Methods for producing petrochemical products using fluidized catalytic cracking

Abstract

The embodiment relates to a method of operating a fluidized catalytic cracking unit, comprising: reacting a heavy hydrocarbon feedstock with a first catalyst to produce a first cracking effluent and a first spent catalyst deposited thereon with coke; reacting a light hydrocarbon feedstock with a second catalyst to produce a second cracking effluent and a second spent catalyst deposited thereon with coke; regenerating the first and second spent catalysts in a shared regenerator by burning the coke deposited on the first and second spent catalysts to form a fresh catalyst, the fresh catalyst being returned as the first catalyst to a first reaction zone and as the second catalyst to a second reaction zone, wherein: both the first and second reaction zones are fluidized catalytic cracking zones operating under high-critical conditions; and the shared regenerator operates without supplemental fuel or a catalyst cooler.

Description

Cross-references to related applications

[0001] This application claims priority to U.S. Application Serial No. 18 / 419,057, filed January 22, 2024, the entire disclosure of which is incorporated herein by reference. Technical Field

[0002] The embodiments of this disclosure generally relate to chemical processing, and more specifically, to methods and systems utilizing fluidized catalytic cracking. Background Technology

[0003] The growing global demand for light olefins, such as ethylene, propylene, and butene, remains a major challenge for many integrated refineries. In particular, the production of ethylene and propylene has received increasing attention as pure olefin streams are considered the cornerstone of polymer synthesis. Light olefins can be produced via fluidized catalytic cracking (FCC) processes. Typical hydrocarbon feedstocks for FCC processes range from hydrocracking tail oil to heavy feed fractions, such as vacuum gas oil and atmospheric residue. However, the supply of these hydrocarbon feedstocks is limited.

[0004] During FCC operation, the feedstock reacts in the presence of a catalyst, forming coke on the catalyst surface, which deactivates the catalyst. The coked catalyst is conveyed to a regenerator, where the coke is burned to regenerate and heat the catalyst. The hot, regenerated catalyst is then transferred back to the reactor to provide heat for the endothermic cracking reaction. However, the heat provided by the coke is often insufficient, requiring the use of coking agents and / or supplemental fuel. Alternatively, the amount of coke formed is often excessive, necessitating the use of expensive catalyst cooling systems to prevent overheating of the FCC reactor. Summary of the Invention

[0005] Therefore, there has been a need for an integrated process capable of producing intermediate compounds from relatively common hydrocarbon feedstocks with minimal processing and operating without the need for supplemental fuel, coking agents, and catalyst coolers. Embodiments of this disclosure address this need by providing a method for operating an FCC with two reaction zones and a shared regenerator, wherein different feedstocks are fed to each reaction zone, such that coke from the first reaction zone can balance the coke deficit in the second reaction zone by appropriate feedstock selection. The feedstock fed to the first reaction zone may include whole crude oil. The feedstock fed to the second reaction zone may include whole crude oil or whole condensate, and may be lighter than the feedstock fed to the first reaction zone (e.g., having a lower API density, a lower boiling point range, or both). Using crude hydrocarbon feedstocks with these different API densities balances the heat load between the two reactions, thus eliminating the need for supplemental fuel or catalyst coolers. Furthermore, using these complete, relatively unprocessed hydrocarbon feedstocks allows for the utilization of widely available feedstocks with minimal processing requirements.

[0006] According to one or more embodiments, a method of operating fluidized catalysis includes: feeding a heavy hydrocarbon feedstock and a first catalyst to a first reaction zone to produce a first cracking effluent and a first spent catalyst deposited thereon with coke; feeding a light hydrocarbon feedstock and a second catalyst to a second reaction zone to produce a second cracking effluent and a second spent catalyst deposited thereon with coke; feeding the first spent catalyst and the second spent catalyst to a shared regenerator; in the shared regenerator, regenerating the first spent catalyst and the second spent catalyst by burning the coke deposited on the first spent catalyst and the second spent catalyst to form a fresh catalyst, the fresh catalyst being fed back to the first reaction zone as the first catalyst and back to the second reaction zone as the second catalyst, wherein: the light hydrocarbon feedstock has an API weight of 38° to 55°; the heavy hydrocarbon feedstock comprises crude oil and has an API weight of 20° to 35°; both the first reaction zone and the second reaction zone are fluidized catalytic cracking zones operating under high-critical conditions; and the shared regenerator operates without supplemental fuel or a catalyst cooler.

[0007] These and other embodiments are described in more detail in the Detailed Description. It should be understood that the foregoing overview and the following Detailed Description present embodiments of the present disclosure and are intended to provide an overview or framework for understanding the nature and features of the claimed technology. The accompanying drawings are included to provide a further understanding of the present disclosure and form part of this specification. The drawings illustrate various embodiments and, together with the description, serve to explain the principles and operation of the present disclosure. Furthermore, the drawings and description are illustrative only and are not intended to limit the scope of the claims in any way. Attached Figure Description

[0008] The following detailed description of specific embodiments of this disclosure can be best understood when read in conjunction with the following accompanying drawings, wherein similar structures are indicated by similar reference numerals, and in the drawings: Figure 1 The relative properties of various hydrocarbon feed streams for producing one or more petrochemical products according to one or more embodiments described in this disclosure are illustrated. Figure 2 This is a general schematic diagram of a hydrocarbon feed conversion system according to one or more embodiments described in this disclosure; and Figure 3 One or more embodiments according to the present disclosure are depicted. Figure 2 A schematic diagram of at least a portion of the system's hydrocarbon feed conversion system.

[0009] For the purpose of providing a simplified schematic and illustrative description of the accompanying drawings, numerous valves, temperature sensors, electronic controllers, etc., that may be used in certain chemical processing operations and are well known to those skilled in the art, are not included. Furthermore, accompanying components typically included in typical chemical processing operations, such as air supplies, catalyst hoppers, and flue gas treatment systems, are not depicted. However, the operating components described in this disclosure may be added to the embodiments described herein.

[0010] It should also be noted that the arrows in the accompanying drawings refer to process streams. However, arrows can also equivalently refer to delivery lines used to transport process streams between two or more system components. Furthermore, arrows connected to system components define the inlet or outlet of each given system component. The direction of the arrows generally corresponds to the primary direction of movement of the stream material contained within the physical delivery line indicated by the arrow. Additionally, arrows not connected to two or more system components indicate product streams leaving the illustrated system or system inlet streams entering the illustrated system. Product streams may be further processed in the associated chemical processing system or may be commercialized as a final product. System inlet streams may be streams delivered from the associated chemical processing system or unprocessed raw material streams. Some arrows may indicate recycle streams, i.e., outflow streams from system components that are recycled back into the system. However, it should be understood that in some embodiments, any indicated recycle stream may be replaced by a system inlet stream of the same material, and a portion of the recycle stream may leave the system as a system product.

[0011] Furthermore, the arrows in the accompanying drawings can schematically depict the process steps of transporting material from one system component to another. For example, an arrow pointing from one system component to another can indicate the "transfer" of the effluent from one system component to another, which may include the "departure" or "removal" of the process material contents from one system component and the "introduction" of the contents of that product stream to another system component. It should be understood that the arrows in the relevant accompanying drawings do not represent necessary or required steps.

[0012] It should be understood that, according to the embodiments presented in the relevant figures, the arrow between two system components may indicate that the logistics flow is unprocessed between the two system components. In other embodiments, the logistics flow indicated by the arrow may have substantially the same composition throughout the transport between the two system components. Furthermore, it should be understood that in one or more embodiments, the arrow may indicate that at least 75% by weight, at least 90% by weight, at least 95% by weight, at least 99% by weight, at least 99.9% by weight, or even 100% by weight of the logistics flow is transported between the system components. Therefore, in some embodiments, not all of the logistics flow indicated by the arrow may be transported between the system components, for example, if a branch is present.

[0013] It should be understood that when two or more lines intersect in the schematic flow diagram of the relevant figures, two or more process streams are “mixed” or “combined.” Mixing or combining can also include mixing by directly introducing the two streams into a similar reactor, separation unit, or other system component. For example, it should be understood that when two streams are depicted as being combined directly before entering a separation unit or reactor, in some embodiments, the streams may be equivalently introduced into the separation unit or reactor and mixed therein.

[0014] Reference will now be made in more detail to various embodiments, some of which are illustrated in the accompanying drawings. Wherever possible, the same reference numerals will be used in all the drawings to refer to the same or similar parts. Detailed Implementation

[0015] Embodiments of this disclosure relate to a method of operating a fluidized catalytic cracking unit. Generally, these methods are described herein in conjunction with one or more systems shown in the accompanying drawings. Figure 2-3 The implementations are similar or identical in many respects, but include the differences described herein. As those skilled in the art will understand, for Figure 2-3 The description of the embodiments herein is generally applicable to embodiments in other figures. For example, the embodiments disclosed herein are applicable to… Figure 2 The concept can also be applied to Figure 3 Conversely, the same applies, even if this is not explicitly stated in this article.

[0016] As used in this disclosure, a "reactor" refers to a vessel in which one or more reactants optionally undergo one or more chemical reactions in the presence of one or more catalysts. For example, a reactor may include a tank or tubular reactor configured to operate as a batch reactor, a continuous stirred tank reactor ("CSTR"), or a plug flow reactor. Exemplary reactors include packed bed reactors (such as fixed bed reactors) and fluidized bed reactors. One or more "reaction zones" may be provided within the reactor. As used in this disclosure, a "reaction zone" refers to a region within the reactor where a specific reaction occurs. For example, a packed bed reactor having multiple catalyst beds may have multiple reaction zones, wherein each reaction zone is defined by a region of each catalyst bed.

[0017] As used in this disclosure, a "separation unit" means any separation device that at least partially separates one or more chemicals mixed in a process stream from each other. For example, a separation unit may selectively separate materials of different chemicals, phases, or sizes to form one or more chemical fractions. Examples of separation units include, but are not limited to, distillation columns, flash tanks, separators, centrifuges, cyclone separators, filters, traps, scrubbers, expansion devices, membranes, solvent extraction devices, etc. It should be understood that the separation processes described in this disclosure may not completely separate all of one chemical component from all of another chemical component. It should be understood that the separation processes described in this disclosure "at least partially" separate different chemical components from each other, and even if not explicitly stated, separation may only include partial separation. As used in this disclosure, one or more chemical components may be "separated" from a process stream to form a new process stream. Typically, a process stream may enter a separation unit and be divided or separated into two or more process streams of the desired composition.

[0018] As used in this disclosure, the term “highly demanding conditions” generally refers to an FCC temperature of 500°C or higher, a catalyst-to-hydrocarbon weight ratio (“catalyst-to-oil ratio” or “CTO”) equal to or greater than 5:1, and a residence time of less than 3 seconds, all of which may be more demanding than typical FCC reaction conditions.

[0019] It should be understood that "effluent" generally refers to the stream that leaves a system component (e.g., a separation unit, reactor, or reaction zone) after a specific reaction or separation, and typically has a different composition (at least proportionally) from the stream that enters the separation unit, reactor, or reaction zone.

[0020] As used in this disclosure, "catalyst" means any substance that increases the rate of a particular chemical reaction. The catalysts described in this disclosure can be used to promote a variety of reactions, such as, but not limited to, cracking (including aromatic cracking), demetallization, desulfurization, and denitrification. As used in this disclosure, "cracking" generally refers to a chemical reaction involving the breaking of carbon-carbon bonds. For example, a molecule having carbon-carbon bonds may break into multiple molecules through the breaking of one or more carbon-carbon bonds, or a compound containing cyclic moieties (such as cycloalkanes, naphthalenes, aromatics, etc.) may be converted into a compound that does not contain cyclic moieties or contains fewer cyclic moieties than before cracking.

[0021] As used in this disclosure, the term "first catalyst" refers to a catalyst introduced into a first FCC reactor unit, such as a catalyst transferred to a first FCC reactor unit. The first catalyst may include at least one or a combination of a regenerated catalyst, a first spent catalyst, a second spent catalyst, and a fresh catalyst. As used in this disclosure, the term "second catalyst" refers to a catalyst introduced into a second reaction zone, such as a catalyst transferred to a second reaction zone. The second catalyst may include at least one or a combination of a regenerated catalyst, a first spent catalyst, a second spent catalyst, and a fresh catalyst.

[0022] As used in this disclosure, the term "awaited catalyst" refers to a catalyst that has been introduced into and passed through the reaction zone to crack hydrocarbon feedstocks (e.g., heavy or light hydrocarbon feedstocks) but has not yet been regenerated in a regenerator after introduction into the reaction zone. "Awaited catalyst" may have coke deposited on it and may include partially coked catalyst as well as fully coked catalyst. The amount of coke deposited on the "awaited catalyst" may be greater than the amount of coke remaining on the regenerated catalyst after regeneration. "Second awaited catalyst" may refer to an awaited catalyst that has coked in a second FCC reactor unit since the last regeneration. "First awaited catalyst" may refer to an awaited catalyst that has coked in a first reaction zone since the last regeneration.

[0023] As used in this disclosure, the term "regenerated catalyst" refers to a catalyst that has been introduced into the reaction zone and then regenerated in a regenerator to heat the catalyst to a higher temperature, oxidize and remove at least a portion of the coke on the catalyst to restore at least a portion of the catalyst's catalytic activity, or both. Compared to the undried catalyst, the "regenerated catalyst" may have less coke, a higher temperature, or both, and may have higher catalytic activity. Compared to fresh catalyst that has not passed through the reaction zone and regenerator, the "regenerated catalyst" may have more coke and lower catalytic activity.

[0024] It should also be understood that a logistics stream can be named after its components, and the components named after these components can be the main components of the logistics stream (e.g., accounting for 50% by weight (“weight%”), 70% by weight, 90% by weight, 95% by weight, 99% by weight, 99.5% by weight, or even 99.9% by weight up to 100% by weight of the logistics stream content). It should also be understood that disclosing the transfer of a logistics stream containing a certain component from one system component to another is equivalent to disclosing the transfer of that component from one system component to another. For example, disclosing a “propylene logistics stream” transferred from a first system component to a second system component should be understood as equivalent to disclosing the transfer of “propylene” from the first system component to the second system component, and so on.

[0025] Now for reference Figure 2 and Figure 3Generally, a hydrocarbon feed conversion system 100 includes two FCC reaction zones. In each zone, the hydrocarbon feed stream is contacted with heated fluidized catalyst particles in a reaction zone maintained at high and harsh temperatures and pressures. As a portion of the hydrocarbon feed stream contacts the hot catalyst and is cracked into lighter products, carbonaceous deposits (commonly referred to as coke) form on the catalyst. The coke deposits formed on the catalyst can reduce its catalytic activity or deactivate it. Catalyst deactivation can lead to catalytic deactivation. The spent catalyst with coke deposits can be separated from the cracking products, removing removable hydrocarbons, and enter a regeneration process where the coke is burned off the catalyst in the presence of air, producing a catalytically active regenerated catalyst. The term "catalytically active" refers to the ability of the regenerated catalyst to increase the cracking rate. The term "catalytic activity" refers to the degree to which the regenerated catalyst increases the cracking rate and may be related to the number of available catalytically active sites on the catalyst. For example, coke deposits on the catalyst may cover or block catalytic active sites on the spent catalyst, reducing the number of available active sites and potentially decreasing the catalyst's catalytic activity. After regeneration, the coke content of the regenerated catalyst may be equal to or less than 10% by weight, 5% by weight, or even 1% by weight, based on the total weight of the regenerated catalyst. Combustion products can be removed from the regeneration process as flue gas. The heated regenerated catalyst can then be recycled back to the reaction zone of the FCC unit.

[0026] Still referencing Figure 2 and Figure 3 The diagram schematically depicts a hydrocarbon feed conversion system 100. The hydrocarbon feed conversion system 100 can be a high-severity fluidized catalytic cracking (“HSFCC”) system. The hydrocarbon feed conversion system 100 typically receives heavy hydrocarbon feed 106 and light hydrocarbon feed 108, and directly processes the heavy hydrocarbon feed 106 and light hydrocarbon feed 108 to produce one or more system product streams. The hydrocarbon feed conversion system 100 may include a first FCC reactor unit 120, a second FCC reactor unit 140, and a common regenerator 160. These system components and their various arrangements will be described in detail herein.

[0027] In some embodiments, light hydrocarbon feed 108 may be fed to a second FCC reactor unit 140 to form a second cracked effluent 148 and a second spent catalyst 146. Similarly, heavy hydrocarbon feed 106 may be fed to a first FCC reactor unit 120 to form a first cracked effluent 128 and a first spent catalyst 126.

[0028] Heavy hydrocarbon feed 106 may include whole crude oil. Crude oil may be previously unprocessed raw hydrocarbons, such as those unprocessed by one or more of the following methods: distillation, cracking, hydrotreating, desalting, or dehydration. In embodiments, the crude oil may have undergone at least some processing, such as desalting, solids separation, washing, desulfurization, or a combination of these methods, but has not yet undergone boiling-point separation (e.g., distillation). For example, the crude oil may be desalted crude oil that has undergone a desalting process or hydrotreated crude oil that has undergone a hydrotreating process. In embodiments, the crude oil may not have undergone pretreatment, separation (e.g., distillation), or other operations that alter its hydrocarbon composition before being introduced into the process. As used herein, “hydrocarbon composition” of crude oil refers to the composition of hydrocarbon components in the crude oil and excludes entrained non-hydrocarbon solids, salts, water, or other non-hydrocarbon components. The oil in the heavy hydrocarbon feed 106 may have an American Petroleum Institute (“API”) density of 20° to 35°, such as API density of 20° to 33°, 20° to 30°, 20° to 28°, 20° to 26°, 20° to 24°, 22° to 35°, 24° to 35°, 24° to 30°, 26° to 35°, 28° to 35°, 30° to 35°, 32° to 35°, 22.5° to 32.5°, 25° to 30°, or any combination of these ranges. In an embodiment, the heavy hydrocarbon feed 106 may be Arab Heavy Crude Oil (crude oil with an API density of approximately 26.8°). Table 1 provides example properties of Arab Heavy Crude Oil.

[0029] Table 1

[0030] Light hydrocarbon feed 108 may include hydrocarbons, for example, at least 90% by weight, at least 95% by weight, or at least 99% by weight of hydrocarbons based on the total weight of said light hydrocarbon feed 108. Light hydrocarbon feed 108 may be crude oil or condensate. Condensate (also known as natural gas liquid or natural gas condensate) refers to a mixture of relatively low-boiling-point hydrocarbon liquids obtained by condensing the vapors of these relatively low-boiling-point hydrocarbon liquid components in a natural gas well or as a natural gas stream flows from the well. Light hydrocarbon feed 108 may be previously unprocessed raw hydrocarbons, for example, unprocessed by one or more of distillation, cracking, hydrotreating, desalting, or dehydration. In embodiments, light hydrocarbon feed 108 may have undergone at least some processing, such as desalting, solids separation, washing, desulfurization, or a combination of these, but has not been distilled. For example, light hydrocarbon feed 108 may be a desalted hydrocarbon feed stream that has undergone a desalting process, or a hydrotreated hydrocarbon feed stream that has undergone a hydrotreating process but has not undergone a distillation process. In this embodiment, the light hydrocarbon feed 108 may not undergo pretreatment, separation (e.g., distillation), or other operations that alter the hydrocarbon composition of the crude hydrocarbon stream before introducing the hydrocarbon stream into the process. The API density of the light hydrocarbon feed 108 may be 38° to 55°, for example, 40° to 55°, 42° to 55°, 44° to 55°, 46° to 55°, 48° to 55°, 50° to 55°, 52° to 55°, 38° to 52°, 38° to 50°, 38° to 48°, 38° to 46°, 38° to 44°, 38° to 43°, 40.5° to 52.5°, 43° to 50°, 45.5° to 47.5°, or any subset thereof. In this embodiment, the light hydrocarbon feed 108 may include Arab ExtraLight Crude Oil (crude oil with an API density of approximately 40.5°) or Khuff condensate (condensate with an API density of approximately 52.26°).

[0031] In this embodiment, the API specific gravity of light hydrocarbon feed 108 is higher than that of heavy hydrocarbon feed 106. Generally, heavier hydrocarbon feeds (i.e., feeds with lower API specific gravity) produce more coke during cracking than lighter hydrocarbon feeds. Therefore, combining light hydrocarbon feed 108 with a higher API specific gravity than heavy hydrocarbon feed 106 allows the operator to adjust coke production (and thus heat generation in the shared regenerator 160) by selecting feeds with different API specific gravity. In an embodiment, the API specific gravity of the light hydrocarbon feed 108 may be at least 5° higher than that of the heavy hydrocarbon feed 106, for example at least 10°, at least 12°, at least 15°, at least 20°, or at least 25° higher, or 5° to 30°, 5° to 50°, 5° to 25°, 10° to 30°, 12° to 30°, 12° to 25°, 15° to 30°, 20° to 30°, 25° to 50°, 25° to 40°, 25° to 35°, 25° to 30°, or any combination of these ranges.

[0032] In an embodiment, the flow rate of heavy hydrocarbon feed 106 may be at least 5% greater than the flow rate of light hydrocarbon feed 108, for example at least 10%, at least 20%, 5% to 50%, 5% to 10%, 10% to 15%, 15% to 20%, 20% to 25%, 25% to 30%, 30% to 40%, 40% to 50%, or any combination of these ranges.

[0033] In one or more embodiments, the light hydrocarbon feed stream and the heavy hydrocarbon feed stream are preheated before being injected into the reactor. The preheating temperature of the feed and the temperature of the regenerated catalyst are controlled by the catalyst-to-oil ratio. The flow rate of the hydrocarbon feed can be adjusted by a flow controller via feed injectors. The pressure of each feed injector determines the flow rate of the light hydrocarbon feed and the heavy hydrocarbon feed. The atomized hydrocarbon feed can be mixed with dispersed steam upon injection into the reactor.

[0034] Now for reference Figure 1Various hydrocarbon feed streams to be converted in conventional FCC processes typically need to meet certain criteria in terms of metal content and Conradson Carbon Residue (CCR) or Ramsbottom carbon content. The CCR of a feedstock is a measure of the carbonaceous material remaining after the feedstock undergoes evaporation and pyrolysis. Higher metal content and CCR in the feedstream can lead to faster catalyst deactivation. For higher CCR contents, more energy may be required in the regeneration step to regenerate the catalyst. For example, some hydrocarbon feedstocks, such as residue oil, contain refractory components, such as polycyclic aromatic hydrocarbons (PAHs), which are difficult to crack and promote coke formation, in addition to the coke formed during catalytic cracking. Due to the high CCR content of these specific hydrocarbon feedstocks, the combustion load on the regenerator is increased to remove coke and residue from the spent catalyst, thus converting it into a regenerated catalyst. This requires modifications to the regenerator to withstand the increased combustion load without material failure. Furthermore, some hydrocarbon feedstocks entering the FCC may contain significant amounts of metals, such as nickel, vanadium, or other metals, which can rapidly deactivate the catalyst during the cracking reaction. For example, the CCR of light hydrocarbon feedstocks may be less than 2.0 wt%, less than 1.0 wt%, or less than 0.1 wt%, while the CCR of heavy hydrocarbon feedstocks may be greater than 2.0 wt% or greater than 5.0 wt%.

[0035] Refer again Figure 2 and Figure 3 One or more supplemental feed streams (not shown) may be added to light hydrocarbon feed 108, heavy hydrocarbon feed 106, or both to introduce hydrocarbon feeds into their respective reaction zones. As previously described, in one or more embodiments, heavy hydrocarbon feed 106 may be crude oil. Light hydrocarbon feed 108 may be crude oil or total condensate.

[0036] In some embodiments not shown in the figures, a coke precursor may be added to the heavy hydrocarbon feed 106 or light hydrocarbon feed 108 before introducing them into their respective reaction zones. The coke precursor is a compound intended to increase coke yield during the reaction process. Considered coke precursors include polycyclic aromatic compounds. Further considered coke precursors include flare oil, which comprises a mixture of light cycle oil (e.g., oil with a boiling point of 216°C to 359°C) and slurry oil (e.g., oil with a boiling point greater than 359°C). In embodiments, the coke precursor may be contacted with the catalyst after the catalyst leaves the reactor and before the catalyst is injected into the regenerator. In embodiments, the heavy hydrocarbon feed 106 may contain less than 1% by weight, less than 0.5% by weight, less than 0.1% by weight, or less than 0.01% by weight of the added coke precursor (e.g., a compound not naturally present in crude oil). In an embodiment, the light hydrocarbon feed 108 may contain less than 1% by weight, less than 0.5% by weight, less than 0.1% by weight, or less than 0.01% by weight of added coke precursors (e.g., compounds not naturally present in crude oil or condensate).

[0037] Still referencing Figure 2 and Figure 3 Heavy hydrocarbon feed 106 can be conveyed to the first FCC reactor unit 120. Heavy hydrocarbon feed 106 can be added to the first catalyst mixing zone 136. Heavy hydrocarbon feed 106 can be combined or mixed with the first catalyst 124 and cracked to produce a mixture of a first spent catalyst 126 and a first crack effluent 128. The first spent catalyst 126 can be separated from the first crack effluent 128 and conveyed to the regeneration zone 162 of the common regenerator 160.

[0038] Light hydrocarbon feed 108 can be conveyed to a second FCC reactor unit 140, which includes a second reaction zone 142. Light hydrocarbon feed 108 can be mixed with and cracked with a second catalyst 144 to produce a second spent catalyst 146 and a second cracked effluent 148. The second spent catalyst 146 can be separated from the second cracked effluent 148 and conveyed to the regeneration zone 162 of a common regenerator 160.

[0039] In some embodiments, steam (not shown) may be introduced into the hydrocarbon feed conversion system 100. In this embodiment, steam may be introduced into at least one of the heavy hydrocarbon feed 106 and the light hydrocarbon feed 108. The steam may act as a diluent to reduce the hydrocarbon partial pressure of at least one of the heavy hydrocarbon feed 106 and the light hydrocarbon feed 108. The steam may reduce secondary reactions and result in a high yield of light olefins.

[0040] The first and second spent catalysts 126 and 146 can be combined and regenerated in the regeneration zone 162 of a common regenerator 160 to produce a regenerated catalyst 116. The regenerated catalyst 116 has a catalytic activity at least greater than that of the first and second spent catalysts 126 and 146. The regenerated catalyst 116 can then be transferred back to the first and second reaction zones 122 and 142. The first and second reaction zones 122 can operate in parallel.

[0041] It should be understood that in some embodiments, the first catalyst 124 and the second catalyst 144 have the same composition, and the first catalyst 124 and the second catalyst 144 can be regenerated in the regeneration zone 162 of the common regenerator 160, such as... Figure 3 As shown.

[0042] Still referencing Figure 2 and Figure 3 In this embodiment, the hydrocarbon feed conversion system 100 may include at least one catalyst recycler, such as a second catalyst 144 and a second recycled catalyst 146. The first crack effluent 128 and the second crack effluent 148 may each include a mixture of cracked hydrocarbon materials, which may be further separated into one or more higher-value petrochemical products and recovered from the system in one or more system product streams. For example, the first crack effluent 128, the second crack effluent 148, or both may include petrochemical products. The petrochemical products may be at least one of ethylene, propylene, butene, or pentene. For example, the first crack effluent 128, the second crack effluent 148, or both may include one or more of cracked gas oil, cracked gasoline, cracked naphtha, mixed butene, butadiene, propylene, ethylene, other olefins, ethane, methane, other petrochemical products, or combinations thereof. The cracked gasoline may be further processed to obtain aromatics, such as benzene, toluene, xylene, or other aromatics. The hydrocarbon feed conversion system 100 may include a product separator 112. The first cracking effluent 128, the second cracking effluent 148, or both the first cracking effluent 128 and the second cracking effluent 148 can be introduced into the product separator 112 to separate these streams into multiple system product streams. In some embodiments, the first cracking effluent 128 and the second cracking effluent 148 can be combined into a combined cracking reaction product stream 114. The combined cracking reaction product stream 114 can be introduced into the product separator 112. Reference Figure 2 and Figure 3 The product separator 112 may be fluidly connected to the first separation zone 130, the second separation zone 150, or both the first separation zone 130 and the second separation zone 150. In an embodiment, the first stripping product stream 134 and the second stripping product stream 154 may be combined to form a mixed stripping product stream.

[0043] Now for reference Figure 2 Product separator 112 may be a distillation column or a collection of separation units that separates 128, the second crack effluent 148, or a combination of cracking reaction product streams 114 into one or more system product streams. These system product streams may include fuel oil stream 181, gasoline stream 182, mixed butene stream 183, butadiene stream 184, propylene stream 185, ethylene stream 186, methane stream 187, light recycle oil stream (e.g., streams with boiling points in the range of 216°C-343°C) 188, heavy recycle oil stream (e.g., streams with boiling points >343°C) 189, other product streams or combinations of these streams, and one or more of hydrogen streams 110. Each system product stream may be fed to one or more additional unit operations for further processing or may be sold as raw material. In an embodiment, the first crack effluent 128 and the second crack effluent 148 may be introduced into product separator 112, respectively. As used in this disclosure, the one or more system product streams may be referred to as petrochemical products, which may be used as intermediates for downstream chemical processing or packaged as finished products. The product separator 112 may also generate one or more recirculated oil streams, which may be recycled back to the hydrocarbon feed conversion system 100.

[0044] Now for reference Figure 3The first FCC reactor unit 120 may include a first catalyst mixing zone 136, a first reaction zone 122, a first separation zone 130, and a first stripping zone 132. Heavy hydrocarbon feed 106 may be introduced into the first catalyst mixing zone 136, where it may be mixed with a first catalyst 124. During steady-state operation of the hydrocarbon feed conversion system 100, the first catalyst 124 may include at least a regenerated catalyst 116 fed from the catalyst hopper 174 to the first catalyst mixing zone 136. In one embodiment, the first catalyst 124 may be a mixture of a first spent catalyst 126 and a regenerated catalyst 116. Alternatively, the first catalyst 124 may be a mixture of a second spent catalyst 146 and a regenerated catalyst 116. The catalyst hopper 174 may receive the regenerated catalyst 116 from a common regenerator 160. During the initial startup of the hydrocarbon feed conversion system 100, the first catalyst 124 may include fresh catalyst (not shown), which is catalyst that has not yet been circulated through the first FCC reactor unit 120 or the second FCC reactor unit 140 and the common regenerator 160. Since the fresh catalyst has not yet been circulated through the reaction zone, it may have higher catalytic activity than the regenerated catalyst 116. In an embodiment, fresh catalyst may also be introduced into the catalyst hopper 174 during operation of the hydrocarbon feed conversion system 100, such that a portion of the first catalyst 124 introduced into the first catalyst mixing zone 136 includes fresh catalyst. During operation, fresh catalyst may be periodically introduced into the catalyst hopper 174 to replenish lost catalyst or compensate for deactivated catalyst due to reasons such as heavy metal accumulation in the catalyst.

[0045] In some embodiments, one or more supplementary feed streams (not shown) may be combined with the heavy hydrocarbon feed 106 before it is introduced into the first catalyst mixing zone 136. In other embodiments, one or more supplementary feed streams may be added directly to the first catalyst mixing zone 136, where they may be mixed with the heavy hydrocarbon feed 106 and the first catalyst 124 before being introduced into the first reaction zone 122. In some embodiments, no supplementary feed stream is combined with the heavy hydrocarbon feed 106. As previously described, the supplementary feed stream may include one or more of vacuum residue, oil sands, bitumen, atmospheric residue, vacuum gas oil, demetallized oil, naphtha stream, other hydrocarbon streams, or combinations thereof.

[0046] A mixture comprising heavy hydrocarbon feed 106 and a first catalyst 124 may be conveyed from a first catalyst mixing zone 136 to a first reaction zone 122. The mixture of heavy hydrocarbon feed 106 and the first catalyst 124 may be introduced into the top portion of the first reaction zone 122. The first reaction zone 122 may be a downflow reactor or a "downstream" reactor, wherein reactants flow vertically downwards from the first catalyst mixing zone 136 through the first reaction zone 122 to a first separation zone 130. The heavy hydrocarbon feed 106 may be reacted by contacting the first catalyst 124 in the first reaction zone 122, such that at least a portion of the heavy hydrocarbon feed 106 undergoes at least a cracking reaction to form at least one cracking product, which may include at least one of the previously described petrochemical products. The temperature of the first catalyst 124 may be equal to or greater than the first cracking temperature T of the first reaction zone 122. 122 It can also transfer heat to the heavy hydrocarbon feed 106 to promote the endothermic cracking reaction.

[0047] It should be understood that Figure 3 The first reaction zone 122 of the first FCC reactor unit 120 depicted is a simplified schematic diagram of a specific embodiment of the first reaction zone 122 of the FCC unit, and other configurations of the first reaction zone 122 may also be suitable for incorporation into the hydrocarbon feed conversion system 100. For example, in some embodiments, the first reaction zone 122 may be an upflow reaction zone. Other reaction zone configurations are also covered. The first FCC reactor unit 120 may be a hydrocarbon feed conversion unit, wherein in the first reaction zone 122, a fluidized first catalyst 124 is contacted with the heavy hydrocarbon feed 106 under high-severity conditions. The first cracking temperature T of the first reaction zone 122 is... 122 The temperature can be 500°C to 800°C, 500°C to 700°C, 500°C to 650°C, 500°C to 600°C, 550°C to 800°C, 550°C to 700°C, 550°C to 650°C, 550°C to 600°C, 600°C to 800°C, 600°C to 700°C, or 600°C to 650°C. In one or more embodiments, the first cracking temperature T of the first reaction zone 122 is... 122 The temperature can be from 500°C to 700°C. In one or more embodiments, the first cracking temperature T of the first reaction zone 122 is... 122 It can range from 550℃ to 630℃.

[0048] In the first reaction zone 122, the weight ratio of the first catalyst 124 to the heavy hydrocarbon feed 106 (the ratio of catalyst to hydrocarbon) can be 5:1 to 40:1, 5:1 to 35:1, 5:1 to 30:1, 5:1 to 25:1, 5:1 to 15:1, 5:1 to 10:1, 10:1 to 40:1, 10:1 to 35:1, 10:1 to 30:1, 10:1 to 25:1, 10:1 to 15:1, 15:1 to 40:1, 15:1 to 35:1, 15:1 to 30:1, 15:1 to 25:1, 25:1 to 40:1, 25:1 to 35:1, 25:1 to 30:1, 22:1 to 25:1, 24:1 to 28:1, or 30:1 to 40:1. The residence time of the mixture of the first catalyst 124 and the heavy hydrocarbon feed 106 in the first reaction zone 122 can be 0.2 seconds to 3 seconds, 0.2 seconds to 2.5 seconds, 0.2 seconds to 2 seconds, 0.2 seconds to 1.5 seconds, 0.4 seconds to 3 seconds, 0.4 seconds to 2.5 seconds, or 0.4 seconds to 2 seconds, 0.4 seconds to 1.5 seconds, 1.5 seconds to 3 seconds, 1.5 seconds to 2.5 seconds, 1.5 seconds to 2 seconds, or 2 seconds to 3 seconds.

[0049] The operation of the first reaction zone 122 can convert hydrocarbons in the heavy hydrocarbon feed 106 into coke, which can be deposited on the first catalyst 124 to form a first spent catalyst 126. This coke can provide heat to regenerate the first spent catalyst 126 and provide additional heat to regenerate a second spent catalyst 146 with insufficient coke in the common regenerator 160. The operation of the first reaction zone 122 can convert 5% to 15% by weight of hydrocarbons in the heavy hydrocarbon feed 106 into coke. In an embodiment, the operation of the first reaction zone 122 can convert 5% to 6% by weight, 6% to 7% by weight, 7% to 8% by weight, 8% to 9% by weight, 9% to 10% by weight, 10% to 11% by weight, 11% to 12% by weight, 12% to 13% by weight, 13% to 14% by weight, 14% to 15% by weight, 6% to 9% by weight, 8% to 11% by weight, or any combination of these ranges of hydrocarbons in the heavy hydrocarbon feed 106 into coke.

[0050] Following the cracking reaction in the first reaction zone 122, the contents of the effluent from the first reaction zone 122 may include the first catalyst 124 and the first cracked effluent 128, which may then be conveyed to the first separation zone 130. In the first separation zone 130, the first catalyst 124 may be separated from at least a portion of the first cracked effluent 128. In some embodiments, the first separation zone 130 may include one or more gas-solid separators, such as one or more cyclone separators. The first catalyst 124 exiting the first separation zone 130 may retain at least a portion of the residual first cracked effluent 128.

[0051] Following the first separation zone 130, the first catalyst 124 (which may include a residual portion of the first cracking effluent 128 retained in the first catalyst 124) may be conveyed to the first stripping zone 132, where at least some of the residual portion of the first cracking effluent 128 may be stripped from the first catalyst 124 and recovered as the first stripping product stream 134. The first stripping product stream 134 may be conveyed to one or more downstream unit operations or combined with one or more other streams for further processing. Steam 133 may be introduced into the first stripping zone 132 to facilitate the stripping of the first cracking effluent 128 from the first catalyst 124. The first stripping product stream 134 may include at least a portion of the steam 133 introduced into the first stripping zone 132. The first stripping product stream 134 exiting the first stripping zone 132 may pass through a cyclone separator (not shown) and exit the stripping vessel (not shown). The first stripping product stream 134 may be directed to one or more product recovery systems according to methods known in the art, or may be recycled in combination with steam. The first stripping product stream 134 can also be combined with one or more other streams, such as the first cracking effluent 128. The first stripping product stream 134 can also be combined with the second stripping product stream 154. The first spent catalyst 126 (i.e., the first catalyst 124 after stripping from the first stripping product stream 134) can be transferred from the first stripping zone 132 to the regeneration zone 162 of the common regenerator 160 to regenerate and produce a regenerated catalyst 116.

[0052] Still referencing Figure 3 The light hydrocarbon feed 108 can be conveyed to the second FCC reactor unit 140 (e.g., Figure 2 (As shown). The second FCC reactor unit 140 may include a second catalyst mixing zone 156, a second reaction zone 142, a second separation zone 150, and a second stripping zone 152. The catalyst mixing zone fluidizes the catalyst, and if process streams such as an inert carrier gas stream or a light hydrocarbon feed 108 are injected into the second catalyst mixing zone 156, the catalyst can be mixed with these process streams.

[0053] As described herein, the light hydrocarbon feed 108 can be conveyed to the second FCC reactor unit 140. However, this is not the only possibility; several embodiments are considered to achieve such an arrangement. For example, as... Figure 3 As shown, light hydrocarbon feed 108 can be injected into the second reaction zone 142. In another embodiment, light hydrocarbon feed 108 can be injected into the second catalyst mixing zone 156. Although the following disclosure will describe in detail... Figure 3 The embodiment described herein relates to the injection of light hydrocarbon feed 108 (i.e., injection into the second reaction zone 142), but other embodiments should also be considered within the scope of embodiments disclosed herein.

[0054] Still referencing Figure 3 During steady-state operation of the hydrocarbon feed conversion system 100, the second catalyst 144 may include at least a regenerated catalyst 116 fed from the catalyst hopper 174 to the second catalyst mixing zone 156. In an embodiment, the second catalyst 144 may be a mixture of a second spent catalyst 146 and the regenerated catalyst 116. Alternatively, the second catalyst 144 may be a mixture of a first spent catalyst 126 and the regenerated catalyst 116. The catalyst hopper 174 may receive the regenerated catalyst 116 from the common regenerator 160 after the first spent catalyst 126 and the second spent catalyst 146 have been regenerated. During the initial startup of the hydrocarbon feed conversion system 100, the second catalyst 144 may include a fresh catalyst (not shown) that has not yet been circulated through the first FCC reactor unit 120 or the second FCC reactor unit 140 and the common regenerator 160. In an embodiment, fresh catalyst may also be introduced into the catalyst hopper 174 during operation of the hydrocarbon feed conversion system 100 such that at least a portion of the second catalyst 144 introduced into the second catalyst mixing zone 156 comprises fresh catalyst. During operation, fresh catalyst can be introduced into the catalyst hopper 174 periodically to replenish lost catalyst or compensate for catalyst that has been permanently deactivated due to heavy metal accumulation or other reasons.

[0055] The second catalyst 144 can be transferred from the second catalyst mixing zone 156 to the second reaction zone 142. The second reaction zone 142 can be a downflow reactor or a "downstream" reactor, wherein reactants flow downward from the second catalyst mixing zone 156 through the second reaction zone 142 to the second separation zone 150. The temperature of the second catalyst 144 can be equal to or greater than the second cracking average temperature T of the second reaction zone 142. 142 It can also transfer heat to the light hydrocarbon feed 108 to promote the endothermic cracking reaction.

[0056] In some embodiments, one or more supplementary feed streams (not shown) may be combined with the light hydrocarbon feed 108 before it is introduced into the second FCC reactor unit 140. In other embodiments, one or more supplementary feed streams may be added directly to the second FCC reactor unit 140. In other embodiments, no supplementary feed stream is combined with the light hydrocarbon feed 108. The supplementary feed stream may include one or more naphtha streams or other lower-boiling-point hydrocarbon streams.

[0057] It should be understood that Figure 3The second reaction zone 142 of the second FCC reactor unit 140 depicted is a simplified schematic diagram of a specific embodiment of the second reaction zone 142, and other configurations of the second reaction zone 142 may also be suitable for incorporation into the hydrocarbon feed conversion system 100. For example, in some embodiments, the second reaction zone 142 may be an upflow reaction zone. Other reaction zone configurations are also covered. The second FCC reactor unit 140 may be a hydrocarbon feed conversion unit, wherein in the second reaction zone 142, the second catalyst 144 is contacted with the light hydrocarbon feed 108 under high-severity conditions. The second cracking temperature T of the second reaction zone 142 is... 142 The temperature can be 500°C to 800°C, 500°C to 700°C, 500°C to 650°C, 500°C to 600°C, 550°C to 800°C, 550°C to 700°C, 550°C to 650°C, 550°C to 600°C, 600°C to 800°C, 600°C to 700°C, or 600°C to 650°C. In some embodiments, the second cracking temperature T of the second reaction zone 142 is... 142 The temperature can be from 500°C to 700°C. In other embodiments, the second cracking temperature T in the second reaction zone 142 is... 142 The temperature can range from 550°C to 630°C. In some embodiments, the second cracking temperature T... 142 It can be compared with the first cracking temperature T 122 Different. In some implementations, the second cracking temperature T 142 It can be at the first cracking temperature T 122 Within 50°C, for example, within 30°C, within 20°C, within 10°C, or within 5°C.

[0058] In the second reaction zone 142, the weight ratio of the second catalyst 144 to the light hydrocarbon feed 108 (the ratio of catalyst to hydrocarbon) can be 5:1 to 40:1, 5:1 to 35:1, 5:1 to 30:1, 5:1 to 25:1, 5:1 to 15:1, 5:1 to 10:1, 10:1 to 40:1, 10:1 to 35:1, 10:1 to 30:1, 10:1 to 25:1, 10:1 to 15:1, 15:1 to 40:1, 15:1 to 35:1, 15:1 to 30:1, 15:1 to 25:1, 25:1 to 40:1, 25:1 to 35:1, 25:1 to 30:1, 25:1 to 28:1, or 30:1 to 40:1. In some embodiments, the weight ratio of the second catalyst 144 to the light hydrocarbon feed 108 in the second reaction zone 142 may differ from the weight ratio of the first catalyst 124 to the heavy hydrocarbon feed 106 in the first reaction zone 122. In some embodiments, the weight ratio of the second catalyst 144 to the light hydrocarbon feed 108 in the second reaction zone 142 may be at least 1, at least 2, at least 3, 1 to 5, 1 to 4, 2 to 5, 2 to 4, or any combination of these ranges greater than the weight ratio of the first catalyst 124 to the heavy hydrocarbon feed 106 in the first reaction zone 122. In some embodiments, the weight ratio of the second catalyst 144 to the light hydrocarbon feed 108 in the second reaction zone 142 may be approximately equal to the weight ratio of the first catalyst 124 to the heavy hydrocarbon feed 106 in the first reaction zone 122. For example, the weight ratio of the second catalyst 144 to the light hydrocarbon feed 108 in the second reaction zone 142 may be within 5 of the weight ratio of the first catalyst 124 to the heavy hydrocarbon feed 106 in the first reaction zone 122, for example, within 4, within 3, within 2, or within 1. The residence time of the mixture of the second catalyst 144 and the light hydrocarbon feed 108 in the second reaction zone 142 may be 0.2 seconds to 3 seconds, 0.2 seconds to 2.5 seconds, 0.2 seconds to 2 seconds, 0.2 seconds to 1.5 seconds, 0.4 seconds to 3 seconds, 0.4 seconds to 2.5 seconds, or 0.4 seconds to 2 seconds, 0.4 seconds to 1.5 seconds, 1.5 seconds to 3 seconds, 1.5 seconds to 2.5 seconds, 1.5 seconds to 2 seconds, or 2 seconds to 3 seconds. In some embodiments, the residence time in the second reaction zone 142 may differ from the residence time in the first reaction zone 122. In some embodiments, the residence time in the second reaction zone 142 may be approximately equal to the residence time in the first reaction zone 122.

[0059] The operation of the second reaction zone 142 can convert hydrocarbons in the light hydrocarbon feed 108 into coke, which can be deposited on the second catalyst 144 to form a second spent catalyst 146. Combustion of this coke may not provide sufficient heat to regenerate the second spent catalyst 146 in the shared regenerator 160. However, a coke-deficient second spent catalyst 146 may help prevent excessive coke on the first spent catalyst 126 from overheating the shared regenerator 160. The operation of the second reaction zone 142 can convert 1% to 7% by weight of hydrocarbons in the light hydrocarbon feed 108 into coke. In an embodiment, the operation of the second reaction zone 142 can convert 1% to 2% by weight, 2% to 3% by weight, 3% to 4% by weight, 5% to 6% by weight, 6% to 7% by weight, 4% to 7% by weight, 1.5% to 4.5% by weight, or any combination of these ranges of hydrocarbons in the light hydrocarbon feed 108 into coke. In some embodiments, the operation of the first reaction zone 122 can convert more heavy hydrocarbon feed 106 into coke than the second reaction zone 142 converts light hydrocarbon feed 108. In embodiments, the operation of the first reaction zone 122 can convert at least 1 wt%, at least 2 wt%, at least 3 wt%, at least 5 wt%, 1 wt% to 2 wt%, 2 wt% to 3 wt%, 3 wt% to 4 wt%, 4 wt% to 5 wt%, 5 wt% to 6 wt%, 6 wt% to 7 wt%, 1 wt% to 3 wt%, 2 wt% to 4 wt%, 5 wt% to 7 wt%, or any combination of these ranges of heavy hydrocarbon feed 106 into coke.

[0060] Following the cracking reaction in the second reaction zone 142, the contents of the effluent from the second reaction zone 142 may include the second catalyst 144 and the second cracked effluent 148, which may be conveyed to the second separation zone 150. In the second separation zone 150, the second catalyst 144 may be separated from at least a portion of the second cracked effluent 148. In an embodiment, the second separation zone 150 may include one or more gas-solid separators, such as one or more cyclone separators. The second catalyst 144 exiting the second separation zone 150 may retain at least a portion of the residual second cracked effluent 148.

[0061] Following the second separation zone 150, the second catalyst 144 may be conveyed to the second stripping zone 152, where at least some residual portion of the second cracking effluent 148 may be stripped from the second catalyst 144 and recovered as the second stripping product stream 154. The second stripping product stream 154 may be conveyed to one or more downstream unit operations or combined with one or more other streams for further processing. Steam may be introduced into the second stripping zone 152 to facilitate the stripping of the second cracking effluent 148 from the second catalyst 144. The second stripping product stream 154 may include at least a portion of the steam introduced into the second stripping zone 152 and may exit from the second stripping zone 152. The second stripping product stream 154 may pass through a cyclone separator (not shown) and exit the stripping container (not shown). The second stripping product stream 154 may be combined with the first stripping product stream 134. Combinations with other streams are also covered. For example, the first stripping product stream 134 (which may contain a majority of steam) may be combined with steam. In another embodiment, the first stripping product stream 134 can be separated into steam and hydrocarbons, and the steam portion can be combined with the steam. The second spent catalyst 146 (i.e., the second catalyst 144 after stripping the second stripping product stream 154) can be conveyed from the second stripping zone 152 to the regeneration zone 162 of the common regenerator 160.

[0062] refer to Figure 3The same type of catalyst, such as a first catalyst 124 and a second catalyst 144, can be used throughout the hydrocarbon feed conversion system 100. The catalysts used in the hydrocarbon feed conversion system 100 (first catalyst 124 and second catalyst 144) may include one or more fluidized bed catalytic cracking catalysts suitable for the first reaction zone 122 and the second reaction zone 142. The catalyst may be a heat carrier and may transfer heat to the heavy hydrocarbon feed 106 in the first reaction zone 122 operating under high-critical conditions and the light hydrocarbon feed 108 in the second reaction zone 142 operating under high-critical conditions. The catalyst may also have multiple catalytically active sites, such as acidic sites that promote the cracking reaction. For example, in an embodiment, the catalyst may be a highly active FCC catalyst with high catalytic activity. Examples of fluidized bed catalytic cracking catalysts suitable for the hydrocarbon feed conversion system 100 may include, but are not limited to, zeolites, silica-alumina catalysts, carbon monoxide combustion promoter additives, residue cracking additives, light olefin production additives, other catalyst additives, or combinations of these components. Zeolites that can be used as at least a portion of a catalyst for cracking may include, but are not limited to, Y, REY, USY, RE-USY zeolites, or combinations of these types of zeolites. The catalyst may also include shape-selective catalyst additives, such as ZSM-5 zeolite crystals or other pentasil-type catalyst structures, which are commonly used in other FCC processes to produce light olefins and / or increase the octane number of FCC gasoline. In one or more embodiments, the catalyst may comprise a mixture of ZSM-5 zeolite crystals with a typical FCC cracking catalyst zeolite and matrix structure. In one or more embodiments, the catalyst may be a mixture of Y-type and ZSM-5 type zeolite catalysts embedded with clay, alumina, and binders.

[0063] In one or more embodiments, at least a portion of the catalyst may be modified to include one or more rare earth elements (the 15 lanthanides of the IUPAC periodic table plus scandium and yttrium), alkaline earth metals (Group 2 of the IUPAC periodic table), transition metals, phosphorus, fluorine, or any combination thereof, which may improve the olefin yield in the first reaction zone 122, the second reaction zone 142, or both. Transition metals may include “elements whose atoms have partially filled d-sublayers, or are capable of forming cations with incomplete d-sublayers” [IUPAC, Chemical Terminology Compendium, Second Edition (“Gold Book”) (1997). Online revision: (2006–) “Transition Elements”]. One or more transition metals or metal oxides may also be impregnated onto the catalyst. The metal or metal oxide may include one or more metals of Groups 6–10 of the IUPAC periodic table. In some embodiments, the metal or metal oxide may include one or more of molybdenum, rhenium, and tungsten, or any combination thereof. In one or more embodiments, a portion of the catalyst may be impregnated with tungsten oxide.

[0064] refer to Figure 3 The first FCC reactor unit 120 and the second FCC reactor unit 140 may share a common regenerator 160. The use of this common regenerator 160, combined with a customized hydrocarbon feed, allows for thermal equilibrium within the regenerator, eliminating the need for replenishment of fuel, coking agent, or catalyst cooler. A first spent catalyst 126 and a second spent catalyst 146 may be fed to the common regenerator 160, where they are mixed and regenerated together to produce a regenerated catalyst 116. The common regenerator 160 may include a regeneration zone 162, a catalyst delivery line 164, a catalyst hopper 174, and a flue gas outlet 166. The catalyst delivery line 164 may be fluidly connected to the regeneration zone 162 and the catalyst hopper 174 for conveying the regenerated catalyst 116 from the regeneration zone 162 to the catalyst hopper 174. In some embodiments, the common regenerator 160 may have more than one catalyst hopper 174, such as a first catalyst hopper (not shown) for the first FCC reactor unit 120 and a second catalyst hopper (not shown) for the second FCC reactor unit 140. In some embodiments, the flue gas outlet 166 may be located at the catalyst hopper 174.

[0065] In this implementation, less than 1% by weight of supplemental fuel may be added to the common regenerator 160 based on the total weight of the spent catalyst delivered to the common regenerator 160. Supplemental fuel is any fuel added to the common regenerator 160 to provide additional heat to regenerate the catalyst, exceeding the heat provided by the coke on the spent catalyst. Common supplemental fuels include hydrogen, methane, carbon monoxide, ethylene, and any other available hydrocarbons. Using supplemental fuel may increase the operating costs of the FCC and may increase its complexity. In this implementation, less than 0.5% by weight, less than 0.1% by weight, and less than 0.01% by weight of supplemental fuel may be added to the common regenerator 160 based on the total weight of the spent catalyst delivered to the common regenerator 160.

[0066] In operation, the first spent catalyst 126 and the second spent catalyst 146 can be transferred from the first stripping zone 132 and the second stripping zone 152 to the regeneration zone 162, respectively. Combustion gas 170 can be introduced into the regeneration zone 162. Combustion gas 170 may include one or more of combustion air, oxygen, fuel gas, fuel oil, other components, or any combination of these components. In the regeneration zone 162, coke deposited on the first spent catalyst 126 and the second spent catalyst 146 can be at least partially oxidized (combusted) in the presence of combustion gas 170 to form at least carbon dioxide and water. In some embodiments, the coke deposits on the first spent catalyst 126 and the second spent catalyst 146 can be completely oxidized in the regeneration zone 162. Other organic compounds, such as residual first or second cracking reaction products, may also be oxidized in the regeneration zone in the presence of combustion gas 170. Other gases, such as carbon monoxide, may be formed during the coke oxidation process in the regeneration zone 162. The oxidation of the coke deposits generates heat, which can be transferred and retained in the regeneration catalyst 116.

[0067] A shared regenerator 160 for regenerating the first spent catalyst 126 and the second spent catalyst 146 can improve the overall efficiency of the hydrocarbon feed conversion system 100. For example, cracking the light hydrocarbon feed 108 in the second FCC reactor unit 140 may produce less coke deposits on the second spent catalyst 146 compared to cracking the heavy hydrocarbon feed 106 in the first FCC reactor unit 120. During regeneration, the combustion of coke deposits on the second spent catalyst 146 generates heat, but the amount of coke present on the second spent catalyst 146 may not be sufficient to generate enough heat for the cracking reaction in the second reaction zone 142. Therefore, the regeneration of the second spent catalyst 146 alone may not generate enough heat to raise the temperature of the regenerated catalyst 116 to the acceptable second cracking temperature T in the second reaction zone 142. 142 In contrast, during the cracking of heavy hydrocarbon feed 106 in the first FCC reactor unit 120, the amount of coke formed and deposited on the first spent catalyst 126 may be excessive, and a catalyst cooler is required to prevent temperature T from rising. 116 This exceeds the preferred range for olefin production or prevents material failure. Typically, a catalyst cooler refers to a physical device, such as a heat exchanger, used to cool catalyst particles. Since the amount of coke deposited on the first spent catalyst 126 may significantly exceed the coke deposits produced in the second reaction zone 142, the combustion of the coke deposits on the first spent catalyst 126 during catalyst regeneration may generate sufficient heat to raise the temperature of the regenerated catalyst 116 (including the regenerated catalyst 116 produced from both the first spent catalyst 126 and the second spent catalyst 146) to high-severity conditions, such as equal to or greater than the first cracking temperature T.122 Or the second cracking temperature T 142 Regeneration catalyst temperature T 116 It can also provide the heat required for the cracking reaction to take place in both the first reaction zone 122 and the second reaction zone 142.

[0068] Flue gas 172 can be conveyed from the regeneration zone 162 to the catalyst hopper 174 via catalyst delivery line 164. The regenerated catalyst 116 can accumulate in the catalyst hopper 174 before being transferred from the catalyst hopper 174 to the first FCC reactor unit 120 and the second FCC reactor unit 140. The catalyst hopper 174 can act as a gas-solid separator to separate the flue gas 172 from the regenerated catalyst 116. In one embodiment, the flue gas 172 can be discharged from the catalyst hopper 174 through a flue gas outlet 166 located within the catalyst hopper 174.

[0069] The catalyst can be recycled through the first FCC reactor unit 120, the second FCC reactor unit 140, the shared regenerator 160, and the catalyst hopper 174. For example, the first catalyst 124 can be introduced into the first FCC reactor unit 120 to catalytically crack the heavy hydrocarbon feed 106 in the first FCC reactor unit 120. During cracking, coke deposits may form on the first catalyst 124, resulting in a first spent catalyst 126 discharged from the first stripping zone 132. The catalytic activity of the first spent catalyst 126 may be lower than that of the regenerated catalyst 116, meaning that the first spent catalyst 126 may be less effective in promoting the cracking reaction compared to the regenerated catalyst 116. The first spent catalyst 126 can be separated from the first cracking effluent 128 in the first separation zone 130 and the first stripping zone 132. The second catalyst 144 can be introduced into the second FCC reactor unit 140 to catalytically crack the light hydrocarbon feed 108 in the second FCC reactor unit 140. During cracking, coke deposits may form on the second catalyst 144, resulting in a second spent catalyst 146 discharged from the second stripping zone 152. The catalytic activity of the second spent catalyst 146 may also be lower than that of the regenerated catalyst 116, meaning that the second spent catalyst 146 may be less effective in promoting the cracking reaction compared to the regenerated catalyst 116. The second spent catalyst 146 can be separated from the second cracking effluent 148 in the second separation zone 150 and the second stripping zone 152. Then, the first spent catalyst 126 and the second spent catalyst 146 can be combined and regenerated in the regeneration zone 162 to produce the regenerated catalyst 116. The regenerated catalyst 116 can be conveyed to the catalyst hopper 174.

[0070] The regenerated catalyst 116 discharged from regeneration zone 162 may have less than 1% coke deposit based on the total weight of the regenerated catalyst 116. In some embodiments, the regenerated catalyst 116 discharged from regeneration zone 162 may have less than 0.5% by weight, less than 0.1% by weight, or less than 0.05% by weight of coke deposit. In some embodiments, the regenerated catalyst 116 discharged from regeneration zone 162 to catalyst hopper 174 may have 0.001 wt% to 1 wt%, 0.001 wt% to 0.5 wt%, 0.001 wt% to 0.1 wt%, 0.001 wt% to 0.05 wt%, 0.005 wt% to 1 wt%, 0.005 wt% to 0.5 wt%, 0.005 wt% to 0.1 wt%, 0.005 wt% to 0.05 wt%, 0.01 wt% to 1 wt%, 0.01 wt% to 0.5 wt%, 0.01 wt% to 0.1 wt%, and 0.01 wt% to 0.05 wt% of coke deposits, based on the total weight of the regenerated catalyst 116. In one or more embodiments, the regenerated catalyst 116 discharged from regeneration zone 162 may be substantially free of coke deposits. As used in this disclosure, the term "substantially free" means that the content of that component in a specific portion of the catalyst, stream, or reaction zone is less than 1% by weight. For example, a regenerated catalyst 116 substantially free of coke deposits may have less than 1% by weight of coke deposits. Removing coke deposits from the regenerated catalyst 116 in the regeneration zone 162 can be achieved by removing the coke deposits from catalytically active sites (e.g., acidic sites) on the catalyst that promote the cracking reaction. Removing coke deposits from catalytically active sites on the catalyst can improve the catalytic activity of the regenerated catalyst 116 compared to the first and second regenerated catalysts 126 and 146. Therefore, the catalytic activity of the regenerated catalyst 116 can be greater than that of the first and second regenerated catalysts 126 and 146.

[0071] The regenerated catalyst 116 absorbs at least a portion of the heat generated by the combustion of coke deposits. This heat raises the temperature of the regenerated catalyst 116 above the temperatures of the first spent catalyst 126 and the second spent catalyst 146. The regenerated catalyst 116 accumulates in the catalyst hopper 174 until it is returned to the first FCC reactor unit 120 as at least a portion of the first catalyst 124 and to the second FCC reactor unit 140 as at least a portion of the second catalyst 144. The temperature of the regenerated catalyst 116 in the catalyst hopper 174 is equal to or greater than the first cracking temperature T in the first reaction zone 122 of the first FCC reactor unit 120. 122 The second cracking temperature T in the second reaction zone 142 of the second FCC reactor unit 140 142Or both. The higher temperature of the regenerated catalyst 116 can provide heat for the endothermic cracking reaction in the first reaction zone 122, the second reaction zone 142, or both.

[0072] As previously mentioned, heavy hydrocarbon feed 106 and light hydrocarbon feed 108, such as crude oil or total condensate, can have a wide range of compositions and boiling points. Due to these compositional differences, both heavy hydrocarbon feed 106 and light hydrocarbon feed 108 may benefit from different operating temperatures and catalyst activities to achieve desired yields of one or more petrochemical products or to improve the selectivity of the reaction for certain products. For example, heavy hydrocarbon feed 106 may be more reactive, and therefore may require only a lower cracking activity compared to light hydrocarbon feed 108 to achieve sufficient yields or selectivity for a particular petrochemical product. However, the coke produced by heavy hydrocarbon feed 106 may be insufficient to operate the regenerator. A lower cracking activity suitable for heavy hydrocarbon feed 106 can be achieved by reducing the catalytic activity of the first catalyst 124 in the first reaction zone 122 and reducing the first cracking temperature T in the first reaction zone 122. 122 Or a combination of both. In contrast, the light hydrocarbon feed 108 may be less reactive, and therefore, compared to the heavy hydrocarbon feed 106, higher catalytic activity may be required to obtain sufficient yield or selectivity of specific petrochemical products, such as increasing the catalytic activity of the second catalyst 144 in the second reaction zone 142 or increasing the second cracking temperature T in the second reaction zone 142. 142 Above the first cracking temperature T 122 Alternatively, both methods can be used simultaneously. However, cracking light hydrocarbon feedstock 108 alone may produce excessive coke, which would necessitate a catalyst cooler.

[0073] As described above in this disclosure, the hydrocarbon feed conversion system 100 may include a common regenerator 160 to regenerate the first spent catalyst 126 and the second spent catalyst 146, thereby producing a regenerated catalyst 116. Therefore, the regenerated catalyst 116 fed to the first FCC reactor unit 120 is the same as the regenerated catalyst 116 fed to the second FCC reactor unit 140, and has the same catalytic efficiency and temperature. However, as previously stated, the reaction conditions that produce sufficient yields or selectivity of a particular petrochemical product in the first FCC reactor unit 120 or the second FCC reactor unit 140 may differ from the reaction conditions provided by feeding the regenerated catalyst 116 to the first FCC reactor unit 120 or the second FCC reactor unit 140.

[0074] Example Various embodiments of the methods and systems for converting feedstocks into fuels will be further illustrated by the following examples. These examples are illustrative and should not be construed as limiting the subject matter of this disclosure.

[0075] In both Examples A and B below, a catalyst mixture was used. This catalyst mixture was prepared by physical mixing and contained 75 wt% HS-FCC / 5a (purchased from JGC Catalysts and Chemicals LTD) and 25 wt% Olefins Ultra® (purchased from WR Grace and Co.). Prior to the experiments, the catalyst was vapor-deactivated at 810°C for 6 hours to simulate the equilibrium catalyst in commercial processes.

[0076] The properties of the feedstock used are shown in Table 2, where KGC refers to Khuff condensate, AXL refers to Arab ultralight crude oil, and AH refers to Arab heavy crude oil.

[0077] Table 2

[0078] The operation of each reaction zone was simulated using a micro downcomer unit (MDU) (manufactured by Amtech, shown in the figure below). To prepare for the experiment, the catalyst was loaded into the hopper and a trap was set. The feed was loaded into the syringe and the pump assembly was prepared. Then, N2 and air were supplied. Next, the heating systems for the catalyst hopper, reactor, and stripper were started. The temperature and pressure were equilibrated to their set points. The liquid products were collected in the trap, and the gaseous products were sent to a gas chromatograph (GC) for analysis. The liquid products were then sent for simulated distillation (SimDist) analysis to determine the composition of gasoline, light cycle oil (LCO), and heavy cycle oil (HCO). The coke content was measured by measuring the CO2 released during catalyst combustion. The results are shown in Table 3.

[0079] Table 3

[0080] In Examples A and B, the required coke and catalyst to hydrocarbon ratios were determined by simulation while keeping the feed rate (60 KBPD per reactor, 120 KBPD for both reactors), feed temperature (300°C), steam inlet rate (14% by weight of fresh feed), downpipe inlet temperature (DIT) (695°C), and downpipe outlet temperature (640°C) constant.

[0081] In Example A, KGC was used as the light hydrocarbon feed and AH was used as the heavy hydrocarbon feed. The results of Example A are shown in Table 4.

[0082] Table 4: Example A

[0083] In Example B, AXL was used as the light hydrocarbon feed and AH was used as the heavy hydrocarbon feed. The results of Example B are shown in Table 5.

[0084] Table 5

[0085] As shown in Table 5, the combination of AXL and AH requires approximately 13% by weight of coke production. As shown in Table 3, the combination of AXL and AH produces approximately 13% by weight of coke production. Therefore, the coke demand is balanced, and the regenerator can operate without a catalyst cooler or supplemental fuel.

[0086] This disclosure includes many aspects.

[0087] Aspect 1 discloses a method for operating a fluidized catalytic cracking unit, the method comprising: feeding a heavy hydrocarbon feedstock and a first catalyst into a first reaction zone to produce a first cracking effluent and a first spent catalyst deposited thereon; feeding a light hydrocarbon feedstock and a second catalyst into a second reaction zone to produce a second cracking effluent and a second spent catalyst deposited thereon; feeding the first spent catalyst and the second spent catalyst into a shared regenerator; and in the shared regenerator, regenerating the catalyst by burning the coke deposited on the first spent catalyst and the second spent catalyst. The first and second spent catalysts are described to form a fresh catalyst, which is then fed back to the first reaction zone as the first catalyst and to the second reaction zone as the second catalyst, wherein: the light hydrocarbon feed has an API density of 38° to 55°; the heavy hydrocarbon feed includes crude oil with an API density of 20° to 35°; both the first and second reaction zones are fluidized catalytic cracking zones operating under high-critical conditions; and the shared regenerator operates without supplemental fuel or a catalyst cooler.

[0088] Aspect 2, including aspect 1, discloses that the light hydrocarbon feedstock includes all crude oil or all condensate.

[0089] Aspect 3 may include Aspect 1 and / or Aspect 2, disclosing that the light hydrocarbon feed and the heavy hydrocarbon feed are not separated by boiling point.

[0090] Aspect 4 may include any one of aspects 1 to 3, disclosing that the API specific gravity of the light hydrocarbon feed is at least 25° higher than that of the heavy hydrocarbon feed.

[0091] Aspect 5 may include any one of aspects 1 to 4, disclosing the light hydrocarbon feed, the heavy hydrocarbon feed, or both of which are hydrogenated feed streams.

[0092] Aspect 6 may include any one of aspects 1 to 5, disclosing that the light hydrocarbon feedstock includes Arabian ultralight crude oil or Khuff condensate.

[0093] Aspect 7 may include any one of aspects 1 to 6, disclosing that the heavy hydrocarbon feedstock is Arab heavy crude oil.

[0094] Aspect 8 may include any one of aspects 1 to 7, disclosing that the first reaction zone operates at a first cracking temperature; the second reaction zone operates at a second cracking temperature; and the first cracking temperature is within 10°C of the second cracking temperature.

[0095] Aspect 9 may include any one of aspects 1 to 8, disclosing that the API specific gravity of the heavy hydrocarbon feed is 24° to 30°; the API specific gravity of the light hydrocarbon feed is 50° to 55°; the first reaction zone is operated at a catalyst-to-hydrocarbon ratio of 15:1 to 40:1; the second reaction zone is operated at a catalyst-to-hydrocarbon ratio of 15:1 to 40:1; and the catalyst-to-hydrocarbon ratio of the second reaction zone minus the catalyst-to-hydrocarbon ratio of the first reaction zone is at least 1.

[0096] Aspect 10 may include any one of aspects 1 to 9, disclosing that the first reaction zone converts 8% to 11% by weight of the heavy hydrocarbon feed into coke; and the second reaction zone converts 1.5% to 4.5% by weight of the light hydrocarbon feed into coke.

[0097] Aspect 11 may include any one of aspects 1 to 10, disclosing that the API specific gravity of the heavy hydrocarbon feed is 24° to 30°; and the ratio of catalyst to hydrocarbon in the second reaction zone minus the ratio of catalyst to hydrocarbon in the first reaction zone is less than 1.

[0098] Aspect 12 may include any one of aspects 1 to 11, disclosing that the first reaction zone converts 6% to 10% by weight of the heavy hydrocarbon feed into coke; the second reaction zone converts 4% to 7% by weight of the light hydrocarbon feed into coke; and the proportion of the heavy hydrocarbon feed converted into coke in the first reaction zone is at least 2 percentage points higher than the proportion of the light hydrocarbon feed converted into coke in the second reaction zone.

[0099] Aspect 13 may include any one of aspects 1 to 12, disclosing that no coke precursor is introduced into the heavy hydrocarbon feed or the light hydrocarbon feed.

[0100] Aspect 14 may include any one of aspects 1 to 13, disclosing that the first reaction zone and the second reaction zone are each operated independently at a temperature greater than or equal to 580°C, a catalyst to hydrocarbon feed weight ratio of 15:1 to 40:1, and a residence time of 0.1 seconds to 60 seconds.

[0101] Aspect 15 may include any one of aspects 1 to 14, disclosing that the first reaction zone and the second reaction zone each operate in a downflow configuration.

[0102] For the purposes of describing and defining this disclosure, it should be noted that the terms “about” or “approximately” as used herein indicate the degree of uncertainty inherent in any quantitative comparison, numerical value, measurement, or other representation. The terms “about” and / or “approximately” are also used in this disclosure to indicate the extent to which a quantitative representation may deviate from the stated reference value without causing a change in the essential function of the subject matter.

[0103] It should be noted that one or more of the following claims use the term "wherein" as a transitional phrase. For the purposes of defining this technology, it should be noted that this term is introduced in the claims as an open transitional phrase to introduce a description of a series of structural features, and should be interpreted in a manner similar to the more commonly used open preamble term "comprising".

[0104] Any quantitative value expressed in this application may be considered to include open-ended implementations consistent with the transitional phrases “comprising” or “including”, as well as closed or partially closed implementations consistent with the transitional phrases “consisting of” and “substantially consisting of”.

[0105] It should also be noted that the description of “at least one” component, element, etc. in this document should not be used to infer that the alternative use of “a” or “an” should be limited to a single component, element, etc.

Claims

1. A method for operating a fluidized catalytic cracking unit, the method comprising: Heavy hydrocarbon feed and first catalyst are conveyed to first reaction zone to produce first cracking effluent and first unprocessed catalyst deposited thereon with coke. The light hydrocarbon feed and the second catalyst are conveyed to the second reaction zone to produce the second cracking effluent and the second unprocessed catalyst deposited thereon with coke. The first and second spent catalysts are transferred to a common regenerator; In the shared regenerator, the first and second spent catalysts are regenerated by burning coke deposited on them, thereby forming fresh catalyst. This fresh catalyst is then returned to the first reaction zone as the first catalyst and to the second reaction zone as the second catalyst, wherein: The API specific gravity of the light hydrocarbon feed is 38° to 55°. The heavy hydrocarbon feed includes crude oil with an API density of 20° to 35°. Both the first and second reaction zones are fluidized catalytic cracking zones operating under high-critical conditions; and The shared regenerator operates without supplemental fuel or a catalyst cooler.

2. The method according to claim 1, wherein the light hydrocarbon feed comprises all crude oil or all condensate.

3. The method according to claim 1 or 2, wherein the light hydrocarbon feed and the heavy hydrocarbon feed are not separated by boiling point.

4. The method according to any one of claims 1 to 3, wherein the API specific gravity of the light hydrocarbon feed is at least 25° higher than that of the heavy hydrocarbon feed.

5. The method according to any one of claims 1 to 4, wherein the light hydrocarbon feed, the heavy hydrocarbon feed, or both are hydrogenated feed streams.

6. The method according to any one of claims 1 to 5, wherein the light hydrocarbon feed comprises Arabian ultralight crude oil or Khuff condensate.

7. The method according to any one of claims 1 to 6, wherein the heavy hydrocarbon feedstock is Arab heavy crude oil.

8. The method according to any one of claims 1 to 7, wherein: The first reaction zone operates at the first cracking temperature; The second reaction zone operates at the second cracking temperature; and The first cracking temperature is within 10°C of the second cracking temperature.

9. The method according to any one of claims 1 to 8, wherein: The API specific gravity of the heavy hydrocarbon feed is 24° to 30°; The API specific gravity of the light hydrocarbon feed is 50° to 55°; The first reaction zone is operated under conditions where the ratio of catalyst to hydrocarbon is 15:1 to 40:1; The second reaction zone operates under a catalyst-to-hydrocarbon ratio of 15:1 to 40:1; and The ratio of catalyst to hydrocarbon in the second reaction zone minus the ratio of catalyst to hydrocarbon in the first reaction zone is at least 1.

10. The method according to any one of claims 1 to 9, wherein: The first reaction zone converts 8% to 11% by weight of the heavy hydrocarbon feed into coke; and The second reaction zone converts 1.5% to 4.5% by weight of the light hydrocarbon feed into coke.

11. The method according to any one of claims 1 to 10, wherein: The API specific gravity of the heavy hydrocarbon feed is 24° to 30°; and The ratio of catalyst to hydrocarbon in the second reaction zone minus the ratio of catalyst to hydrocarbon in the first reaction zone is less than 1.

12. The method according to any one of claims 1 to 11, wherein: The first reaction zone converts 6% to 10% by weight of the heavy hydrocarbon feed into coke; The second reaction zone converts 4% to 7% by weight of the light hydrocarbon feed into coke; and The proportion of heavy hydrocarbon feed converted into coke in the first reaction zone is at least 2 percentage points higher than the proportion of light hydrocarbon feed converted into coke in the second reaction zone.

13. The method according to any one of claims 1 to 12, wherein no coke precursor is introduced into the heavy hydrocarbon feed or the light hydrocarbon feed.

14. The method according to any one of claims 1 to 13, wherein the first reaction zone and the second reaction zone are each operated independently at a temperature greater than or equal to 580°C, a catalyst to hydrocarbon feed weight ratio of 15:1 to 40:1, and a residence time of 0.1 seconds to 60 seconds.

15. The method according to any one of claims 1 to 14, wherein the first reaction zone and the second reaction zone are each operated in a downflow configuration.

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