at least 100°C lower than the temperature of the second stream before contact with the first quench medium. In some embodiments, the cooling second stream may be at a temperature in the range of 500°C, 515°C, 530°C, 550°C, or 560°C to 575°C, 590°C, 600°C, 610°C, or 620°C. In some embodiments, the cooling second stream may be at a temperature from ≥500°C or ≥550°C to <620°C. A second cooling stream may come into contact with a second quench medium within a contact zone located within the quench tower. In some embodiments, the second quench medium may come into contact with the second cooling stream countercurrently within the quench tower. For example, the second cooling stream may be introduced into the quench tower below the second quench medium and flow upward within the quench tower, while the second quench medium flows downward within the quench tower. In some embodiments, the second quench medium may be introduced into the quench tower by one or more nozzles.

[0023] A gas stream containing one or more dehydrogenated hydrocarbons and substantially or completely free of encompassed coking catalyst particles may be recovered as overhead from the quench tower. In some embodiments, the velocity of this gas stream at the upper end or zone of the quench tower may be sufficiently slow that coking catalyst particles are no longer encompassed in it, resulting in at least the majority of the encompassed catalyst particles falling downwards and being encompassed into the second quench medium. In some embodiments, a gas stream substantially free of encompassed coking catalyst particles may contain some encompassed coking catalyst particles in amounts of <0.001 wt%, <0.01 wt%, <0.1 wt%, <1 wt%, or <10 wt%. In some embodiments, the temperature of the gas stream may be in the range of 50°C, 100°C, or 150°C to 200°C, 250°C, or 300°C. The condensed first quench medium stream is recovered as a side draw from the quench tower, and at least a portion of this condensed first quench medium may be recirculated and come into contact with an additional amount of the second stream. In some embodiments, the condensed first quench medium stream may be at a temperature ranging from 50°C, 60°C, or 70°C to 80°C, 100°C, or 120°C.

[0024] A slurry stream, which may contain at least a portion of the second quench medium and the accompanying coking catalyst particles, can be recovered as a lower stream from the quench tower. In some embodiments, the lower zone within the quench tower may contain an inventory of the slurry stream. As a result, the slurry stream recovered from the quench tower may be taken from this inventory. The slurry stream may be at a temperature ranging from 150°C, 200°C, or 250°C to 300°C, 400°C, or 500°C when recovered from the quench tower. In some embodiments, the quench tower may include one or more internal structures that can facilitate the separation of the cooling second stream into a gas stream, a first quench medium stream, and a slurry stream. Examples of internal structures include, but are not limited to, trays, grids, packings, or any combination thereof. Examples of trays include, but are not limited to, fixed valve trays, jet tab trays, sieve trays, dual-float trays, baffle trays, square iron trays, draw-off trays, shed deck trays, disc trays, donut trays, side-by-side-splash trays, or any combination thereof. Suitable fixed valve trays, sieve trays, dual-float trays, and grids are described in Distillation Design, Henry Z. Kister, McGraw-Hill Inc., 1992, pp. 262-265 and 464-466. Suitable jet tub trays include those described in International Publication No. WO2011 / 014345. In some embodiments, the quench tower disclosed herein is also known as, or sometimes referred to as, a primary separator.

[0025] In some embodiments, if the process conditions within the quench tower are such that encompassed coking catalyst particles may remain in the gas stream recovered as overhead from the quench tower, the gas stream may undergo further processing. In some embodiments, if the gas stream recovered as overhead from the quench tower contains any encompassed coking catalyst particles, the gas stream may be further separated by one or more electrostatic dust collectors, one or more filters, one or more screens, one or more membranes, wet gas scrubbers, contact with absorbent scavengers, one or more additional quench towers, one or more electrocyclones, one or more hydrocyclones, one or more centrifuges, one or more plates or cones, or any combination thereof, to remove at least a portion of the encompassed coking catalyst particles from the gas stream. In some embodiments, if the hydrocarbon-containing feed contains water and / or water is produced during the dehydrogenation reaction, resulting in the conversion effluent containing water, the water stream may be recovered from the quench tower as a second side draw from the quench tower. In these embodiments, the water stream is removed from the process, and a portion of the water stream may be recirculated to the upper section of the quench tower to further facilitate the separation of the encompassed coking catalyst pulverized, the first quench medium, and the second quench medium, or a combination thereof, from the conversion effluent within the quench tower. In some embodiments, the water stream may be vaporized and recirculated to the inlet of the conversion zone as hydrocarbon co-feed.

[0026] The first and second quenching media are, independently, one or more aromatic hydrocarbons, water, or mixtures thereof, or may include these. In some embodiments, the aromatic hydrocarbons may be 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 standard boiling point of <580°C, or may include these. In some embodiments, the polycyclic aromatic hydrocarbons may have standard boiling points of <580°C, <550°C, <500°C, <400°C, <300°C, <200°C, or <100°C. Suitable aromatic hydrocarbons include, but are not limited to, benzene, toluene, cumene, ethylbenzene, xylene, methylethylbenzene, trimethylbenzene, methylnaphthalene, A-100 solvent mixture, A-150 solvent mixture, A-200 solvent mixture, A-250 solvent mixture, intermediate distillates, ultra-low sulfur diesel, heavy diesel fuel, or any mixture thereof, or may include these. In some embodiments, the second quench medium may have low surface tension, high thermal stability, and low toxicity. In some embodiments, the first quench medium may be, but not limited to, benzene or contain benzene, and the second quench medium may be, but not limited to, A-100 solvent mixture, A-150 solvent mixture, A-200 solvent mixture, A-250 solvent mixture, intermediate distillates, ultra-low sulfur diesel, heavy diesel fuel, or any mixture thereof or contain these.

[0027] 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 compositions of the first and second quench mediums may include one or more identical components and one or more different components, resulting in some parts of the compositions of the first and second quench mediums being the same and some parts of the compositions being different. In some embodiments, the second quench medium may have a standard boiling point higher than that of the first quench medium. In some embodiments, the second quench medium may have a standard boiling point lower than that of the first quench medium. In some embodiments, the first quench medium may be benzene or contain benzene, and the second quench medium may contain one or more polycyclic aromatic hydrocarbons. In some embodiments, the first quench medium may not be used. In some embodiments, the mass ratio of the first quench medium to the second stream may range from 0.01, 0.05, or 0.08 to 0.1, 0.2, or 0.3. In some embodiments, the mass ratio of the second quench medium to the second cooling stream may range from 0.01, 0.1, or 0.3 to 0.5, 1, 2, or 5. In some embodiments, the mass ratio of the first quench medium to the second quench medium may range from 0.002, 0.02, or 0.2 to 1, 5, or 10.

[0028] At least a portion of the encompassed coking catalyst particles may be separated from the slurry, resulting in a recovered second quench medium and a recovered encompassed coking catalyst particle stream with little to no encompassed coking catalyst particles. In some embodiments, at least a portion of the recovered second quench medium may be recirculated to a quench tower, where it may come into contact with an additional amount of the second cooling stream. In some embodiments, encompassed coking catalyst particles may be separated from the slurry by one or more liquid-solid separators. Suitable liquid-solid separators may include, but are not limited to, one or more filters, one or more membranes, one or more screens or strainers, one or more separator drums, one or more centrifuges, one or more sedimentation tanks, or any combination thereof. In some embodiments, two or more liquid-solid separators may be used in parallel. As a result, at least one first liquid-solid separator may be operated in filtration mode while at least one second liquid-solid separator is operated in backwash mode to remove the collected coking catalyst particles from the separators. The filtration mode and backwash mode may be alternated periodically. In some embodiments, when encompassed coking catalyst particles are separated from the slurry using two or more filters, the backwash mode may include at least one compressed gas pulse through at least one filter, which is a backwash mode in the reverse direction to remove the coking catalyst particles separated from the filters. In some embodiments, the combustion gas recovered from the catalyst regeneration step may be used as a gas for backwashing the filter, with or without an optional step to remove any encompassed catalyst particles from the combustion gas. In some embodiments, a liquid stream may be used for backwashing the filter. In some embodiments, a suitable process for recovering encompassed coking catalyst particles from the slurry may include the process disclosed in U.S. Patent No. 7,375,143.

[0029] In some embodiments, at least a portion of the coking catalyst particles in the recovered encompassed coking catalyst particle stream may be transported to a metal recycling facility. In these embodiments, at least a portion of Group 8-10 elements may be recovered from the coking catalyst particles in the recovered encompassed coking catalyst particle stream. In some embodiments, at least a portion of the coking catalyst particles transported to the metal recycling facility may be transported to the facility in the form of sludge or cake. In some embodiments, the liquid in the sludge or cake may contain at least a portion of the second quench medium. In other embodiments, the encompassed coking catalyst particles may be substantially separated from the second quench medium and transported in the form of fluid particles. In yet another embodiment, the encompassed coking catalyst particles may be substantially separated from the second quench medium and mixed with another liquid medium to form another slurry, sludge or cake that can be transported to the metal recycling facility. The recovered Group 8-10 elements(s) can be reused to produce new catalyst particles, purified, and then sold as a commodity or used for any other desired purpose. In some embodiments, at least a portion of Group 8-10 elements can be recovered from coking catalyst particles by any suitable process or combination of processes. Suitable processes for recycling at least a portion of Group 8-10 elements include, but are not limited to, those described in U.S. Patent No. 7,033,480; U.S. Patent Application Publication No. 2004 / 0219082; UK Patent Application Publication No. GB829972A; Chinese Patent No. CN101760627; and / or Chinese Patent Publication No. CN104831071A.

[0030] At least a portion of the coking catalyst particles in the first stream and, optionally, at least a portion of the coking catalyst particles in the recovered and entrained coking catalyst particle stream may be brought into contact with one or more oxidants and, optionally, one or more hydrocarbon fuels in the combustion zone to cause combustion of coke and, if present, at least a portion of the fuel, thereby generating a combustion effluent that may contain regenerated catalyst particles and combustion gases with less coke. The oxidizer may be, but is not limited to, molecular oxygen, ozone, carbon dioxide, water vapor, or a mixture thereof. In some embodiments, the amount of oxidizer used may exceed the amount required for 100% combustion of coke on the coking catalyst particles to increase the rate of coke removal from the catalyst particles, thereby reducing the time required for coke removal and potentially leading to an increased yield of the upgraded product produced within a given time. The optional fuel may be, but is not limited to, molecular hydrogen, methane, ethane, propane, or a mixture thereof. The optional fuel may be mixed with an inert gas, such as argon, neon, helium, molecular nitrogen, methane, or a mixture thereof.

[0031] Coking catalyst particles and an oxidizer, and if present, fuel, can be brought into contact with each other at temperatures ranging from 500°C, 550°C, 600°C, 650°C, 700°C, 750°C, or 800°C to 900°C, 950°C, 1,000°C, 1,050°C, or 1,100°C to generate regenerated catalyst particles. In some embodiments, coking catalyst particles and an oxidizer, and if present, fuel, can be brought into contact with each other at temperatures ranging from 500°C to 1,100°C, 600°C to 1,100°C, 600°C to 1,000°C, 650°C to 950°C, 700°C to 900°C, or 750°C to 850°C to generate regenerated catalyst particles. The coking catalyst particles, the oxidizer, and, if present, the fuel, may be in contact with each other under oxidizer partial pressures ranging from 20 kPa absolute pressure, 50 kPa absolute pressure, 70 kPa absolute pressure, 100 kPa absolute pressure, 150 kPa absolute pressure, or from 200 kPa absolute pressure to 300 kPa absolute pressure, 500 kPa absolute pressure, 750 kPa absolute pressure, or 1,000 kPa absolute pressure. The coking catalyst particles and oxidizer, and if present, the fuel, may be in contact with each other for a time range from 15 seconds, 30 seconds, 1 minute, 2 minutes, or 5 minutes to 10 minutes, 20 minutes, 30 minutes, 40 minutes, 50 minutes, or 60 minutes. For example, the coking catalyst particles and oxidizer, and if present, the fuel, may be in contact with each other for a time range from 2 seconds to 50 minutes, 55 minutes, or 60 minutes. In some embodiments, the coking catalyst particles and oxidizer, and if present, the fuel, may be in contact for a time sufficient to remove ≥50 wt%, ≥75 wt%, or ≥90 wt%, or >99% of any coke placed on the catalyst particles.

[0032] In some embodiments, the time that coking catalyst particles, oxidizer, and, if present, fuel are in contact with each other may be longer than the time that the catalyst particles are in contact with the hydrocarbon-containing feed to produce conversion effluent. For example, the time that coking catalyst particles and oxidizer and, if present, fuel are in contact with each other may be at least 50%, at least 100%, at least 300%, at least 500%, at least 1,000%, at least 10,000%, at least 30,000%, at least 50,000%, at least 75,000%, at least 100,000%, at least 250,000%, at least 500,000%, at least 750,000%, at least 1,000,000%, at least 1,250,000%, at least 1,500,000%, at least 1,800,000%, at least 2,500,000%, at least 3,500,000%, or 4,140,000% longer than the time that the catalyst particles are in contact with the hydrocarbon-containing feed to produce conversion effluent. While we do not wish to be constrained by theory, it is conceivable that at least a portion of the Group 8-10 elements, such as Pt, arranged on the support in coking catalyst particles may aggregate compared to the Group 8-10 elements arranged on the support in the catalyst particles before contact with the hydrocarbon-containing feed. It is conceivable that at least a portion of the Group 8-10 elements may redisperse around the support during the combustion of at least a portion of the coke on the coking catalyst particles. Any redispersion of at least a portion of the aggregated Group 8-10 elements can enhance the activity of the catalyst particles and improve their selectivity over multiple cycles.

[0033] In some embodiments, at least a portion of the Group 8-10 elements in the regenerated catalyst particles, such as Pt, may be in a higher oxidation state compared to the Group 8-10 elements in catalyst particles contacted with a hydrocarbon-containing feed and compared to the Group 8-10 elements in coking catalyst particles. As a result, as described above, in some embodiments, the process may include a step of contacting at least a portion of the regenerated catalyst particles with a reducing gas to produce regenerated reduced catalyst particles. Suitable reducing gases (reducing agents) are, but are not limited to, molecular hydrogen, carbon monoxide, methane, ethane, ethylene, propane, propylene, water vapor, or mixtures thereof, or may include these. In some embodiments, the reducing agent may be mixed with an inert gas, such as argon, neon, helium, molecular nitrogen, or a mixture thereof. In these embodiments, at least a portion of the Group 8-10 elements in the regenerated reduced catalyst particles may be reduced to a lower oxidation state, e.g., to an elemental state, compared to the Group 8-10 elements in the regenerated catalyst particles. In these embodiments, an additional amount of hydrocarbon-containing feed may be contacted with at least a portion of the regenerated catalyst particles and / or at least a portion of the regenerated reduced catalyst particles.

[0034] In some embodiments, the regenerated catalyst particles and reducing gas may be in contact at temperatures ranging from 400°C, 450°C, 500°C, 550°C, 600°C, 620°C, 650°C, or 670°C to 720°C, 750°C, 800°C, or 900°C. The regenerated catalyst particles and reducing gas may be in contact for times ranging from 1 second, 5 seconds, 10 seconds, 20 seconds, 30 seconds, or 1 minute to 10 minutes, 30 minutes, or 60 minutes. The regenerated catalyst particles and reducing gas may be in contact at reducing agent partial pressures ranging from 20 kPa absolute pressure, 50 kPa absolute pressure, 70 kPa absolute pressure, 100 kPa absolute pressure, 150 kPa absolute pressure, or 200 kPa absolute pressure to 300 kPa absolute pressure, 500 kPa absolute pressure, 750 kPa absolute pressure, or 1,000 kPa absolute pressure. In some embodiments, when a hydrocarbon-containing fuel is introduced into the combustion zone, the catalyst may be further deactivated compared to the combustion of coke placed on catalyst particles in the absence of the hydrocarbon fuel. In such embodiments, the regenerated catalyst particles can be further completely regenerated and their activity improved by immersion in dry air. For example, the regenerated catalyst particles can be further completely reduced by contact with an oxidizing gas containing <5 mol%, <3 mol%, <1 mol%, <0.5 mol%, or <0.1 mol% H2O for a period of at least 30 seconds, at least 1 minute, or at least 5 minutes at temperatures ranging from 620°C, 650°C, 675°C, 700°C, or 750°C to 775°C, 800°C, 850°C, 900°C, 950°C, or 1,000°C. In some embodiments, regenerated catalyst particles and an oxidizing gas containing <5 mol% H2O may be in contact with each other for durations of ≤2 hours, ≤1 hour, ≤30 minutes, ≤10 minutes, ≤5 minutes, ≤1 minute, ≤30 seconds, ≤10 seconds, ≤5 seconds, or ≤1 second to generate an oxidation precursor catalyst. When regenerated catalyst particles are in contact with an oxidizing gas containing <5 mol% H2O and also with a reducing gas to generate regenerated reduced catalyst particles, contact with the oxidizing gas may occur before contact with the reducing gas. Surprisingly and unexpectedly, it was found that contacting a regenerating catalyst generated in the presence of an arbitrary hydrocarbon fuel with an oxidizing gas containing 5 mol% or less of H2O significantly improved the activity and / or selectivity of the regenerating catalyst. While we do not wish to be constrained by theory, it is conceivable that H2O present in the oxidizing gas or generated as a combustion product may significantly reduce the effectiveness of the redispersion of group 8-10 elements, such as Pt, and consequently, the effectiveness of the regenerating catalyst.

[0035] In some embodiments, a first portion of coking catalyst particles in a first stream rich in coking catalyst particles may be supplied to a combustion zone for catalyst particle regeneration, and a second portion of coking catalyst particles in the first stream may be returned to a direct conversion zone for recirculation. In some embodiments, if the process includes both regeneration and reduction, a first portion of coking catalyst particles in a first stream rich in coking catalyst particles may be supplied to a combustion zone for catalyst particle regeneration, and a second portion of coking catalyst particles may be supplied to a reduction zone. In other embodiments, if the process includes both regeneration and reduction, a first portion of coking catalyst particles in a first particle stream rich in coking catalyst particles may be supplied to a combustion zone for catalyst particle regeneration, a second portion of coking catalyst particles may be returned to a direct conversion zone for recirculation, and a third portion of coking catalyst particles may be supplied to a reduction zone. In any of these embodiments, some coking catalyst particles, some regenerating catalyst particles, and / or at least some regenerating reducing catalyst particles may be continuously or intermittently removed from the process, and new or make-up catalyst particles may be introduced into the process. Removal of catalyst particles may occur as the catalyst particles decompose and become smaller, inactivated, and / or begin to convert the hydrocarbon-containing feed at an undesirable conversion rate. In some embodiments, at least some of the removed catalyst particles may be transported to a metal recycling facility where metals may be recovered.

[0036] At least a portion of the coking catalyst particles, at least a portion of the regenerated catalyst particles, at least a portion of the regenerated reduction catalyst particles, new or replenished catalyst particles, or a mixture thereof may be in contact with an additional amount of hydrocarbon-containing feed in the conversion zone to generate additional conversion effluent. In some embodiments, the cycle time from contact between the hydrocarbon-containing feed and the catalyst particles to contact with the additional amount of hydrocarbon-containing feed, at least a portion of the regenerated catalyst particles and / or regenerated reduction catalyst particles, and optionally new or replenished catalyst particles may be ≤5 hours, ≤4 hours, ≤3 hours, ≤2 hours, or ≤70 minutes, for example, 1 to 70 minutes or 5 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 encompassing gaseous components from the catalyst particles. In some embodiments, coking catalyst particles may be contacted with a stripping fluid before contact with an oxidizing agent to remove at least a portion of any upgraded encompassing hydrocarbons and / or molecular hydrogen and / or other gaseous components. Similarly, regenerated catalyst particles and / or regenerated reduction catalyst particles may be contacted with a stripping gas to remove at least a portion of any encompassing combustion gas or reduction gas from them. In some embodiments, the stripping gas may be inert under dehydrogenation, combustion, and / or reduction conditions. Suitable stripping fluids may be, but are not limited to, molecular nitrogen, helium, argon, carbon dioxide, water vapor, methane, or mixtures thereof, or contain these. The stripping gas is used with coking catalyst particles, regenerated catalyst particles, and / or regenerated reduction catalyst particles, and approximately 0.1 m³ per cubic meter of catalyst particles. 3 ~10m 3 They can be contacted in a volume ratio of stripping gas.

[0037] As described above, the first cycle begins when catalyst particles come into contact with a hydrocarbon-containing feed, and then comes into contact with at least an oxidizer to generate regenerated catalyst particles, or comes into contact with at least an oxidizer and an optional reducing gas to generate regenerated reduced catalyst particles, and the first cycle ends when the regenerated catalyst particles or regenerated reduced catalyst particles come into contact with an additional amount of hydrocarbon-containing feed. For example, if some sweeping fluid is used to strip residual hydrocarbons from the coking catalyst particles, the time that the fluid is used will be included in the cycle time. In one embodiment, a riser structure may be provided, in which hydrocarbon-containing feed can be mixed with a diluent gas within the riser and brought into contact with heated fluid catalyst particles. The diluent gas may be, but not limited to, molecular nitrogen, methane, water vapor, molecular hydrogen, or mixtures thereof, or contain these. The mixture is moved through the riser by convection or otherwise carries the fluid catalyst particles, and as the mixture flows through the riser, it can come into contact and react to produce a conversion effluent containing one or more dehydrogenated hydrocarbons and coking catalyst particles. The residence time of the hydrocarbon-containing feed and fluid catalyst particles may be sufficient to achieve a desired conversion rate of the hydrocarbon-containing feed to one or more dehydrogenated hydrocarbons. The specific design of the riser, including its construction and dimensions, may be determined at least in part by the intended chemistry, but typically may require a velocity exceeding 4.5 m / s under average gas composition. Suitable systems for carrying out the dehydrogenation of hydrocarbon-containing feeds include technically well-known systems such as fluid reactors disclosed in U.S. Patent Nos. 3,888,762; 7,102,050; 7,195,741; 7,122,160; and 8,653,317; U.S. Patent Application Publications 2004 / 0082824; 2008 / 0194891; and International Publications WO2001 / 85872; WO2004 / 029178; and WO2005 / 077867.

[0038] dehydrogenation catalyst particles The dehydrogenation catalyst particles are distributed as follows, based on the mass of the carrier: 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%, and 0.06 wt%. It may contain, 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 Group 8 to 10 elements, such as Pt, arranged on a carrier. In some embodiments, the catalyst particles are based on the mass of the carrier and are ≤5.5wt%, ≤4.5wt%, ≤3.5wt%, ≤2.5wt%, ≤1.5wt%, ≤1wt%, ≤0.9wt%, ≤0.8wt%, ≤0.7wt%, ≤0.6wt%, ≤0.5wt%, ≤0.4wt%, ≤0.3wt%, ≤0.2wt%, ≤0.15wt%, ≤0.1wt%, ≤0.09wt%, ≤0.08wt%, ≤0 It may contain group 8-10 elements, such as Pt, arranged on a carrier in amounts of 0.07 wt%, ≤0.06 wt%, ≤0.05 wt%, ≤0.04 wt%, ≤0.03 wt%, ≤0.02 wt%, ≤0.01 wt%, ≤0.009 wt%, ≤0.008 wt%, ≤0.007 wt%, ≤0.006 wt%, ≤0.005 wt%, ≤0.004 wt%, ≤0.003 wt%, or ≤0.002 wt%.In some embodiments, the catalyst particles may contain, based on the mass of the carrier, group 8 to 10 elements disposed on the carrier in amounts of >0.001, >0.003 wt%, >0.005 wt%, >0.007, >0.009 wt%, >0.01 wt%, >0.02 wt%, >0.04 wt%, >0.06 wt%, >0.08 wt%, >0.1 wt%, >0.13 wt%, >0.15 wt%, >0.17 wt%, >0.2 wt%, >0.23, >0.25 wt%, >0.27 wt%, or >0.3 wt% and <0.5 wt%, <1 wt%, <2 wt%, <3 wt%, <4 wt%, <5 wt%, or <6 wt%. In some embodiments, the Group 8-10 elements may be, but are not limited to, Fe, Co, Ni, Ru, Pd, Os, Ir, Pt, combinations thereof, or mixtures thereof, or include them. In at least one embodiment, the Group 8-10 elements may be Pt or include Pt. In some embodiments, the catalyst particles may optionally contain two or more Group 8-10 elements, for example, Pt and Ni and / or Pd. When two or more Group 8-10 elements are arranged on the support, the catalyst particles are distributed in amounts of 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%, and 0.05 wt%, based on the mass of the support. The catalyst particles may contain the total amount of all Group 8-10 elements arranged on the carrier, ranging from 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 from 1 wt% to 2 wt%, 3 wt%, 4 wt%, 5 wt%, or 6 wt%. In some embodiments, the active components of the catalyst particles may contain Group 8-10 elements, which may have the ability to cause one or more dehydrogenations of a hydrocarbon feed.

[0039] In some embodiments, catalyst particles may include a promoter placed on the support, up to 10 wt%, based on the mass of the support. The promoter may be, but not limited to, Sn, Ga, Zn, Ge, In, Re, Ag, Au, Cu, combinations thereof, or mixtures thereof, or include them. In at least one embodiment, the promoter may be Sn or include Sn. In some embodiments, the promoter may be associated with Pt and / or Ni and / or Pd, if present. For example, a promoter and Pt placed on the support may form a Pt-promoter cluster that can be dispersed on the support. The promoter can improve the selectivity / activity / lifetime of the catalyst particles for a given upgraded hydrocarbon. In some embodiments, the promoter can improve the propylene selectivity of the catalyst particles when the hydrocarbon-containing feed includes propane. The catalyst particles may contain a promoter in amounts ranging from 0.01 wt%, 0.1 wt%, 0.2 wt%, 0.3 wt%, 0.4 wt%, 0.5 wt%, 0.6 wt%, 0.7 wt%, 0.8 wt%, 0.9 wt%, or from 1 wt% to 3 wt%, 5 wt%, 7 wt%, or 10 wt%, based on the mass of the carrier. In some embodiments, the catalyst particles may contain one or more alkali metal elements disposed on the support in an amount up to 5 wt% based on the mass of the support. The alkali metal elements, if present, may be, but not limited to, Li, Na, K, Rb, Cs, combinations thereof, or mixtures thereof, or include them. In at least one embodiment, the alkali metal elements may be K and / or Cs, or include them. In at least some embodiments, the alkali metal elements, if present, can improve the selectivity of the catalyst particles for a given upgraded hydrocarbon. The catalyst particles may contain alkali metal elements in amounts 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 from 1 wt% to 2 wt%, 3 wt%, 4 wt%, or 5 wt%, based on the mass of the carrier.

[0040] The carrier may be, but is not limited to, one or more Group 2 elements, combinations thereof, or mixtures thereof. In some embodiments, Group 2 elements may exist in elemental form. In other embodiments, Group 2 elements may exist in compound form. For example, Group 2 elements may exist as oxides, phosphates, halides, halates, sulfates, sulfides, borates, nitrides, carbides, aluminates, aluminosilicates, silicates, carbonates, metaphosphates, selenides, tungstates, molybdates, chromates, chromates, dichromates, or silide. In some embodiments, mixtures of any two or more compounds that may contain Group 2 elements may exist in different forms. For example, the first compound may be an oxide and the second compound may be an aluminate. In this case, the first and second compounds may contain the same or different Group 2 elements. The carrier is classified based on its mass as follows: ≥0.5wt%, ≥1wt%, ≥2wt%, ≥3wt%, ≥4wt%, ≥5wt%, ≥6wt%, ≥7wt%, ≥8wt%, ≥9wt%, ≥10wt%, ≥11wt%, ≥12wt%, ≥13wt%, ≥14wt%, ≥15wt%, ≥16wt%, ≥17wt%, ≥18wt%, ≥19wt%, ≥20wt%, ≥21wt% It may contain Group 2 elements in the following proportions: %, ≥22wt%, ≥23wt%, ≥24wt%, ≥25wt%, ≥26wt%, ≥27wt%, ≥28wt%, ≥29wt%, ≥30wt%, ≥35wt%, ≥40wt%, ≥45wt%, ≥50wt%, ≥55wt%, ≥60wt%, ≥65wt%, ≥70wt%, ≥75wt%, ≥80wt%, ≥85, or ≥90wt%. In some embodiments, the carrier may contain Group 2 elements in amounts ranging 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%. In some embodiments, the molar ratio of present Group 2 elements to Group 8-10 elements (multiple elements are possible) is 0.24, 0.5, 1, 10, 50, 100, 300, 450, 600, 800, 1,000, 1,200, 1,500, 1,700, or 2,000 to 3,000, 3,500, 4,000, 4,500, 5,000, 5,500, 6,000, 6,500, 7,000, 7,500, 8,000, 8,500, 9,000, 9,500, 10,000, 1 It may be in the range of 5,000, 20,000, 25,000, 30,000, 35,000, 40,000, 45,000, 50,000, 55,000, 60,000, 65,000, 70,000, 75,000, 80,000, 85,000, 90,000, 95,000, 100,000, 200,000, 300,000, 400,000, 500,000, 600,000, 700,000, 800,000, or up to 900,000.

[0041] In some embodiments, the support may be in the form of a mixed group 2 element / Al metal oxide containing a group 2 element and Al, and having O, Mg, and Al atoms mixed on an atomic scale. In some embodiments, the support may be or contain a group 2 element and Al in the form of one or more oxides of a group 2 element and Al2O3, which may be mixed on an nm scale. In some embodiments, the support may be or contain an oxide of a group 2 element, e.g., MgO, and Al2O3 mixed on an nm scale. In some embodiments, the carrier may be a first amount of group 2 elements and Al in the form of a mixed group 2 element / Al metal oxide, and a second amount of group 2 elements in the form of an oxide of a group 2 element. In these embodiments, the mixed group 2 element / Al metal oxide and the oxide of a group 2 element may be mixed on an nm scale, and the group 2 elements and Al in the mixed group 2 element / Al metal oxide may be mixed on an atomic scale. In other embodiments, the support may be 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 a second amount of Al in the form of Al2O3, or may contain these. In these embodiments, the mixed group 2 element / Al metal oxide, the oxide of a group 2 element, and Al2O3 may be mixed on an nm scale, and the group 2 element and Al in the mixed group 2 element / Al metal oxide may be mixed on an atomic scale. In some embodiments, when the carrier contains a group 2 element and Al, the mass ratio of the group 2 element to Al in the carrier may be in the range of 0.001, 0.005, 0.01, 0.05, 0.1, 0.15, 0.2, 0.3, 0.5, 0.7, or from 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 carrier contains Al, the carrier may contain Al in amounts ranging 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 mass of the carrier.

[0042] In some embodiments, the support is, but is not limited to, the following compound: Mg w Al2O 3+w (w is a positive number); Ca x Al2O 3+x (x is a positive number); Sr y Al2O 3+y (y is a positive number); Ba z Al2O 3+z (z is a positive number); BeO; MgO; CaO; BaO; SrO; BeCO3; MgCO3; CaCO3; SrCO3, BaCO3; CaZrO3; Ca7ZrAl6O 18 CaTiO3;Ca7Al6O 18 Ca7HfAl6O 18;BaCeO3; may consist of 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 elements include Mg, and at least a portion of the group 2 elements may be in the form of MgO or mixed oxides containing MgO. In some embodiments, the support may be, but not limited to, a MgO-Al2O3 mixed metal oxide or contain thereof. In some embodiments, when the support is a MgO-Al2O3 mixed metal oxide, the support may have a molar ratio of Mg to Al equal to 20, 10, 5, 2, 1 to 0.5, 0.1, or 0.01. Mg w Al2O 3+w (where w is a positive number) may have a molar ratio of Mg to Al ranging from 0.5, 1, 2, 3, 4, or 5 to 6, 7, 8, 9, or 10 when present as a carrier or as a component of a carrier. In some embodiments, Mg w Al2O 3+w This may include MgAl2O4, Mg2Al2O5, or a mixture thereof. Ca x Al2O 3+x (where x is a positive number) may have a molar ratio of Ca to Al in the range of 1:12, 1:4, 1:2, 2:3, 5:6, 1:1, 12:14, or 1.5:1 when present as a carrier or as a component of a carrier. In some embodiments, Ca x Al2O 3+x This may include tricalcium aluminate, dodecalcium heptaluminate, monocalcium aluminate, monocalcium dialuminate, monocalcium hexaluminate, dicalcium aluminate, pentacalcium trialuminate, tetracalcium trialuminate, or any mixture thereof. Sr y Al2O 3+y (where y is a positive number) may have a molar ratio of Sr to Al ranging from 0.05, 0.3, or 0.6 to 0.9, 1.5, or 3 when present as a carrier or as a component of a carrier. z Al2O 3+z(where z is a positive number) may have a molar ratio of Ba to Al ranging from 0.05, 0.3, or 0.6 to 0.9, 1.5, or 3 when present as a carrier or as a component of a carrier.

[0043] In some embodiments, the carrier may also include, but not limited to, at least one metallic element and / or at least one metalloid element selected from groups other than Group 2 and Group 10, and / or at least one mixture thereof. This 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. If the carrier also contains a compound comprising a metallic element and / or metalloid element selected from groups other than Group 2 and Group 10 (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), the compound may exist in the carrier as an oxide, phosphate, halide, halate, sulfate, sulfide, borate, nitride, carbide, aluminate, aluminosilicate, silicate, carbonate, metaphosphate, selenide, tungstate, molybdate, chromate, chromate, dichromate, or silicide. In some embodiments, at least one metallic element and / or at least one metalloid element and / or at least one compound thereof (where 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) selected from groups other than Group 2 and Group 10 may be, but not limited to, one or more rare earth elements, i.e., elements having 21, 39, or 57-71 atoms, or may include such elements.

[0044] If the carrier contains at least one metallic element and / or at least one metalloid element selected from groups other than Group 2 and Group 10 and / or at least one compound thereof (where 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 the at least one metallic element and / or at least one metalloid element selected from groups other than Group 2 and Group 10 can, in some embodiments, function as a binder and may be referred to as a “binder”. Regardless of whether at least one metallic element and / or at least one metalloid element selected from groups other than Group 2 and Group 10, and / or at least one compound thereof (where 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), for the sake of clarity and simplicity of explanation, in this specification, at least one metallic element and / or at least one metalloid element selected from groups other than Group 2 and Group 10 will hereafter be referred to as a "binder." In the literature, the compound referred to as a "binder" in this specification is also known as a filler, matrix, additive, etc. In some embodiments, the carrier may contain a binder in an amount ranging 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 mass of the carrier. In some embodiments, suitable compounds containing a binder include, but are not limited to, the following compounds: B2O3, AlBO3, Al2O3, SiO2, ZrO2, TiO2, SiC, Si3N4, aluminosilicate, zinc aluminosilicate, ZnO, VO, V2O3, VO2, V2O5, Ga s O t In u O v , Mn2O3, Mn3O4, 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 one or more mixtures and combinations thereof, or may include these.

[0045] The catalyst particles may have median particle sizes ranging from 1 μm, 5 μm, 10 μm, 20 μm, 40 μm, or 60 μm to 80 μm, 100 μm, 115 μm, 130 μm, 150 μm, 200 μm, 300 μm to 400 μm, or 500 μm. The catalyst particles were measured according to ASTM D7481-18, modified using 10, 25, or 50 mL graduated cylinders instead of 100 or 250 mL graduated cylinders, and measured at 0.3 g / cm³. 3 , 0.4 g / cm³ 3 , 0.5 g / cm 3 , 0.6 g / cm³ 3 , 0.7 g / cm³ 3 , 0.8 g / cm³ 3 , 0.9 g / cm³ 3 , or 1 g / cm³ 3 From 1.1 g / cm³ 3 , 1.2 g / cm³ 3 1.3 g / cm³ 3 1.4 g / cm³ 3 1.5 g / cm³ 3 1.6 g / cm³ 3 1.7 g / cm³ 3 1.8 g / cm³ 3 1.9 g / cm³ 3 , or 2g / cm³ 3 The apparent loose bulk density may range up to . In some embodiments, the catalyst particles may have a 1-hour abrasion degree 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 particle morphology is mostly spherical to facilitate movement within the fluidized bed reactor. In some embodiments, the catalyst particles may have a size and density consistent with the GelDart A or GelDart B definitions of the fluidizable solid. In some embodiments, the catalyst particles are 0.1 m 2 / g, 1m 2 / g, 10m 2 / g, or 100m 2 / g to 500m 2 / g, 800m 2 / g, 1,000m 2 / g, or 1,500m 2 The surface area can range from up to 1 / g. The surface area of ​​the catalyst particles can be measured according to the Brunauer-Emmett-Teller (BET) method, which utilizes nitrogen adsorption-desorption (at liquid nitrogen temperature, 77K) using a Micromeritics 3flex instrument after degassing the powder at 350°C for 4 hours. Further information on this method can be found, for example, in “Characterization of Porous Solids and Powders: Surface Area, Pore Size and Density,” S. Lowell et al., Springer, 2004.

[0046] The preparation of the support can be achieved by any known process. For simplicity and ease of explanation, the preparation of suitable support, including magnesium-aluminum mixed oxide (Mg(Al)O or MgO / Al2O3) support, will be described in more detail. Catalyst synthesis techniques are well known, and the following description is for illustrative purposes only and should not be considered limiting to the synthesis of support or catalyst particles. In some embodiments, to produce an MgO / Al2O3 mixed oxide support, Mg and Al precursors, such as Mg(NO3)2 and Al(NO3)3, may be mixed together, for example, by ball mill grinding followed by calcination to produce the support. In another embodiment, the two precursors may be dissolved in H2O, stirred until dry (and possibly heated), and then calcined to produce the support. In yet another embodiment, the two precursors may be dissolved in H2O, followed by the addition of a base and a carbonate, such as NaOH / Na2CO3, to produce hydrotalcite, which may then be calcined to produce the support. In another embodiment, a support may be produced by mixing commercially available MgO and Al2O3 and ball-milling them. In another embodiment, a Mg(NO3)2 precursor may be dissolved in H2O, and this solution may be impregnated onto an existing support, such as an Al2O3 support, dried, and calcined to produce a support. In yet another embodiment, Mg derived from Mg(NO3)2 may be loaded onto an existing Al2O3 support by ion adsorption, followed by liquid-solid separation, dried, and calcined to produce a support. While we do not wish to be constrained by theory, the supports produced by any one of the above methods and / or other methods may include (i) Mg and Al mixed together on an nm scale, (ii) Mg and Al in the form of a mixed Mg / Al metal oxide, or (iii) a combination of (i) and (ii).

[0047] Group 8-10 metals and their promoters and / or alkali metal elements can be loaded onto a mixed oxide support by any known technique. For example, one or more Group 8-10 element precursors, e.g., chloroplatinic acid, tetraammineplatin nitrate, and / or tetraammineplatin hydroxide, one or more promoter precursors (if used), e.g., salts of SnCl4 and / or AgNO3, and one or more alkali metal element precursors (if used), e.g., KNO3, KCl, and / or NaCl, can be dissolved in water. This solution can be impregnated onto the support and then dried and calcined. In some embodiments, the Group 8-10 element precursors and optionally promoter precursors and / or alkali metal element precursors can be loaded onto the support simultaneously or separately in an order separated by drying and / or calcination steps. In other embodiments, the Group 8-10 elements and optionally promoters and / or alkali metal elements can be loaded onto the support by chemical vapor deposition. In this case, the precursors are vaporized and accumulated on the support and then calcined. In other embodiments, Group 8-10 element precursors, and optionally promoter precursors and / or alkali metal precursors, may be loaded onto the carrier by liquid-solid separation, drying, and calcination after ion adsorption. Catalyst particles may also be synthesized using a one-pot synthesis method, in which the carrier precursors, Group 8-10 metal active phases, and promoters are all mixed together wet or dry, with or without any other additives to aid synthesis, followed by drying and calcination.

[0048] In some embodiments, catalyst particles can be formulated into Geldart A or B type particles by a well-known spray-drying process. Typically, spray-dried catalyst particles having an average cross-sectional area ranging from 20 μm, 40 μm, or 50 μm to 80 μm, 90 μm, or 100 μm are used in FCC type fluidized bed reactors. To produce spray-dried catalyst particles, a carrier, group 8-10 elements, and any additional components, such as promoters and / or alkali metals, can be made into a slurry, in which a binder / additive is included, and then spray-dried and calcined. Alternatively, group 8-10 elements, and any additional components, such as promoters and / or alkali metals, can be added to a formulation carrier to produce formulation catalyst particles. Suitable processes that can be used to prepare the catalyst particles disclosed herein include those described in U.S. Patent Nos. 4,788,371; 4,962,265; 5,922,925; 8,653,317; European Patent No. EP0098622; Journal of Catalysis 94 (1985), pp. 547-557; and / or Applied Catalysis 54 (1989), pp. 79-90.

[0049] Hydrocarbon-containing feed C2-C 16Alkanes are, but are not limited to, ethane, propane, n-butane, isobutane, n-pentane, isopentane, n-hexane, 2-methylpentane, 3-methylpentane, 2,2-dimethylbutane, n-heptane, 2-methylhexane, 2,2,3-trimethylbutane, cyclopentane, cyclohexane, methylcyclopentane, ethylcyclopentane, n-propylcyclopentane, 1,3-dimethylcyclohexane, or mixtures thereof, or may include these. For example, a hydrocarbon-containing feed may include propane, which can be dehydrogenated to produce propylene, and / or isobutane, which can be dehydrogenated to produce isobutylene. In another example, a hydrocarbon-containing feed may include liquefied petroleum gas (LPG), which may be in the gas phase upon contact with catalyst particles. In some embodiments, the hydrocarbons in the hydrocarbon-containing feed may consist substantially of a single alkane, such as propane. In some embodiments, the hydrocarbon-containing feed is a single C2-C mixture of ≥50 mol%, ≥75 mol%, ≥95 mol%, ≥98 mol%, or ≥99 mol%, based on the total mass of all hydrocarbons in the hydrocarbon-containing feed. 16 Alkanes, such as propane, may be included. In some embodiments, the hydrocarbon-containing feed is composed of at least 50 vol%, at least 55 vol%, at least 60 vol%, at least 65 vol%, at least 70 vol%, at least 75 vol%, at least 80 vol%, at least 85 vol%, at least 90 vol%, at least 95 vol%, at least 97 vol%, or at least 99 vol% single C2-C based on the total volume of the hydrocarbon-containing feed. 16 This may include alkanes, such as propane. C8-C 16 Alkyl aromatic hydrocarbons are, but are not limited to, ethylbenzene, propylbenzene, butylbenzene, one or more ethyltoluenes, or mixtures thereof, or may include these. In some embodiments, the hydrocarbon-containing feed is a single C8-C hydrocarbon in a total mass of ≥50 mol%, ≥75 mol%, ≥95 mol%, ≥98 mol%, or ≥99 mol%, based on the total mass of all hydrocarbons in the hydrocarbon-containing feed. 16It may contain alkyl aromatic hydrocarbons, such as ethylbenzene. In some embodiments, ethylbenzene can be dehydrogenated to produce styrene. Thus, in some embodiments, the processes disclosed herein can include propane dehydrogenation, butane dehydrogenation, isobutane dehydrogenation, pentane dehydrogenation, pentane dehydrogenation cyclization to cyclopentadiene, naphtha reforming, ethylbenzene dehydrogenation, ethyltoluene dehydrogenation, etc.

[0050] In some embodiments, the hydrocarbon-containing feed can be diluted with one or more diluent gases. Suitable diluents can be, but are not limited to, argon, neon, helium, molecular nitrogen, carbon dioxide, methane, molecular hydrogen, or a mixture thereof or can include these. When the hydrocarbon-containing feed contains a diluent, the hydrocarbon-containing feed can contain from 0.1 vol%, 0.5 vol%, 1 vol%, or 2 vol% to 3 vol%, 8 vol%, 16 vol%, or 32 vol% of the diluent based on the total volume of any C2-C 16 alkanes and any C8-C 16 alkyl aromatic hydrocarbons. When the diluent contains molecular hydrogen, the molar ratio of molecular hydrogen to the total amount of any C2-C 16 alkanes and any C8-C 16 alkyl aromatic hydrocarbons can range from 0.1, 0.3, 0.5, 0.7, or 1 to 2, 3, 4, 5, 6, 7, 8, 9, or 10. In some embodiments, when a diluent is used, the diluent is mixed with the hydrocarbon-containing feed and / or introduced into the conversion zone as an individual feed through one or more inlets assigned to supply the diluent to the conversion zone or supplied in other ways. Similarly, this hydrocarbon-containing feed may also be introduced into the conversion zone through one or more inlets assigned to supply the hydrocarbon-containing feed to the conversion zone.

[0051] In some embodiments, the hydrocarbon-containing feed is substantially free of any water or steam, i.e., for example, any C2-C in the hydrocarbon-containing feed 16 alkanes and any C8-C16 Based on the total volume of alkyl aromatic hydrocarbons, there may be only <0.1 vol% of water or steam. In other embodiments, the hydrocarbon-containing feed may contain steam. For example, the hydrocarbon-containing feed may be any C2-C in the hydrocarbon-containing feed 16 alkane and any C8-C 16 Based on the total volume of alkyl aromatic hydrocarbons, it may contain from 0.1 vol%, 0.3 vol%, 0.5 vol%, 0.7 vol%, 1 vol%, 3 vol%, or 5 vol% to 10 vol%, 15 vol%, 20 vol%, 25 vol%, 30 vol%, 35 vol%, 40 vol%, 45 vol%, or 50 vol% of water or steam. In other embodiments, the hydrocarbon-containing feed may be any C2-C in the hydrocarbon-containing feed 16 alkane and any C8-C 16 Based on the total volume of alkyl aromatic hydrocarbons, it may contain ≦50 vol%, ≦45 vol%, ≦40 vol%, ≦35 vol%, ≦30 vol%, ≦25 vol%, ≦20 vol%, or ≦15 vol% of water or steam. In other embodiments, the hydrocarbon-containing feed may be any C2-C in the hydrocarbon-containing feed 16 alkane and any C8-C 16 Based on the total volume of alkyl aromatic hydrocarbons, it may contain at least 1 vol%, at least 3 vol%, at least 5 vol%, at least 10 vol%, at least 15 vol%, at least 20 vol%, at least 25 vol%, or at least 30 vol% of water or steam. Similar to the diluent, when water or steam is supplied to the conversion zone, the water or steam may be supplied to the conversion zone as a component of the hydrocarbon-containing feed or through one or more individual inlets assigned to introduce steam into the conversion zone.

[0052] In some embodiments, the hydrocarbon-containing feed may contain sulfur. For example, the hydrocarbon-containing feed may contain sulfur in the range of 0.5 ppm, 1 ppm, 5 ppm, 10 ppm, 20 ppm, 30 ppm, 40 ppm, 50 ppm, 60 ppm, 70 ppm, or 80 ppm to 100 ppm, 150 ppm, 200 ppm, 300 ppm, 400 ppm, or 500 ppm. In other embodiments, the hydrocarbon-containing feed may contain sulfur in the range of 1 ppm to 10 ppm, 10 ppm to 20 ppm, 20 ppm to 50 ppm, 50 ppm to 100 ppm, or 100 ppm to 500 ppm. If sulfur is present in the hydrocarbon-containing feed, it may be, but is not limited to, H2S, dimethyl disulfide, one or more mercaptans, or any mixture thereof, or include these. In some embodiments, sulfur may be introduced into the conversion zone as a separate feed, as a component of a diluent if one is used, and / or as a component of steam if one is used. Hydrocarbon-containing feeds may be substantially free of molecular oxygen or completely free. In some embodiments, hydrocarbon-containing feeds may contain ≤5 mol%, ≤3 mol%, or ≤1 mol% molecular oxygen (O2). Supplying a hydrocarbon-containing feed that is substantially free of molecular oxygen is thought to substantially inhibit oxidative coupling reactions that would otherwise consume at least some of the alkanes and / or alkyl aromatic hydrocarbons in the hydrocarbon-containing feed.

[0053] Recovery and use of dehydrogenated hydrocarbons The conversion effluent may contain at least one olefin, water, unreacted hydrocarbons, unreacted molecular hydrogen, etc. The olefin(s) can be recovered or obtained by any conventional process, for example, by one or more conventional processes. One such process may include a step of cooling the effluent to condense at least a portion of any water and heavy hydrocarbons present, leaving the olefin and any unreacted alkanes or alkyl aromatic hydrocarbons mainly in the gas phase. The olefin and unreacted alkanes or alkyl aromatic hydrocarbons can then be removed from the reaction product in one or more separator drums. For example, the dehydrogenated product can be separated from the unreacted hydrocarbon-containing feed using one or more splitters. In some embodiments, recovered olefins, such as propylene, can be used in the production of polymers. For example, recovered propylene can be polymerized to produce polymers having segments or units derived from recovered propylene, such as polypropylene, ethylene-propylene copolymer, etc. Recovered isobutene can be used in the production of one or more oxygen-containing compounds, such as methyl tert-butyl ether, fuel additives, such as diisobutene, and synthetic elastomer polymers, such as butyl rubber.

[0054] Representative Embodiments Figure 1 shows a system for dehydrogenating a hydrocarbon-containing feed in line 101 according to one or more embodiments, and includes a reactor or conversion zone 103, a regenerator or combustion zone 104, an oxygen immersion zone 137, a reduction zone 139, and a quench tower 113. The hydrocarbon-containing feed may be introduced through line 101 to the conversion zone 103, for example, at the lower end of a riser reactor or the upper end of a downer reactor. In some embodiments, the hydrocarbon-containing feed in line 101 may contain water vapor. Regenerated reduction catalyst particles may be transported from the reduction zone 139 to the conversion zone 103 through line 102. The hydrocarbon-containing feed may come into contact with the regenerated reduction catalyst particles in the conversion zone 103 to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed, producing a conversion effluent via line 105 that may contain coking catalyst particles, one or more dehydrogenated hydrocarbons, unreacted hydrocarbon-containing feed, water vapor, benzene, or any mixture thereof.

[0055] The conversion effluent can be introduced through line 105 into one or more separators 106, for example, one or more cyclones. The separator 106 can separate the conversion effluent into a first stream 107 rich in coking catalyst particles and low in one or more dehydrogenated hydrocarbons, and a second stream passing through line 109 rich in one or more dehydrogenated hydrocarbons and containing entrained coking catalyst particles. The first stream may be recirculated to the combustion zone 104 via line 107. In some embodiments, the first stream of line 107 may contain entrained gaseous components, such as one or more dehydrogenated hydrocarbons, unreacted hydrocarbon-containing feed, water vapor, or a mixture thereof. In such embodiments, at least a portion of the gaseous components in the first stream of line 107 may be stripped before the first stream is introduced into the combustion zone 104. An oxidizer and optionally fuel may be introduced into the combustion zone 104 via line 108 and come into contact with at least a portion of the coking catalyst particles in the first stream, causing combustion of coke and, if present, at least a portion of the fuel, to produce a combustion effluent containing regenerated catalyst particles and combustion gases. The combustion of coke and, if present, fuel generates heat that can burn the coke from the coking catalyst particles, redisperse group 8-10 elements on the spent catalyst particles, and heat the regenerated catalyst particles.

[0056] The combustion effluent is recovered via line 131 and may enter one or more separators 132, for example, one or more cyclones, to separate it into a stream 134 containing most of the catalyst particles and a small amount of entrained combustion gas from the combustion effluent, and a combustion gas stream 133 containing most of the combustion gas and, if any, a small amount of entrained catalyst particles. In some embodiments, one or more separators 132 may include three or more cyclones to achieve high solid recovery efficiency from the combustion effluent of line 131 and to reduce the amount of entrained catalyst particles in the combustion gas stream 133. Stream 134 may be sent to an oxygen immersion zone 137. A relatively dry oxidizer gas stream 136 is supplied to the oxygen immersion zone 137 to fully regenerate the catalyst. After entering zone 137, any unreacted dry oxidizer gas streams, entrained with fully regenerated catalyst particles, can exit zone 137 as stream 135. Stream 135 enters the separator 132 and may be split into a solid stream and a gaseous stream. A solid stream rich in fully regenerated catalyst particles may merge into stream 134 and return to zone 137. A gaseous stream rich in unreacted dry oxidizing gas may merge into stream 133. Fully regenerated catalyst particles may leave zone 137 as stream 138 and enter the reduction zone 139. A reduction gas stream 140 may also be supplied to zone 139. Regenerated reduction catalyst particles may leave the reduction zone 139 via line 102 and enter the conversion zone 103. Unreacted reduction gas may leave the reduction zone as stream 141. If the combustion gas stream 133 contains any entrained catalyst particles, these catalyst particles may be removed by a filter, electrostatic dust collector, wet gas scrubber, etc. The separation devices 106 and 132 on the conversion zone and combustion zones 103 and 104, and / or the operating conditions of the separation devices 106 and 132, can be adjusted to deliver more or less entrained catalyst particles from either the second stream 109 or the combustion gas stream 133, respectively, depending on the level of difficulty in collecting entrained catalyst from the second stream 109 and the combustion gas stream of line 133.

[0057] The second stream 109 may enter the plenum 110. Within the plenum 110, stream 109 may be mixed with the first quench medium stream 111 to generate a second cooling stream for line 112. In some embodiments, the temperature of the second stream for line 109 may be >620°C. In some embodiments, benzene is produced during the dehydrogenation of the hydrocarbon-containing feed, and the benzene may be present in the second cooling stream. In some embodiments, benzene may be used as the first quench in line 111. In some embodiments, the first quench medium stream may be in the liquid phase when it comes into contact with the second stream in the plenum 110. In some embodiments, contact between the second stream 109 in the plenum 110 and the first quench medium stream of line 111 may result in a second cooling stream having a temperature of ≤620°C, ≤610°C, ≤600°C, ≤590°C, or ≤580°C. In some embodiments, the second cooling stream may have a temperature in the range of ≥550°C and ≤620°C or ≤600°C. Lowering the temperature of the second stream in line 109 to below 600°C can reduce or stop undesirable thermal reactions of the gaseous components.

[0058] The second cooling stream may be introduced via line 112 into a gas-liquid contact zone 114 located within the quench tower 113. Before entering zone 114, the second cooling stream via line 112 may be passed through one or more heat exchangers for heat recovery. Within the gas-liquid contact zone 114, the second cooling stream may come into contact with a catalyst particle lean second quench medium stream introduced into the quench tower 113 via line 115. The second quench medium stream of line 115 is sprayed downward into the gas-liquid contact zone 114 opposite the second cooling stream of line 112 to ensure good contact between the second cooling stream and the second quench medium stream. Within the gas-liquid contact zone 114, most of the catalyst fines and heat in the second cooling stream 112 are transferred to the second quench medium stream 115, potentially generating a slurry that may contain at least a portion of the liquid phase second quench and at least a portion of the encompassed coking catalyst particles. In some embodiments, the second quench medium of stream 115 may have a higher standard boiling point than the first quench medium 111. For example, the standard boiling point of the second quench medium stream 115 may be 150°C to 580°C.

[0059] The slurry can be recovered from the quench tower 113 via line 116. In some embodiments, the slurry may accumulate at the bottom of the quench tower 113 to form a liquid reservoir 117. In some embodiments, a replenishment stream via line 129 may be mixed, blended, combined, or otherwise contacted with the slurry in line 116 to produce a mixed stream in line 118. The slurry stream in line 116 or the mixed stream in line 118 may be cooled in one or more heat exchangers 119 to produce a cooled slurry stream via line 120. At least a portion of the cooled slurry stream via line 120 is introduced into a solid-liquid separator 121, as a result of recovering a fine-grained lean second quench medium stream via line 115 and a fine-grained rich second quench medium stream via line 122. An example of a solid-liquid separator 121 is a filter. In some embodiments, at least a portion of the fine-grain-rich second quench medium stream of line 122 may be introduced into the combustion zone 104 via line 123. Residual hydrocarbons in the fine-grain-rich second quench medium stream of line 123 may burn in the combustion zone 104 to generate heat. Catalyst particles contained in the fine-grain-rich second quench medium stream of line 123 may be regenerated within the combustion zone 104. In some embodiments, at least a portion of the fine-particle-rich second quench medium stream of line 122 is transported to a metal recycling facility 124 where group 8-10 elements may be recycled.

[0060] In some embodiments, a first quench medium having a standard boiling point lower than that of a second quench medium, located above the gas-liquid contact zone 114 in the quench column 113, is removed from the quench column via line 132, cooled by one or more heat exchangers 126, and a first portion or amount may be returned to the quench column 113 for recirculation. In some embodiments, the first quench medium may be benzene, one of the products of alkane dehydrogenation, and a second portion or amount of the cooled first quench medium may be removed to form a product stream 125. In some embodiments, a third portion or amount of the cooled first quench medium may be recirculated to the plenum 110 via line 111 as a first quench medium stream. At a location above zone 114 of the quench tower 113, at least a portion of any water present in the quench tower 113 may be withdrawn from the quench tower via line 133, cooled by one or more heat exchangers 127, and at least a portion of this cooling water may be returned to the quench tower 113 for recirculation. A portion or amount of the cooling water may be withdrawn via line 128 and sent for wastewater treatment. The overhead product stream 130 exiting the quench tower 113 is essentially free of coking catalyst particles and can then be further cooled, compressed, and sent for further product recovery. In some embodiments, the overhead product stream of line 130 can be passed through one or more gas-solid separators to remove at least a portion of any entrained catalyst particles present.

[0061] Figure 2 shows another system for dehydrogenating a hydrocarbon-containing feed in line 201 according to one or more embodiments, the system comprising a reactor or conversion zone 203, a regenerator or combustion zone 204, an oxygen immersion zone 237, a reduction zone 240, and a quench tower 213. The hydrocarbon-containing feed may be introduced into the conversion zone 203 via line 201, for example, at the lower end of a riser reactor or the upper end of a downer reactor. In some embodiments, the hydrocarbon-containing feed in line 201 may contain water vapor. Regenerated reduction catalyst particles may be transported from the reduction zone 240 to the conversion zone 203 via line 202. The hydrocarbon-containing feed may come into contact with the regenerated reduction catalyst particles in the conversion zone 203 to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed, producing a conversion effluent via line 205 that may contain one or more dehydrogenated hydrocarbons, unreacted hydrocarbon-containing feed, water vapor, benzene, or any mixture thereof. The conversion effluent can be introduced via line 205 into one or more separators 206, for example, one or more cyclones. The separator 206 can separate the conversion effluent into a first stream 207 rich in coking catalyst particles and low in one or more dehydrogenated hydrocarbons, and a second stream via line 209 rich in one or more dehydrogenated hydrocarbons and containing entrained coking catalyst particles.

[0062] The first stream may be recirculated to the combustion zone 204 via line 207. In some embodiments, the first stream of line 207 may contain entrained gaseous components, such as one or more dehydrogenated hydrocarbons, unreacted hydrocarbon-containing feed, steam, or a mixture thereof. In such embodiments, at least a portion of the gaseous components in the first stream may be stripped before the first stream of line 207 is introduced into the combustion zone 204. An oxidizer and optionally fuel may be introduced into the combustion zone 204 via line 208 and come into contact with at least a portion of the coking catalyst particles in the first stream, causing combustion of coke and, if present, at least a portion of the fuel, to produce a combustion effluent containing regenerated catalyst particles and combustion gases. The combustion of coke and, if present, fuel generates heat that can burn the coke from the coking catalyst particles, redisperse group 8-10 elements on the spent catalyst particles, and heat the regenerated catalyst particles.

[0063] The combustion effluent is recovered via line 233 and may enter one or more separators 234, for example, one or more cyclones, to separate it into a stream 236 containing most of any catalyst particles encombusted with the combustion effluent and a small amount of encombusted combustion gas, and a combustion gas stream 235 containing most of the combustion gas and, if any, a small amount of encombusted catalyst particles. In some embodiments, one or more separators 234 may include three or more cyclones to achieve high solid recovery efficiency from the combustion effluent of line 233 and to reduce the amount of encombusted catalyst particles in the combustion gas stream 235. Stream 236 can be sent to the oxygen immersion zone 237. A relatively dry oxidant gas stream 239 can be supplied to the oxygen immersion zone 237 to fully regenerate the catalyst. After entering zone 237, any unreacted dry oxidant gas streams, accompanied by fully regenerated catalyst particles, can exit zone 237 as stream 238. Stream 238 can enter the separator 234 and be split into a solid stream and a gaseous stream. The solid stream, rich in fully regenerated catalyst particles, can merge with stream 236 and return to zone 237. The gaseous stream, rich in unreacted dry oxidant gas, can merge with stream 235. The fully regenerated catalyst particles can leave zone 237 as stream 241 and enter the reduction zone 240. A reduction gas stream 242 can also be supplied to zone 240. The regenerated reduction catalyst particles can exit the reduction zone 240 via line 202 and enter the conversion zone 203. Any unreacted reducing gases can leave the reduction zone as stream 243.

[0064] In some embodiments, if the combustion gas stream 235 contains any entrained catalyst particles, it may be passed through a filter, electrostatic dust collector, wet gas scrubber, etc. Separators 206 and 234 on the conversion zone and combustion zones 203 and 204 may be adjusted to feed more or less entrained catalyst particles from either the second stream 209 or the combustion gas stream 233, respectively, depending on the level of difficulty in collecting the entrained catalyst from the second stream of line 209 and the combustion gas stream of line 235. The second stream 209 may enter the plenum 210. Within the plenum 210, stream 209 may be mixed with the first quench medium stream 211 to generate a second cooling stream for line 212. In some embodiments, the temperature of the second stream for line 209 may be >620°C.

[0065] In some embodiments, benzene may be produced during the dehydrogenation of the hydrocarbon-containing feed, and benzene may be present in the second cooling stream. In some embodiments, benzene may be used as the first quench medium in line 211. In some embodiments, the first quench medium stream may be in the liquid phase upon contact with the second stream in the plenum 210. In some embodiments, contact between the second stream 209 in the plenum 210 and the first quench medium stream of line 211 may result in a second cooling stream having temperatures of ≤620°C, ≤610°C, ≤600°C, ≤590°C, or ≤580°C. In some embodiments, the second cooling stream may have temperatures in the range of ≥550°C and ≤620°C or ≤600°C. Lowering the temperature of the second stream in line 209 to below 600°C may reduce or stop undesirable thermal reactions of the gaseous components. The second cooling stream may be introduced via line 212 into a gas-liquid contact zone 214 located within the quench tower 213. Before entering zone 214, the second cooling stream via line 212 may also travel through one or more heat exchangers for heat recovery. Within the gas-liquid contact zone 214, the second cooling stream may come into contact with a catalyst particle lean second quench medium stream introduced into the quench tower 213 via line 215. The second quench medium stream of line 215 is sprayed downward into the gas-liquid contact zone 214 opposite the second cooling stream of line 212 to ensure good contact between the second cooling stream and the second quench medium stream. Within the gas-liquid contact zone 214, most of the catalyst fine particles and heat in the second cooling stream 212 are transferred to the second quench medium stream 215, potentially generating a slurry that may contain at least some of the liquid phase first and second quench medium and coking catalyst particles.

[0066] The slurry can be recovered from the quench tower 213 via line 216. In some embodiments, the slurry may accumulate at the bottom of the quench tower 213 to form a liquid reservoir 217. The liquid reservoir may also contain unreacted water which can be added as a reactant to the hydrocarbon-containing feed. The slurry stream from line 216 is introduced into a separator 218, which may yield a water stream containing coking catalyst particles via line 219 and a quench medium stream containing coking catalyst particles via line 226. The water stream is introduced to the separator 220 via line 219, which may result in a water stream containing coking catalyst particles via line 222 and a water stream with fewer coking catalyst particles via line 221. In some embodiments, the separator 220 may be a liquid-solid filter. The wastewater stream may be sent to a wastewater treatment facility via line 221. In some embodiments, at least a portion of the water stream containing coking catalyst particles may be transported to the metal recycling facility 224 via line 222, to the combustion zone 204 via line 228, or a combination thereof. The quench medium stream may be introduced to one or more heat exchangers 227 via line 226 to generate a cooling quench medium stream via line 229. The cooling quench medium stream may be introduced to one or more solid-liquid separators 230 via line 229 to provide a quench medium stream with fewer coking catalyst particles via line 215 and a quench medium stream rich in coking catalyst particles via line 231. In some embodiments, the solid-liquid separator 230 may be a liquid-solid filter.

[0067] In some embodiments, at least a portion of the quench medium stream rich in coking catalyst particles may be transported via line 231 to the metal recycling facility 224, via line 223 to the combustion zone 204, or a combination thereof. If at least a portion of the quench medium stream rich in coking catalyst particles is transported via line 223 to the combustion zone 204, the residual hydrocarbons therein may burn in the conversion zone 204 to generate heat, where the coking catalyst particles can be regenerated. In some embodiments, a first portion of the quench medium stream with fewer coking catalyst particles may be recirculated via line 215 to the quench tower 213 as a second quench medium, a second portion of the quench medium stream with fewer coking catalyst particles may be recirculated via line 215 to the plenum 210 as a first quench medium via line 211, and optionally, a third portion of the quench medium stream with fewer coking catalyst particles in line 215 may be recovered as a product via line 225. The overhead product stream 232 exiting the quench tower 213 is essentially free of coking catalyst particles and can then be further cooled, compressed, and sent for further product recovery. In some embodiments, the overhead product stream can be passed through one or more gas-solid separators via line 232 to remove at least a portion of any entrained catalyst particles present. [Examples]

[0068] Examples The above considerations can be further explained by referring to the following non-limiting examples. Catalyst composition 1 was prepared by mixing CATAPAL® D pseudo-boehmite (Sasol) (47 g) and calcined Mg-Al hydrotalcite (PURALOX® MG70) (44 g) containing 70 wt% MgO and 30 wt% Al2O3 in deionized water (524 ml) to prepare a slurry. The slurry was milled and spray-dried using a Buchi B-290 mini spray dryer to produce spray-dried particles. The spray-dried particles were calcined in air at 550°C for 4 hours to produce calcined carrier particles nominally containing 50 wt% PURALOX® MG70 and 50 wt% Al2O3 derived from CATAPAL® D. The calcined carrier particles were impregnated with an aqueous solution containing tin(IV) chloride pentahydrate, chloroplatinic acid hexahydrate, and deionized water using spontaneous wetness impregnation. This impregnated material was baked in air at 800°C for 12 hours to produce a catalyst composition containing nominally 0.3 wt% Pt and 1.5 wt% Sn on a 50:50 MG70:CATAPAL(registered trademark) D.

[0069] Catalyst composition 2 was prepared by mixing 85 g of 40 wt% aluminum chlorohydrol solution (ACH) and 88 g of calcined magnesium-alkaline hydrotalcite (PURALOX® MG70) in 596 ml of deionized water to prepare a slurry. The slurry was milled and spray-dried using a Buchi B-290 mini spray dryer to produce spray-dried particles. The spray-dried particles were calcined in air at 550°C for 4 hours to produce calcined carrier particles nominally containing 80 wt% PURALOX® MG70 and 20 wt% Al2O3 derived from ACH. The calcined carrier particles were impregnated with an aqueous solution containing tin(IV) chloride pentahydrate, chloroplatinic acid hexahydrate, and deionized water using spontaneous wetness impregnation. This impregnated material was baked in air at 800°C for 12 hours to produce a catalyst composition containing nominally 0.3 wt% Pt and 1.5 wt% Sn on an 80:20 MG70:ACH base.

[0070] Catalyst compositions 3 to 16 were prepared according to the following procedure. Each catalyst composition contained 80 wt% MgO and 20 wt% Al2O3, and 150 m 2 A support was formed by calcining PURALOX® MG80 / 150 (3 grams) (Sasol), a mixed Mg / Al metal oxide with a surface area of ​​ / g, at 550°C for 3 hours under air. A solution containing an appropriate amount of tin(IV) chloride pentahydrate (for use in the preparation of catalyst composition (Acros Organics)) and / or an appropriate amount of chloroplatinic acid (for use in the preparation of catalyst composition (Sigma Aldrich)) and 1.8 ml of deionized water was prepared in a small glass vial. For each catalyst composition, the calcined PURALOX® MG80 / 150 support (2.3 grams) was impregnated with the corresponding solution. This impregnated material was allowed to equilibrium in a sealed container at room temperature (RT) for 24 hours, dried at 110°C for 6 hours, and calcined at 800°C for 12 hours. Table 1 shows the nominal Pt and Sn content of each composition based on the mass of the support.

[0071] [Table 1]

[0072] Examples using the above catalyst compositions 1 and 2 Fixed-bed experiments were conducted at an absolute pressure of approximately 100 kPa. The composition of the reactor effluent was measured using gas chromatography (GC). Next, the yield and selectivity of C3H6 were calculated using the concentrations of each component in the reactor effluent. The yield and selectivity of C3H6 reported in these examples were calculated on a carbon molar basis. In each embodiment, 0.3 g of catalyst Mcat was mixed with an appropriate amount of quartz diluent and packed into a quartz reactor. The amount of diluent was determined so that the catalyst bed (catalyst + diluent) overlapped with the isothermal zone of the quartz reactor and that the catalyst bed was mostly isothermal during operation. The dead volume of the reactor was filled with quartz chips / rods. The yield and selectivity of C3H6 were calculated using the concentrations of each component in the reactor effluent. rxn At the start and t rxn The yield and selectivity of C3H6 at the end of the process are determined by Y, respectively. ini , Yend S ini , and S end This is expressed as follows, and reported as a percentage in the table below.

[0073] The process steps for Examples 1 and 2 were as follows: 1. An inert gas was flowed through the system. 2. While flowing an inert gas through the reaction zone, introduce an oxygen-containing gas (Ogas) at a flow rate (F regen The reaction zone was then flowed through the bypass of the reaction zone. The reaction zone was regenerated at temperature T regen It was heated. 3. Next, introduce an oxygen-containing gas into the reaction zone for a specific time (t regen The catalyst was regenerated by running water through it. regen Next, while maintaining the oxygen-containing gas flow rate, the temperature in the reaction zone is controlled to T regen From reduction temperature (T red I changed it to ). 4. An inert gas was flowed through the system. 5. While flowing an inert gas through the reaction zone, introduce an H2-containing gas (Hgas) at a flow rate (F red The gas was then flowed through the bypass of the reaction zone for a specific period of time. After this, the H2-containing gas was introduced into the T red Within the reaction zone, a specific time (t red It was broadcast over a period of time. 6. An inert gas was flowed through the system. During this process, the temperature of the reaction zone was set to T red The reaction temperature was changed from 655°C to 655°C. 7. While flowing an inert gas through the reaction zone, introduce a hydrocarbon-containing feed (HCgas) containing 81 vol% C3H8, 9 vol% inert (Ar or Kr), and 10 vol% water vapor at a flow rate (F rxn The hydrocarbon-containing feed was then flowed through the bypass of the reaction zone for a specified period of time. Next, the hydrocarbon-containing feed was flowed through the reaction zone at 655°C for 10 minutes. GC sampling of the reaction effluent was started immediately after switching the feed from the bypass to the reaction zone. The above process steps were repeated periodically until stable performance was obtained. Table 2 shows that both catalyst 1 and catalyst 2 were active / selective for propane dehydrogenation. Figure 3 is a graph showing the propylene selectivity of C mol% and the propylene yield of C mol% as a function of flow time, demonstrating that catalyst 2 was stable for propane dehydrogenation over 60 cycles.

[0074] [Table 2]

[0075] Examples using the above catalyst compositions 3 to 16 Fixed-bed experiments were conducted at an absolute pressure of approximately 100 kPa using catalyst compositions 3 to 16. The composition of the reactor effluent was measured using gas chromatography (GC). Next, the yield and selectivity of C3H6 were calculated using the concentrations of each component in the reactor effluent. The yield and selectivity of C3H6 reported in these examples were calculated on a carbon molar basis. In each example, 0.3 g of the catalyst composition was mixed with an appropriate amount of quartz diluent and packed into a quartz reactor. The amount of diluent was determined so that the catalyst bed (catalyst + diluent) overlapped with the isothermal zone of the quartz reactor and that the catalyst bed was mostly isothermal during operation. The dead volume of the reactor was filled with quartz chips / rods. t rxn At the start and t rxn The yield and selectivity of C3H6 at the end of the process are determined by Y, respectively. ini , Y end S ini , and S end The results are expressed as follows, and the percentages for catalyst compositions 3 to 10 are reported in Tables 3 and 4.

[0076] The process steps for catalyst compositions 3 to 10 were as follows: 1. An inert gas was flowed through the system. 2. Dry air was passed through the bypass of the reaction zone at a flow rate of 83.9 sccm while an inert gas was passed through the reaction zone. The reaction zone was heated to a regeneration temperature of 800°C. 3. Next, dry air was passed through the reaction zone at a flow rate of 83.9 sccm for 10 minutes to regenerate the catalyst. 4. An inert gas was flowed through the system. 5. While passing an inert gas through the reaction zone, an H2-containing gas containing 10 vol% H2 and 90 vol% Ar was passed through the bypass of the reaction zone at a flow rate of 46.6 sccm for a specific period of time. After this, the H2-containing gas was flowed into the 800°C reaction zone for 3 seconds. 6. An inert gas was introduced into the system. During this process, the reaction zone temperature was changed from 800°C to 670°C. 7. While passing an inert gas through the reaction zone, a hydrocarbon-containing feed (HCgas) containing 81 vol% C3H8, 9 vol% inert gas (Ar or Kr), and 10 vol% water vapor was passed through the bypass of the reaction zone at a flow rate of 35.2 sccm for a specified time. Next, the hydrocarbon-containing feed was passed through the reaction zone at 670°C for 10 minutes. GC sampling of the reaction effluent was started immediately after switching the feed from the bypass to the reaction zone. The above process steps were repeated periodically until stable performance was obtained. Tables 3 and 4 show that catalyst composition 8, containing only 0.025 wt% Pt and 1 wt% Sn, exhibited both similar yield and similar selectivity compared to catalyst 3, which contained 0.4 wt% Pt and 1 wt% Sn, which was surprising and unexpected. Catalyst 10, which contained no Pt, did not show a recognizable propylene yield.

[0077] [Table 3]

[0078] [Table 4]

[0079] Catalysts 3-10 were tested using the same process steps 1-7 described above, as were catalysts 11-16. Table 5 shows that, based on the mass of the support, the Sn level should not be too low or too high for the optimal propylene yield in a catalyst composition containing 0.1 wt% Pt.

[0080] [Table 5]

[0081] Table 6 shows that, based on the mass of the support, the level of Sn should not be too high or too low for a catalyst composition containing 0.0125 wt% Pt to achieve the optimal propylene yield.

[0082] [Table 6]

[0083] Except for using a flow rate of 17.6 sccm instead of 35.2 sccm in step 7, catalyst composition 8, containing only 0.025 wt% Pt and 1 wt% Sn, was subjected to a lifetime test using the same process steps 1 to 7 described above for catalysts 3 to 10. Figure 4 shows that catalyst composition 8 maintained its performance over 204 cycles (x axis is time, and y axis is the yield and selectivity for C3H6, both in carbon mole percent).

[0084] Various terms have been defined above. Unless a term used in a claim is defined above, the broadest definition given to that term by a person skilled in the art should be given, as reflected in at least one publication or issued patent. Furthermore, all patents, test procedures, and other documents referenced in this application are invoked by reference in full to the extent that such disclosure is not inconsistent with this application, and are invoked for all rights in which such invocation is permitted. The above description relates to embodiments of the present invention, but it is possible to devise other further embodiments of the present invention without departing from the basic scope of the present invention, and the scope of the present invention is defined by the following claims. This disclosure includes the following embodiments. <Embodiment 1> A hydrocarbon upgrade process, (I) A step of bringing a hydrocarbon-containing feed into contact with fluid dehydrogenation catalyst particles in a conversion zone to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed, thereby generating a conversion effluent containing coking catalyst particles and one or more dehydrogenated hydrocarbons, (II) A step of separating from the conversion effluent a first stream rich in the coking catalyst particles and low in the one or more dehydrogenated hydrocarbons and a second stream rich in the one or more dehydrogenated hydrocarbons and containing encompassed coking catalyst particles, (III) The step of bringing the second stream into contact with the first quench medium to generate a second cooling stream, (IV) The step of bringing the second cooling stream into contact with the second quench medium in the quench tower, (V) A step of recovering from the quench tower a gas stream containing one or more dehydrogenated hydrocarbons, a condensed first quench medium stream, and a slurry stream in which the liquid phase contains at least a portion of the second quench medium and the encompassed coking catalyst particles, (VI) A step of recirculating at least a portion of the condensed first quench medium back to step (III), (VII) Separating at least a portion of the encompassed coking catalyst particles from the slurry stream to provide a recovered second quench medium stream and a recovered encompassed coking catalyst particle stream, (VIII) The step of recirculating at least a portion of the recovered second quench medium stream to step (IV) The process including the process described above. <Embodiment 2> moreover, (IX) The steps of bringing at least a portion of the coking catalyst particles in the first stream and at least a portion of the coking catalyst particles in the recovered entrained catalyst particle stream into contact with an oxidizer and optionally fuel in a combustion zone to cause combustion of at least a portion of the coke and, if present, the fuel, to produce a combustion effluent containing regenerated catalyst particles and combustion gas with less coke, (X) A step of separating the combustion gas stream and the regenerated catalyst particle stream, (XI) The step of bringing an additional amount of the hydrocarbon-containing feed into contact with the fluid regenerative catalyst particles from the regenerative catalyst particle stream to generate an additional conversion effluent containing recoking catalyst particles and one or more additional dehydrogenated hydrocarbons. The process described in Embodiment 1, including the process described in Embodiment 1. <Embodiment 3> The dehydrogenation catalyst particles contain group 8 to 10 elements arranged on a support, and the process is, (XII) A step of transporting at least a portion of the recovered enclosed catalyst particle stream to a metal recycling facility, (XIII) A step of recovering at least a portion of the Group 8 to 10 elements from the coking catalyst particles in the recovered encompassed coking catalyst particle stream. The process according to Embodiment 1 or Embodiment 2, further comprising: <Embodiment 4> (XIV) The process according to any one of embodiments 1 to 3, further comprising the step of cooling the slurry stream before step (VII) to generate a cooled slurry stream. <Embodiment 5> The conversion effluent further contains benzene, and the process is, The process according to any one of Embodiments 1 to 4, further comprising the step of removing the (XV)benzene product stream from the quench tower. <Embodiment 6> The process according to Embodiment 5, wherein the first quench medium includes at least a portion of the benzene product stream removed from the quench tower. <Embodiment 7> The process according to any one of embodiments 1 to 6, wherein the first stream and the second stream are separated from the conversion effluent in one or more cyclones, and the second stream is brought into contact with the first quench medium in at least one plenum of the one or more cyclones. <Embodiment 8> The process according to any one of embodiments 1 to 6, wherein the first stream and the second stream are separated from the conversion effluent in a primary separator and a secondary separator located downstream of the primary separator and in fluid communication with the primary separator, and the second stream is brought into contact with the first quench medium in the plenum of the secondary separator. <Embodiment 9> The process according to any one of embodiments 1 to 6, wherein the first stream and the second stream are separated from the conversion effluent in one or more gas-solid separators, and the second stream is brought into contact with the first quench medium in a transfer line that is fluidly connected to the one or more gas-solid separators and the quench tower. <Embodiment 10> The process according to any one of embodiments 1 to 9, wherein the first quenching medium is in the liquid phase when it comes into contact with the second stream, and the first quenching medium is in the gas phase after it comes into contact with the second stream. <Embodiment 11> The process according to any one of Embodiments 1 to 10, wherein the first quenching medium comprises benzene, water, or a polycyclic aromatic hydrocarbon having a standard boiling point of <580°C, or a mixture thereof. <Embodiment 12> The process according to any one of Embodiments 1 to 11, wherein the second quenching medium comprises benzene, water, or a polycyclic aromatic hydrocarbon having a standard boiling point of <580°C, or a mixture thereof. <Embodiment 13> The process according to any one of embodiments 1 to 12, wherein the second quenching medium has a standard boiling point higher than the standard boiling point of the first quenching medium. <Embodiment 14> The process according to any one of embodiments 1 to 13, wherein the lower zone within the quench tower contains the inventory of the slurry stream. <Embodiment 15> The process according to any one of Embodiments 1 to 14, wherein in step (VII), the encompassed coking catalyst particles are separated from the slurry stream by one or more filters. <Embodiment 16> The process according to any one of Embodiments 1 to 15, wherein the first quenching medium comprises a liquid hydrocarbon and any non-solid component in the second cooling stream is entirely in the gas phase. <Embodiment 17> The process according to any one of Embodiments 1 to 16, wherein the first quenching medium comprises an aromatic hydrocarbon formed during the dehydrogenation of the hydrocarbon-containing feed. <Embodiment 18> The process according to any one of Embodiments 1 to 17, wherein the second quenching medium contains aromatic hydrocarbons that are not formed during the dehydrogenation of the hydrocarbon-containing feed. <Embodiment 19> The process according to any one of embodiments 1 to 18, wherein the second quench medium is in countercurrent contact with the second cooling stream within the quench tower. <Embodiment 20> The process according to any one of embodiments 1 to 19, wherein the conversion effluent is at a temperature of ≥620°C and the second cooling stream is at a temperature of ≥500°C and <620°C. <Embodiment 21> The process according to any one of Embodiments 1 to 20, wherein the dehydrogenation catalyst particles comprise 0.001 wt% to 6 wt% of Group 8 to 10 elements disposed on a support, and a promoter up to 10 wt% optionally comprising Sn, Cu, Au, Ag, Ga, combinations thereof, or mixtures thereof, all mass percentage values ​​being based on the mass of the support. <Embodiment 22> The process according to any one of Embodiments 1 to 20, wherein the dehydrogenation catalyst particles comprise 0.001 wt% to 6 wt% of Pt disposed on a support and up to 10 wt% of a promoter optionally comprising Sn, Cu, Au, Ag, Ga, a combination thereof, or a mixture thereof, and the support comprises at least 0.5 wt% of a group 2 element, and all mass percentage values ​​are based on the mass of the support. <Embodiment 23> The dehydrogenation catalyst particles were measured according to ASTM D7481-18, modified to have a median particle size in the range of 10 μm to 500 μm and using 10, 25, or 50 mL graduated cylinders instead of 100 or 250 mL graduated cylinders, and measured to be 0.3 g / cm³. 3 ~2g / cm 3 The process according to any one of Embodiments 1 to 22, having an apparent loose bulk density in the range of . <Embodiment 24> The process according to any one of Embodiments 1 to 23, wherein the dehydrogenation catalyst particles satisfy the requirements of the Geldart A or Geldart B classification.

Claims

1. A hydrocarbon upgrade process, (I) A step of bringing a hydrocarbon-containing feed into contact with fluid dehydrogenation catalyst particles in a conversion zone to cause dehydrogenation of at least a portion of the hydrocarbon-containing feed, thereby generating a conversion effluent containing coking catalyst particles and one or more dehydrogenated hydrocarbons, (II) A step of separating from the conversion effluent a first stream rich in the coking catalyst particles and low in the one or more dehydrogenated hydrocarbons and a second stream rich in the one or more dehydrogenated hydrocarbons and containing encompassed coking catalyst particles, (III) The step of bringing the second stream into contact with the first quench medium to generate a second cooling stream, (IV) The step of bringing the second cooling stream into contact with the second quench medium in the quench tower, (V) A step of recovering from the quench tower a gas stream containing one or more dehydrogenated hydrocarbons, a condensed first quench medium stream, and a slurry stream containing at least a portion of the liquid phase second quench medium and the encompassed coking catalyst particles, (VI) A step of recirculating at least a portion of the condensed first quench medium back to step (III), (VII) Separating at least a portion of the encompassed coking catalyst particles from the slurry stream to provide a recovered second quench medium stream and a recovered encompassed coking catalyst particle stream, (VIII) The step of recirculating at least a portion of the recovered second quench medium stream to step (IV) Includes, The process wherein the dehydrogenation catalyst particles comprise a group 8 to 10 element disposed on a support, and a promoter comprising Sn, Cu, Au, Ag, Ga, a combination thereof, or a mixture thereof.

2. moreover, (IX) The steps of bringing at least a portion of the coking catalyst particles in the first stream and at least a portion of the coking catalyst particles in the recovered entrained catalyst particle stream into contact with an oxidizer and optionally fuel in a combustion zone to cause combustion of the coke and, if present, at least a portion of the fuel, thereby generating a combustion effluent containing regenerated catalyst particles and combustion gas with less coke, (X) A step of separating the combustion gas stream and the regenerated catalyst particle stream, (XI) The step of bringing an additional amount of the hydrocarbon-containing feed into contact with the fluid regenerative catalyst particles from the regenerative catalyst particle stream to generate an additional conversion effluent containing recoking catalyst particles and one or more additional dehydrogenated hydrocarbons. The process according to claim 1, including the process described in claim 1.

3. The process is (XII) A step of transporting at least a portion of the recovered enclosed catalyst particle stream to a metal recycling facility, (XIII) A step of recovering at least a portion of the Group 8 to 10 elements from the coking catalyst particles in the recovered encompassed coking catalyst particle stream. The process according to claim 1 or claim 2, further comprising:

4. The conversion effluent further contains benzene, and the process is, The process according to claim 1 or 2, further comprising the step of removing a benzene product stream from the quench tower, wherein the first quench medium comprises at least a portion of the benzene product stream removed from the quench tower.

5. The process according to claim 1 or 2, wherein the first stream and the second stream are separated from the conversion effluent in one or more cyclones, and the second stream is brought into contact with the first quench medium in at least one plenum of the one or more cyclones.

6. The process according to claim 1 or 2, wherein the first stream and the second stream are separated from the conversion effluent in a primary separator and a secondary separator located downstream of the primary separator and in fluid communication with the primary separator, and the second stream is brought into contact with the first quench medium in the plenum of the secondary separator.

7. The process according to claim 1 or 2, wherein the first stream and the second stream are separated from the conversion effluent in one or more gas-solid separators, and the second stream is in contact with the first quench medium in a transfer line that is fluidly connected to the one or more gas-solid separators and the quench tower.

8. The process according to claim 1 or 2, wherein the first quenching medium and / or the second quenching medium comprises benzene, water, or a polycyclic aromatic hydrocarbon having a standard boiling point of <580°C, or a mixture thereof.

9. The process according to claim 1 or claim 2, wherein the second quenching medium has a standard boiling point higher than the standard boiling point of the first quenching medium.

10. The process according to claim 1 or 2, wherein the first quenching medium comprises a liquid hydrocarbon and any non-solid component in the second cooling stream is entirely in the gas phase.

11. The process according to claim 1 or 2, wherein the converted effluent is at a temperature of ≥620°C and the second cooling stream is at a temperature of ≥500°C and <620°C.

12. The process according to claim 1 or 2, wherein the dehydrogenation catalyst particles comprise 0.001 wt% to 6 wt% of the group 8 to 10 elements and up to 10 wt% of the promoter, all mass percentage values ​​being based on the mass of the support.

13. The process according to claim 1 or 2, wherein the dehydrogenation catalyst particles comprise 0.001 wt% to 6 wt% of Pt and up to 10 wt% of the promoter, and the support comprises at least 0.5 wt% of a group 2 element, and all mass percentage values ​​are based on the mass of the support.

14. The dehydrogenation catalyst particles were measured according to ASTM D7481-18, modified to have a median particle size in the range of 10 μm to 500 μm and using 10, 25, or 50 mL graduated cylinders instead of 100 or 250 mL graduated cylinders, and measured to be 0.3 g / cm³. 3 ~2g / cm³ 3 The process according to claim 1 or claim 2, having an apparent loose bulk density in the range of .

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

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