KR20230127988A - Process for the production of olefins and aromatics through hydrogen pyrolysis and coke management - Google Patents

Abstract

Systems and processes for the production of olefins and aromatics. The process comprises contacting a first hydrocarbon feed with a catalyst and a source of hydrogen under conditions sufficient to produce a spent catalyst and an intermediate stream containing olefins and aromatics, and contacting the spent catalyst with the intermediate stream and coke precursor feed. to produce a product stream comprising spent coking catalyst and additional olefins and aromatics.

Description

Process for the production of olefins and aromatics through hydrogen pyrolysis and coke management

CROSS REFERENCES TO RELATED APPLICATIONS

This application claims priority to US Provisional Application No. 63/109,507, filed on November 4, 2020, the entire contents of which are incorporated herein by reference.

The present invention relates generally to a hydropyrolysis process for producing olefins and aromatics. The process comprises (a) contacting a first hydrocarbon feed stream with a catalyst and a source of hydrogen under conditions sufficient to produce a used catalyst and an intermediate stream comprising olefins and aromatics; and ( b) contacting the spent catalyst with the intermediate stream and coke precursor feed to produce a product stream comprising spent cocked catalyst and additional olefins and aromatics. The spent coking catalyst may be used in step (a) to help with heat management of the reaction.

Light olefins such as ethylene, propylene and butylene are important raw materials for multiple end products such as polymers, rubbers, plastics, and octane booster compounds. Demand for light olefins is expected to continue to increase. Aromatic hydrocarbons such as benzene, toluene, and xylene are important commodity chemicals whose demand continues to increase. High value chemicals such as light olefins and aromatics can be produced by fluidized catalytic cracking (FCC) of petroleum feedstocks.

Examples of fluid catalytic cracking processes are disclosed in US 7,491,315 using a dual riser reactor configuration and US 9,550,708 using a single riser reactor system. One of the problems currently facing FCC processes is that the catalysts used in these processes are prone to catalyst deactivation due to the relatively rapid accumulation of carbonaceous deposits on the catalyst. In particular, carbonaceous deposits, ie coke formation, can reduce catalyst efficiency and adversely affect light olefin and aromatics yields.

Discoveries have been made that provide solutions to at least some of the problems associated with fluid catalytic cracking (FCC) processes used to produce high value chemicals such as olefins and/or aromatics. This solution involves catalytic cracking of hydrocarbons with a fluidized catalyst in the presence of a hydrogen source (eg, hydrogen (H ₂ ) gas) to reduce coke formation on the catalyst and then contacting the catalyst with a coke precursor to precipitate the coke. make a premise The use of hydrogen to reduce coke formation on the catalyst in the first reaction zone of a reactor (e.g. riser reactor or lower reactor) reduces the reactor The catalyst/feed (C/F) ratio may be higher to supply the endothermic heat of the reaction. The use of a hydrogen source maintains catalytic activity in the first reaction zone when coke precursor feed is added to the reactor at a downstream location to obtain coke burned in the catalyst regenerator. This can be advantageous in that higher C/F ratios and/or catalysts that are more active in the first reaction zone can result in higher yields of high value chemicals such as olefins and/or aromatics. The use of coke precursors in the second reaction zone allows (1) cracking of the coke precursors to produce additional high value chemicals (e.g., olefins and/or aromatics) and/or (2) exiting the reactor for coke combustion. This can result in increased coke content on the catalyst going to the regenerator. Regeneration of coked catalyst can generate heat. The heat generated in (2) may be supplied to the first reaction zone as needed. The amount of coke precursor used in the second reaction zone can be varied as desired and can be based on the thermal energy requirements of the first reaction zone. In other words, a more active catalyst in the first reaction zone with a higher C/F ratio at a lower coke precursor feed injection or maintaining the same C/F ratio but with the coke on the catalyst exiting the reactor held constant. There is a range available. Thus, advantages of the present invention may include increased production of olefins and/or aromatics by managing catalytic activity and/or an efficient thermal management process during the FCC reaction.

One aspect of the present invention relates to processes for the production of olefins and aromatics. This process may include steps (a) and/or (b). In step (a), a first hydrocarbon feed stream containing a first hydrocarbon is a cracking catalyst and a source of hydrogen under conditions sufficient to produce an intermediate stream containing spent catalyst and olefins and aromatics. can come into contact with In step (b) the spent catalyst and the intermediate stream may be contacted with a coke precursor stream to form a products stream containing spent coking catalyst and additional olefins and aromatics. The coke precursor may contact the spent catalyst and form a carbonaceous deposit on the surface of the spent catalyst to form the spent coking catalyst. At least a portion of the olefins and aromatics from the intermediate stream may be passed to the product stream. In some aspects, the contacting conditions in step (a) may include a temperature of 500°C to 750°C, or 600°C to 750°C. In some aspects, the contacting conditions in step (a) may include a temperature between 700°C and 850°C. In some aspects, the contacting conditions in step (a) may further comprise a pressure of about 0.5 bara to about 5 bara and/or a contact time in the reactor of 0.1 sec to 5 sec. In some aspects, the catalyst to feed (C/F) ratio (w/w) in step (a) may be greater than the C/F ratio in step (b). In some aspects, the C/F ratio of step (a) may be between 4 and 40. In some aspects, the C/F ratio of step (b) may be between 4 and 40. In some aspects, the cracking catalyst can include a zeolite catalyst, a fluid catalytic cracking (FCC) catalyst, a hydrocracking catalyst, or an aluminosilicate or any combination thereof. Non-limiting examples of zeolite catalysts include ZSM-5, ZSM-11, ferrierite, heulandite, zeolite A, erionite, and chabazite. , or any combination thereof. In some aspects, the zeolite catalyst may be present in an active or inert matrix. Non-limiting examples of FCC catalysts include X-type zeolite, Y-type and/or USY-type zeolite, mordenite, poe Faujasite, nano-crystalline zeolites, MCM mesoporous materials, SBA-15, silica-alumino phosphate, gallophosphate, titano titanophosphate, a catalyst that has been consumed or equilibrated from FCC units, or any combination thereof. The FCC catalyst may be present in an active or inactive matrix with or without a metal support. A non-limiting example of a hydrocracking catalyst includes a metal oxide with a metal sulfide in the form of an active catalyst on a support. In some aspects, the support can be silica, aluminum carbon, titania, zirconia or aluminosilicate or any combination thereof. In some aspects, the cracking catalyst can be a zeolite and/or a metal supported zeolite, for example a zeolite intercalated in a matrix and/or a metal supported zeolite. In some aspects, the cracking catalyst can be ZSM-5 and/or metal supported ZSM-5. In some aspects, olefins and aromatics, such as light olefins, may have a yield of 4 to 20 per unit of coke formed in step (a). The weight percent (wt.%) of coke in the spent catalyst may be lower than the weight percent of coke in the spent coking catalyst. The spent coking catalyst can be regenerated and the regenerated catalyst can be recycled to step (a). The hydrogen source may be hydrogen (H ₂ ) gas, methane, ethane, ethylene, propane, propylene, butane, butene, or any combination thereof, preferably H ₂ gas. The first hydrocarbon feed stream is a recycled crackable hydrocarbon stream containing naphtha, condensates, eg petroleum condensates, gas oil, C ₃ and C ₄ saturated gases, cracked naphtha stream, C ₃ and C ₄ saturated gases. or any combination thereof, wherein the first hydrocarbon is naphtha, condensate, such as petroleum condensate, gas oil, C ₃ and C ₄ saturated gas, cracked naphtha stream, C ₃ and C ₄ It may be one or more hydrocarbons included in a recycled crackable hydrocarbon stream containing saturated gas or a combination thereof. The coke precursor stream is a fluid catalytic cracking cycle oil and slurry oil, coker stream, slurry oil, crude oil, carbon black oil, cracked distillate, vacuum residue or cracked oil, for example cracked oil from a source such as bio-oil or fuel oil, or any combination thereof. In some aspects, a second hydrocarbon feed stream containing a second hydrocarbon may be provided in step (a), wherein the cracking catalyst is contacted with the first hydrocarbon feed stream and the second hydrocarbon feed stream to obtain the intermediate stream and the spent catalyst can be produced. In some aspects, the cracking catalyst can contact the first hydrocarbon feed stream and the second hydrocarbon feed stream in the presence of a hydrogen source to produce the intermediate stream. In some aspects, the cracking catalyst can contact a second hydrocarbon feed stream downstream to contact the crack catalyst with the first hydrocarbon feed stream. The second hydrocarbon feed stream is crude oil; atmospheric residue; vacuum gas oil; unconverted oil in a hydrocracker, for example at the bottom of a hydrocracker; hydrowax; plastics or polymers dissolved or slurried in a solvent; polyolefin oligomers; plastic; partially depolymerized plastics; plastic pyrolysis oil; hydrogenated plastic pyrolysis oil; recycled naphtha and gas oil streams; naphtha; gas oil; vacuum gas oil and/or unconverted oil products from hydrocracking of plastics; or any combination thereof, wherein the second hydrocarbon is crude oil; atmospheric residue; vacuum gas oil; unconverted oil in the hydrocracker, for example at the bottom of the hydrocracker; hydrowax; plastics or polymers dissolved or slurried in a solvent; polyolefin oligomers; plastic; partially depolymerized plastics; plastic pyrolysis oil; hydrogenated plastic pyrolysis oil; recycled naphtha and gas oil streams; naphtha; gas oil; unconverted vacuum gas oil and/or oil products from hydrocracking of plastics; or one or more hydrocarbons included in any combination thereof. Plastics may include, but are not limited to, polyolefins (HDPE, LDPE, LLDPE, PP), PS, PVC, PVDC, PET, or combinations thereof. The plastic may be pure, post-consumer recycled or post-industrial recycled plastic. In some aspects, the average molecular weight of the one or more second hydrocarbons, eg, the hydrocarbons in the second hydrocarbon feedstream, may be higher than the average molecular weight of the one or more first hydrocarbons, eg, the hydrocarbons in the first hydrocarbon feedstream.

In some aspects, a third hydrocarbon feedstream containing a third hydrocarbon may be provided in step (a), wherein the cracking catalyst comprises the first hydrocarbon feedstream, the second hydrocarbon feedstream, and the third hydrocarbon feedstream. can be contacted with to produce the intermediate stream and the spent catalyst. In some aspects, the cracking catalyst can contact the first hydrocarbon feedstream, the second hydrocarbon feedstream, and the third hydrocarbon feedstream in the presence of a hydrogen source to produce the intermediate stream. In some aspects, the cracking catalyst can contact the third hydrocarbon feed stream downstream to be contacted with the second hydrocarbon feed stream and the first hydrocarbon feed stream. The third hydrocarbon feed stream is crude oil, atmospheric residue, vacuum gas oil, unconverted oil in a hydrocracker, for example at the bottom of a hydrocracker, hydrowax, polyolefin oligomers, plastics, partially depolymerized plastics, dissolved in a solvent or slurried plastics or polymers, plastic pyrolysis oils, hydrogenated plastics pyrolysis oils, heavy recycled crackable hydrocarbon streams, gas oils, vacuum gas oils and unconverted oil products from the hydrocracking of plastics, or these wherein the third hydrocarbon is crude oil, atmospheric residue, vacuum gas oil, hydrocracker, e.g. unconverted oil at the bottom of a hydrocracker, hydrowax, polyolefin oligomers, plastics, partially Depolymerized plastics, solvent-dissolved or slurried plastics or polymers, plastic pyrolysis oils, hydrogenated plastic pyrolysis oils, heavy recycled crackable hydrocarbon streams, gas oils, vacuum gas oils from hydrocracking of plastics and unconverted oil product, or one or more hydrocarbons included in any combination thereof. In some aspects, the average molecular weight of the one or more third hydrocarbons, eg, the hydrocarbons of the third hydrocarbon feedstream, may be higher than the average molecular weight of the one or more second hydrocarbons, eg, the hydrocarbons of the second hydrocarbon feedstream. The first, second and/or third hydrocarbon stream optionally contains a catalyst suspended, dispersed and/or dissolved in the respective stream.

In some aspects, the spent coking catalyst may be included in the product stream, and the process may include separating the spent coking catalyst from the product stream. In some aspects, the spent coking catalyst may be separated from the product stream with a cyclone separator. In some aspects, the product stream after separation from the spent coking catalyst may be sent to a fractionator/separation train known in the art to obtain refined gaseous olefins and/or aromatics. The gaseous olefin may be ethylene, propylene and/or butylene. The aromatic may be benzene, toluene, ethylbenzene and/or xylene. In some aspects, the separated spent coking catalyst may be regenerated. In some aspects, the regeneration process may include contacting the separated spent coking catalyst with a regeneration stream. In some aspects, the regeneration stream may contain oxygen (O ₂ ). In some aspects, the recycle stream may contain 18 vol % to 30 vol % or 20 vol % to 25 vol % oxygen (O ₂ ). In some aspects, the regeneration stream may contain air, diluted air, oxygen enriched air, or any combination thereof. In some aspects, the regeneration stream may be contacted with the spent coking catalyst at a temperature of 500° C. to 800° C., a pressure of 0.5 bara to 5 bara, and/or a contact time of 5 minutes to 30 minutes. In some aspects, the regeneration of catalyst from the spent coking catalyst may generate heat and at least some of the heat may be provided to step (a). In some aspects, the regenerated catalyst can be recycled to step (a).

In some aspects, steps (a) and (b) of the hydrogen pyrolysis process may be performed in a reactor comprising a first reaction zone and a second reaction zone, wherein step (a) is performed in a first reaction zone and (b) is carried out in a second reaction zone. The reaction zones may be in fluid communication with one another. In some aspects, the reactor can be a riser unit or a lower unit of a fluid catalytic cracking unit. In one aspect, the first and second reaction zones are included in a riser unit of a fluid catalytic cracking unit, wherein the first reaction zone is upstream of the second reaction zone, and the first and second reaction zones are It is in fluid communication with another reaction zone. In another aspect, the first and second reaction zones are included in a downer unit of a fluid catalytic cracking unit, wherein the first reaction zone is upstream of the second reaction zone, and wherein the first and second reaction zones are included. A zone is in fluid communication with another reaction zone. The average hydrocarbon residence time in the reactor may be 100 ms to 2 seconds, preferably 100 ms to 1 second. The source of hydrogen may be provided in step (a) comprised in a lift stream and the lift stream may further comprise steam. In some aspects, the lift stream may comprise from 0.1% to 99.9% by weight of a hydrogen source, such as H ₂ , and from 0.1% to 99.9% by weight of steam. In some aspects the lift stream may include a hydrocarbon gas. In some specific aspects, the lift stream may contain 1% by weight hydrogen and optionally the balance steam and hydrocarbon gases. The lift stream is formed in the reactor to crack catalysts such as cracking catalysts, spent catalysts, spent coking catalysts, and/or hydrocarbons such as first, second and/or tertiary hydrocarbons, olefins and/or aromatics. It can be used to assist in the flow of materials such as refined products, and to control the average hydrocarbon residence time in the reactor, as well as for improved contact and mixing of the hydrocarbon stream with the catalyst. In some aspects, the average hydrocarbon residence time in the reactor can be reduced by increasing the flow rate of the lift stream.

In certain aspects, oxygenate may be supplied to the reactor at one or more locations. The oxygenate may be provided in step (a) and/or step (b). In some aspects, one or more oxygenate streams comprising oxygenates may be fed to the reactor. The one or more oxygenate streams may be fed to the reactor at one or more locations. In some aspects, multiple oxygenate streams, such as 2 to 15 or 2 to 10 oxygenate streams, may be provided at multiple locations in the reactor. One or more oxygenate streams may be provided in step (a) and/or step (b). In certain aspects, an oxygenate may be fed to a reactor comprising a first hydrocarbon feed stream, a second hydrocarbon feed stream, a third hydrocarbon feed stream, and/or a coke precursor stream. In some aspects, an oxygenate stream may be supplied to the reactor through a nozzle. In some aspects, the amount of oxygenate provided to the first reaction zone (eg, high conversion zone) is greater than that provided to the second reaction zone (eg, low conversion zone). can be high In some aspects, the number of oxygenate streams provided to the first reaction zone may be greater than the number of oxygenate streams provided to the second reaction zone. For example, the number of oxygenate stream nozzles may be greater in the first reaction zone than the number of oxygenate stream nozzles in the second reaction zone. Introducing higher amounts of oxygenate to the high conversion zone can help maintain high temperature severity in the high conversion zone, resulting in increased formation of light gas olefins. In the reactor, the oxygenates can decompose to generate heat, increase the reactor temperature, and/or reduce the cracking catalyst and/or weight percent coke relative to the catalyst used. The oxygenate may be used to control the temperature, eg the local temperature of the reactor at one or more locations along the length of the reactor. In certain aspects, the process measures a local temperature at one or more locations where oxygenate is supplied, and if the local temperature at the one or more locations is lower than a desired temperature at the one or more locations, the above-mentioned reaction to the reactor is performed. At least one oxygenate is supplied by increasing the oxygenate flow rate or, if the local temperature at the one or more locations is higher than the desired temperature at the one or more locations, reducing the oxygenate flow rate to the reactor. It may include controlling the local temperature of the reactor on location. In some aspects, the local temperature at one or more locations can be measured by one or more temperature sensors located on and/or near a wall of the reactor and/or located at one or more locations. The thermal profile of the reactor may be established by controlling the local temperature of the reactor at the one or more locations. In some aspects, the reactor may include one or more corresponding first heaters located on the outer surface of the reactor wall layer along with one or more temperature sensors located on the inner surface of the reactor wall along the length of the reactor. During the hydrogen pyrolysis process, the reactor local temperature may be controlled by supplying an oxygenate to the one or more thermal sensors, one or more heaters, and/or one or more locations of the reactor, at the inlet to the cracking catalyst to the reactor. The difference between the temperature and the temperature at the outlet for the spent coking catalyst from the reactor may be less than 200°C, preferably less than 150°C, more preferably less than 100°C. This allows the reactor to be operated at a desired higher temperature severity level and also to apply a temperature profile along the length of the reactor for a desired product yield. It also helps to partially isolate the reactor from the regenerator from a heat balance point of view and can operate at higher catalyst flow rates if desired. In some aspects, one or more first heaters may form a first heater layer of a reactor, wherein the reactor is positioned on an outer surface of the first heater layer to insulate the first heater layer from the outside. Additional layers may be included. The reactor may further include one or more second heaters positioned on an outer surface of the first insulating layer. The first insulating layer and the one or more second heaters help minimize heat loss from the reactor. In some aspects, the average internal diameter of the reactors in the first reaction zone is greater than the average internal diameter of the reactors in the second reaction zone. In some other aspects, the average internal diameter of the reactors in the first reaction zone is less than the average internal diameter of the reactors in the second reaction zone. In some aspects, the residence time in the reactor may be 0.1 to 1 second to have high light gas olefin selectivity and reduce secondary cracking to aromatics. In some aspects the residence time in the reactor can be controlled from 0.1 to 1 second by reducing the length of the reactor. In some aspects, high value chemicals (e.g., gaseous olefins, benzene, toluene, xylenes and/or ethyl benzene) or at least a portion of the high value chemicals can be separated from the product stream and the residual stream returned to the bottom of the reactor. can be supplied. In some aspects, the reactor can be operated at higher superficial velocities for lower residence times. Operating at higher temperature severities, such as high conversion zones, helps to increase the conversion and make more light olefins. In some aspects, increasing the superficial velocity, reducing the length of the reactor, and/or separating higher value chemicals from the product stream can avoid further formation of aromatics from the light olefins formed.

In some aspects the features and advantages as disclosed above may be extended to the dual reactor concept. In some aspects high value chemicals, such as gaseous olefins, benzene, toluene, xylenes and ethyl benzene, or portions of the high value chemicals, can be separated from the product stream and the residual stream fed to the second reactor. . The residual stream may contain crackable hydrocarbons. The residual stream may be treated in the second reactor to form additional methane, gaseous olefins and/or aromatics. In some aspects, the residual stream can be cracked in the second reactor. The residence time in the reactor and/or the second reactor can be independently controlled from 0.1 to 1 second by reducing the length of the reactor and/or the second reactor to have high light gas olefin selectivity and reducing secondary cracking to aromatics. there is. In some aspects, the reactor and the second reactor can be operated at higher superficial velocities for lower residence times. Operating at higher temperature severities, such as high conversion zones, helps to increase the conversion and make more light gas olefins. In some aspects, increasing the surface temperature, reducing the length of the reactor, and/or separating higher value chemicals from the product stream can avoid further formation of aromatics from the light olefins formed. The two reactor configuration may provide increased flexibility for adjusting the cracking zone operating parameters. In some aspects, the reactor and the second reactor can receive regenerated catalyst from the regenerator, and spent catalyst from the reactor and the second reactor can be sent to the regenerator for regeneration. In some aspects, the reactor can receive regenerated catalyst from the regenerator, catalyst from the reactor outlet can be fed to the second reactor, and spent catalyst from the second reactor can be fed to the second reactor for regeneration. can be sent to the regenerator.

One aspect of the invention relates to a system for the production of olefins and aromatics. The system may include a reactor and/or regeneration unit of the present invention. In some aspects, the system can include the second reactor.

The following includes definitions of various terms and phrases used throughout this specification.

As used herein, the term "atmospheric residue" refers to the distillation bottoms stream obtained from a crude atmospheric distillation column. As used herein, the term “vacuum residue” refers to the distillation bottoms stream obtained from a crude oil vacuum distillation column. Vacuum residue refers to the hydrocarbon fraction having a boiling point above about 550°C.

The terms "light olefin", "gas phase olefin" and "light gas olefin" are used interchangeably herein and refer to ethylene, propylene and butylene.

The term "about" or "approximately" is defined as approximate as understood by one skilled in the art. In one non-limiting embodiment, the term is defined as within 10%, preferably within 5%, more preferably within 1%, and most preferably within 0.5%.

The terms “wt%”, “volume%” or “mole%” refer to the weight percentage, volume percentage, or mole percentage of a component, respectively, based on the total weight, total volume of material, or total moles of the component containing that component. means In a non-limiting example, 10 g of a component in 100 g of material is 10% by weight of the component.

The term “substantially” and variations thereof are defined to include ranges within 10%, within 5%, within 1% or within 0.5%.

The term “inhibiting” or “reducing” or “preventing” or “avoiding” or any variation of these terms as used in the claims and/or specification herein encompasses any measurable reduction or complete inhibition to achieve the desired result.

The term "effective" as used in the specification and/or claims herein means adequate to achieve a desired, expected or intended result.

When used in conjunction with any of the terms "comprising," "including," "containing," or "having" in the claims or description, the words The use of "a" or "an" can mean "one", but it can also mean "one or more", "at least one" " and "one or more than one".

The phrase "and/or" may include "and" or "or". For example, A, B and/or C include: A alone, B alone, combination of A and B, combination of A and C, combination of B and C, or combination of A, B and C can do.

The terms “comprising” (and including, e.g. any form of “comprise and comprises”) and “having” (and having, e.g. “have and has”) )"), "including" (and including, for example, any form of "includes and include") or "containing" (and containing, For example, any forms of “contains and contain” are inclusive or open-ended and do not exclude additional, unrecited elements or method steps.

The methods of the present invention may "comprise", "consist essentially of", or "consist of" certain ingredients, components, compositions, etc. disclosed throughout this specification. In one non-limiting aspect, with respect to the transitional phrase “consisting essentially of”, a fundamental and novel feature of the processes of the present invention is the hydrolysis of hydrocarbons in the presence of a hydrogen source such as H ₂ and a fluid catalyst to form olefins. and the ability to produce aromatics and then contact the catalyst with a coke precursor to form a coke catalyst.

Other objects, features and advantages of the present invention will become apparent from the following drawings, detailed description and embodiments. However, it should be understood that these drawings, detailed description and examples, while indicating specific embodiments of the invention, are given by way of example only and not intended to be limiting. It is also contemplated that variations and modifications within the spirit and scope of this invention will become apparent to those skilled in the art from the detailed description herein. In additional embodiments, features of certain embodiments may be combined with features of other embodiments. For example, features of one embodiment may be combined with features of any of the other embodiments. In additional embodiments, additional features may be added to specific embodiments disclosed herein.

The advantages of the present invention will become apparent to those skilled in the art upon reference to the following detailed description and accompanying drawings.
1 is a schematic diagram of an embodiment of the present invention for producing olefins and aromatics.
Figure 2 is a schematic diagram of a second embodiment of the present invention for producing olefins and aromatics.
Figure 3 is a schematic diagram of a third embodiment of the present invention for producing olefins and aromatics.
4A is a schematic diagram of a fourth embodiment of the present invention for producing olefins and aromatics.
4B is a top cross-sectional view of reactor 402.
Figure 5 is a schematic diagram of a fifth embodiment of the present invention for producing olefins and aromatics.
Figure 6 is a schematic diagram of a sixth embodiment of the present invention for producing olefins and aromatics.
Figure 7 is a schematic diagram of an embodiment of the present invention for producing olefins and aromatics, wherein the system of Figures 1-6 includes an optional second reactor.
Figure 8 shows the yield of total aromatics and light olefins per unit of coke for hydrogen pyrolysis and high intensity pyrolysis of plastics feed.
The present invention is capable of various modifications and substitutions, the specific embodiments of which are shown by way of example in the drawings. The drawings may not be to scale.

A discovery has been made that provides solutions to at least some of the above problems associated with producing olefins and aromatics in FCC processes. The solution may include performing hydropyrolysis of a hydrocarbon feed with a fluidized catalyst in the presence of a hydrogen source and then contacting the catalyst with a coke precursor to form a coke catalyst. It has been found in the context of the present invention that the use of a hydrogen source during fluid catalytic cracking can reduce the formation of coke on the catalyst during cracking and also increase the yield of light olefins and aromatics. The thermal balance of the process may be maintained by contacting the catalyst with a coke precursor to form coke deposits on the catalyst. Hydrogen pyrolysis process using a fluidized catalyst can be carried out in a high reactive zone of an FCC cracking unit, such as the bottom part of a riser unit or the top part of a downer unit, wherein coke formation on the fluidized catalyst It may be performed in a low reactive zone downstream of the FCC cracking unit, such as the top portion of a riser unit or the bottom portion of a downer unit.

These and other non-limiting aspects of the invention are discussed in more detail in the following sections with reference to the drawings. The apparatus shown in the drawings may be one or more heating and/or cooling devices (eg, insulation, electric heaters, wall jacketed heat exchangers) or a controller (eg, a computer) that may be used to control the temperature and pressure of the process. , fluid valves, automated valves, etc.). Although generally only one device is shown, it should be understood that multiple devices may be accommodated in one device.

Referring to Figure 1, a system and method for producing olefins and/or aromatics according to one embodiment of the present invention is described. The system 100 may include a disintegration unit 102 . The cracking unit may include a high reactivity zone 102a and a low reactivity zone 102b. The low reactivity zone 102b may be located downstream of the high reactivity zone 102a. The zones 102a and 102b may be in fluid communication. The boundary 103 between the zones may be an operational boundary rather than a physical boundary and may change position depending on conditions such as operating conditions and/or reaction conditions in the cracking unit 102. The average temperature in the high reactivity zone 102a may be higher than the average temperature in the low reactivity zone 102b. Lift stream 106 containing a source of hydrogen may be fed to cracking unit 102 in high reactivity zone 102a. Catalyst stream 108 containing a cracking catalyst, for example a fluidized catalyst, may be fed to cracking unit 102 in high reactivity zone 102a. In some aspects, lift stream 106 and catalyst stream 108 can be fed to cracking unit 102 as separate feeds and can be combined in cracking unit 102 to form a combined stream. The cracking catalyst can be fluidized in the combined stream. The overall flow direction of the catalyst together with the combined streams in cracking unit 102 is indicated by the dotted arrow. In some aspects, lift stream 106 and catalyst stream 108 may be combined and fed to a cracking unit as a combined stream (not shown). A first hydrocarbon feed stream 110 containing first hydrocarbons may be fed to cracking unit 102 in high reactivity zone 102a downstream to lift stream 106 and catalyst stream 108 . A second hydrocarbon feed stream 118 containing second hydrocarbons is sent to the cracking unit 102 in a high reactivity zone 102a downstream of the lift stream 106, the catalyst stream 108 and the first hydrocarbon feed stream 110. can be supplied with A third hydrocarbon feed stream (119) containing a third hydrocarbon is provided downstream to the lift stream (106), the catalyst stream (108), the first hydrocarbon feed stream (110), and the second hydrocarbon feed stream (118). In the reactive zone 102a it may be fed to the cracking unit 102. In cracking unit 102, first hydrocarbon feed stream 110, second hydrocarbon feed stream 118, and/or third hydrocarbon feed stream 119 are contacted with a fluidized bed cracking catalyst in the combined stream to produce spent catalyst and olefins. and/or intermediate streams containing aromatics. The olefins and/or aromatics may be formed by hydropyrolysis of at least a portion of the first, second and/or tertiary hydrocarbons. The overall flow direction of the spent catalyst together with the intermediate stream in cracking unit 102 is indicated by the dotted arrow. Coke precursor stream 112 containing coke precursor may be fed to cracking unit 102 in low reactivity zone 102b. The coke precursor, spent catalyst and intermediate streams can be contacted to form spent coking catalyst and additional olefins and/or aromatics. Coke may be deposited on the spent catalyst by contacting the coke precursor with the spent catalyst to form spent coking catalyst from the spent catalyst. Spent coking catalyst can be separated from olefins and/or aromatics. A product stream 114 containing at least a portion of additional olefins and/or aromatics, and olefins and/or aromatics from the intermediate stream may exit cracking unit 102. Stream 116 containing spent coke catalyst may exit cracking unit 102. In some aspects, the spent coking catalyst is separated from the olefins and/or aromatics in a separation device such as a volute followed by steam stripping coils and baffles for efficient stripping of hydrocarbons from the spent coking catalyst. Hydrocarbons can be further stripped from the spent coking catalyst in this equipped stripping vessel. In some aspects, oxygenate stream 120 containing oxygenates may be fed to cracking unit 102 . In some aspects, oxygenate stream 120 may be supplied to cracking unit 102 through a nozzle. In some aspects, oxygenate stream 120 is downstream of lift stream 106, catalyst stream 108, first hydrocarbon feed stream 110, and second hydrocarbon feed stream 118 and is downstream of a third hydrocarbon feed stream ( 119) can be fed to the cracking unit 102 in zone 102a upstream. In some aspects, oxygenate stream 120 is downstream to lift stream 106, catalyst stream 108, and first hydrocarbon feed stream 110 and includes second hydrocarbon feed stream 118 and third hydrocarbon feed stream. Upstream to 119 (not shown) may be fed to cracking unit 102 in zone 102a. In some aspects, oxygenate stream 120 may be fed to cracking unit 102 in zone 102b (not shown). In some aspects, multiple oxygenate streams may be fed to cracking unit 102 in zones 102a and/or 102b at multiple locations (not shown). Product stream 114 may be sent to a fractionation unit and downstream separation train for further purification of olefins and/or aromatics (not shown). Stream 116 may be sent to a regeneration unit (not shown). In some aspects, the average internal diameter of digestion unit 102 in zone 102a may be greater than the average internal diameter in zone 102b (not shown). In some aspects, the average internal diameter of digestion unit 102 in zone 102b can be greater than the average internal diameter in zone 102a (not shown).

Referring to FIG. 2, a system and method for producing olefins and/or aromatics according to a second embodiment of the present invention will be described. System 200 may include disintegration unit 202 . The cracking unit may include a high reactivity zone 202a and a low reactivity zone 202b. The low reactivity zone 202b may be located downstream of the high reactivity zone 202a. The zones 202a and 202b may be in fluid communication. The boundary 203 between the zones may be an operational boundary rather than a physical boundary, and may change position depending on conditions such as operating conditions and/or reaction conditions in the cracking unit 202 . The average temperature of the high reactivity zone 202a may be higher than the average temperature of the low reactivity zone 202b. Lift stream 206 containing a source of hydrogen may be fed to cracking unit 202 in high reactivity zone 202a. Catalyst stream 208 containing cracking catalyst, for example a fluidized catalyst, may be fed to cracking unit 202 in reactive zone 202a. In some aspects, lift stream 206 and catalyst stream 208 can be fed to cracking unit 202 as separate feeds and can be combined in cracking unit 202 to form a combined stream. The cracking catalyst can be fluidized in the combined stream. The overall flow direction of the catalyst together with the combined streams in cracking unit 202 is indicated by the dotted arrow. A first hydrocarbon feed stream 210 containing first hydrocarbons may be fed to cracking unit 202 in high reactivity zone 202a downstream to lift stream 206 and catalyst stream 208. A second hydrocarbon feed stream 218 containing a second hydrocarbon is a cracking unit in the high reactivity zone 202a downstream to the lift stream 206, the catalyst stream 208 and the first hydrocarbon feed stream 210 ( 202) can be supplied. A third hydrocarbon feed stream 219 containing a third hydrocarbon is highly reactive downstream to the lift stream 206, the catalyst stream 208, the first hydrocarbon feed stream 210 and the second hydrocarbon feed stream 218. In zone 202a it may be fed to cracking unit 202. In cracking unit 202, first hydrocarbon feed stream 210, second hydrocarbon feed stream 218 and/or third hydrocarbon feed stream 219 are contacted with a fluidized catalyst in the combined stream to break down spent catalyst and olefins and /or intermediate streams containing aromatics may be formed. The olefins and/or aromatics may be formed by hydropyrolysis of at least a portion of the first, second and/or tertiary hydrocarbons. The overall flow direction of spent catalyst along with the intermediate stream in cracking unit 202 is indicated by the dotted arrow. Coke precursor stream 212 containing coke precursor may be fed to cracking unit 202 in low reactivity zone 202b. The coke precursor, spent catalyst and intermediate streams can be contacted to form spent coking catalyst and additional olefins and/or aromatics. Coke may be deposited on the spent catalyst by contacting the coke precursor with the spent catalyst to form spent coking catalyst from the spent catalyst. Spent coking catalyst can be separated from olefins and/or aromatics. A product stream 214 containing at least a portion of additional olefins and/or aromatics, and olefins and/or aromatics from the intermediate stream may exit cracking unit 202. Stream 216 containing spent coking catalyst may exit cracking unit 202. In some aspects, the spent coking catalyst is separated from the olefins and/or aromatics in a separation device such as a volute, and then in a stripping vessel equipped with steam stripping coils and baffles for efficient stripping of hydrocarbons from the spent coking catalyst. Hydrocarbons can be additionally stripped from the spent coking catalyst. In some aspects, oxygenate streams 220a/b/c/d may be supplied to cracking unit 202 through nozzles 231a/b/c/d, respectively. The oxygenate stream may contain oxygenates. Oxygenate stream 220a may be fed to zone 202a downstream to first hydrocarbon stream 210 and upstream to second hydrocarbon stream 218 . Oxygenate stream 220b may be fed to zone 202a downstream to second hydrocarbon stream 218 and upstream to third hydrocarbon stream 219 . Oxygenate stream 220c may be fed to zone 202a downstream to third hydrocarbon stream 219. Oxygenate stream 220d may be fed to zone 202b upstream of coke precursor stream 212 . In some aspects, multiple oxygenate streams may be fed to cracking unit 202 in zones 202a and/or 202b at multiple locations. Product stream 214 may be sent to a fractionation unit and downstream separation train for further purification of olefins and/or aromatics (not shown). Stream 216 may be sent to a regeneration unit (not shown). The average internal diameter of digestion unit 202 in zone 202a may be greater than the average internal diameter in zone 202b. Under similar process conditions, the average hydrocarbon residence time in such a reactor, e.g., reactor 202, may be lower in the upstream high reactivity zone and the downstream low reactivity zone compared to a reactor having a similar or identical average inside diameter; The olefin selectivity over the aromatic selectivity from hydrocracking can be increased with the design of such a reactor, for example reactor 202.

Referring to FIG. 3, a system and method for producing olefins and/or aromatics according to a third embodiment of the present invention is described. System 300 may include disintegration unit 302 . The cracking unit may include a high reactivity zone 302a and a low reactivity zone 302b. The low reactivity zone 302b may be located downstream of the high reactivity zone 302a. The zones 302a and 302b may be in fluid communication. The boundary 303 between the zones may be an operational boundary rather than a physical boundary, and may change position depending on conditions such as operating conditions and/or reaction conditions in the cracking unit 302. The average temperature of the high reactivity zone 302a may be higher than the average temperature of the low reactivity zone 302b. Lift stream 306 containing a source of hydrogen may be fed to cracking unit 302 in high reactivity zone 302a. Catalyst stream 308 containing cracking catalyst, for example a fluidized catalyst, may be fed to cracking unit 302 in high reactivity zone 302a. In some aspects, lift stream 306 and catalyst stream 308 may be fed to cracking unit 302 as separate feeds and may be combined in cracking unit 302 to form a combined stream. The cracking catalyst can be fluidized in the combined stream. The overall flow direction of the catalyst together with the combined streams in cracking unit 302 is indicated by the dotted arrow. A first hydrocarbon feed stream 310 containing first hydrocarbons may be fed to cracking unit 302 in high reactivity zone 302a downstream to lift stream 306 and catalyst stream 308. A second hydrocarbon feed stream 318 containing a second hydrocarbon is a cracking unit ( 302) can be supplied. A third hydrocarbon feed stream 319 containing a third hydrocarbon is highly reactive downstream to the lift stream 306, the catalyst stream 308, the first hydrocarbon feed stream 310 and the second hydrocarbon feed stream 318. It may be fed to cracking unit 302 in zone 302a. In cracking unit 302, first hydrocarbon feed stream 310, second hydrocarbon feed stream 318, and/or third hydrocarbon feed stream 319 are contacted with a fluidized catalyst in the combined stream to produce spent catalyst and olefins. and/or intermediate streams containing aromatics. The olefins and/or aromatics may be formed by hydrocracking of at least a portion of the first, second and/or tertiary hydrocarbons. The overall flow direction of spent catalyst along with the intermediate stream in cracking unit 302 is indicated by the dotted arrow. Coke precursor stream 312 containing coke precursor may be fed to cracking unit 302 in low reactivity zone 302b. The coke precursor can contact the spent catalyst to form spent coking catalyst and additional olefins and/or aromatics. Coke may be deposited on the spent catalyst by contacting the coke precursor with the spent catalyst to form spent coking catalyst from the spent catalyst. Spent coking catalyst can be separated from olefins and/or aromatics. A product stream 314 containing at least a portion of additional olefins and/or aromatics, and olefins and/or aromatics from the intermediate stream may exit cracking unit 302. Stream 316 containing spent coke catalyst may exit cracking unit 302. In some aspects, the spent coking catalyst is separated from the olefins and/or aromatics in a separation device such as a volute, and then in a stripping vessel equipped with a stripping coil and baffles to efficiently strip hydrocarbons from the spent coking catalyst. Hydrocarbons can be additionally stripped from the spent coking catalyst. In some aspects, oxygenate streams 320a/b/c/d may be supplied to cracking unit 302. In some aspects, oxygenate streams 320a/b/c/d may be supplied to cracking unit 302 through nozzles 331a/b/c/d, respectively. The oxygenate stream may contain oxygenates. Oxygenate stream 320a may be fed to zone 302a downstream to first hydrocarbon stream 310 and upstream to second hydrocarbon stream 318 . Oxygenate stream 320b may be fed to zone 302a downstream to second hydrocarbon stream 318 and upstream to third hydrocarbon stream 319 . Oxygenate stream 320c may be fed to zone 302a downstream to third hydrocarbon stream 319. Oxygenate stream 320d may be fed to zone 302b upstream to coke precursor stream 312. In some aspects, multiple oxygenate streams may be fed to cracking unit 302 in zones 302a and/or 302b at multiple locations. Product stream 314 may be sent to a fractionation unit and downstream separation for further purification of olefins and/or aromatics (not shown). Stream 316 may be sent to a regeneration unit (not shown). The average internal diameter of digestion unit 302 in zone 302b may be greater than the average internal diameter in zone 302a. Under similar process conditions, the average hydrocarbon residence time in such a reactor, e.g., reactor 302, may be higher in the upstream high reactivity zone and the downstream low reactivity zone compared to a reactor having a similar or identical average internal diameter; The olefin selectivity over the aromatic selectivity from hydrocracking can be increased with the design of such a reactor, for example reactor 302.

Referring to Figs. 4A to 4B, a system and method for producing olefins and/or aromatics according to a fourth embodiment of the present invention are described. System 400 may include disintegration unit 402 . The cracking unit may include a high reactivity zone 402a and a low reactivity zone 402b. The low reactivity zone 402b may be located downstream of the high reactivity zone 402a. The zones 402a and 402b may be in fluid communication. The boundary 403 between the zones may be an operational boundary rather than a physical boundary and may change position depending on conditions such as operating conditions and/or reaction conditions in cracking unit 402 . The average temperature of the high reactivity zone 402a may be higher than the average temperature of the low reactivity zone 402b. Reactor 402 may include one or more first heater(s) positioned along wall 421 along the length of reactor 402 . One or more first heater(s) may form the first heater layer 422 . The reactor 402 can include an insulating layer 424 positioned along an outer surface of the first heat layer 422 . Reactor 402 may further include one or more second heater(s) positioned along an outer surface of insulating layer 424 , forming second heater layer 426 . The reactor 402 can include a second insulating layer 430 positioned along an outer surface of the second heat layer 426 . Reactor 402 may further include one or more temperature sensors 428 located on wall 421 configured to measure the temperature of the reactor. A top cross-sectional view of reactor 402 is shown in FIG. 4B. Wall 421 , first heater layer 422 , insulating layer 424 and second heater layer 426 and second insulating layer 430 may surround the bore of reactor 402 . Lift stream 406 containing a source of hydrogen may be fed to cracking unit 402 in high reactivity zone 402a. Catalyst stream 408 containing a cracking catalyst, for example a fluidized catalyst, may be fed to cracking unit 402 in high reactivity zone 402a. In some aspects, lift stream 406 and catalyst stream 408 can be fed to cracking unit 402 as separate feeds and can be combined in cracking unit 402 to form a combined stream. The catalyst can be fluidized in the combined stream. The overall flow direction of the catalyst together with the combined streams in cracking unit 402 is indicated by the dotted arrow. A first hydrocarbon feed stream 410 containing first hydrocarbons may be fed to cracking unit 402 in high reactivity zone 402a downstream to lift stream 406 and catalyst stream 408. A second hydrocarbon feed stream 418 containing a second hydrocarbon is a cracking unit in the high reactivity zone 402a downstream to the lift stream 406, catalyst stream 408 and first hydrocarbon feed stream 410 402) can be supplied. A third hydrocarbon feed stream 419 containing a third hydrocarbon is highly reactive downstream to the lift stream 406, the catalyst stream 408, the first hydrocarbon feed stream 410 and the second hydrocarbon feed stream 418. It may be fed to cracking unit 402 in zone 402a. In cracking unit 402, first hydrocarbon feed stream 410, second hydrocarbon feed stream 418, and/or third hydrocarbon feed stream 419 are contacted with a fluidized catalyst in the combined stream to produce spent catalyst and olefins. and/or intermediate streams containing aromatics. The olefins and/or aromatics may be formed by hydropyrolysis of at least a portion of the first, second and/or tertiary hydrocarbons. The overall flow direction of spent catalyst along with the intermediate stream in cracking unit 402 is indicated by the dotted arrow. Coke precursor stream 412 containing coke precursor may be fed to cracking unit 402 in low reactivity zone 402b. The coke precursor, spent catalyst and intermediate streams may be contacted to form spent coking catalyst and additional olefins and/or aromatics. Coke may be deposited on the spent catalyst by contacting the coke precursor with the spent catalyst to form spent coking catalyst from the spent catalyst. Spent coking catalyst can be separated from olefins and/or aromatics. A product stream 414 containing at least a portion of additional olefins and/or aromatics, and olefins and/or aromatics from the intermediate stream may exit cracking unit 402. Stream 416 containing spent coke catalyst may exit cracking unit 402. In some aspects, the spent coking catalyst is separated from the olefins and/or aromatics in a separation device such as a volute, then in a stripping vessel equipped with steam stripping coils and baffles for efficient stripping of hydrocarbons from the spent coking catalyst. Hydrocarbons can be additionally stripped from the spent coking catalyst. In some aspects, oxygenate stream 420 containing oxygenates may be fed to cracking unit 402 . In some aspects, oxygenate stream 420 may be supplied to cracking unit 402 through a nozzle. In some aspects, oxygenate stream 420 is downstream to lift stream 406, catalyst stream 408, first hydrocarbon feed stream 410 and second hydrocarbon feed stream 418 and a third hydrocarbon feed stream. It may be fed to cracking unit 402 in zone 402a upstream to 419. In some aspects, oxygenate stream 420 is downstream to lift stream 406, catalyst stream 408 and first hydrocarbon feed stream 410 and to second hydrocarbon feed unit 418 and third hydrocarbon feed unit. In zone 402a upstream to 419, cracking unit 402 may be fed. In some aspects, oxygenate stream 420 may be fed to cracking unit 402 in zone 402b (not shown). In some aspects, multiple oxygenate streams may be fed to cracking unit 402 in zones 402a and/or 402b at multiple locations (not shown). Product stream 414 may be sent to a fractionation unit for further purification of olefins and/or aromatics (not shown). Stream 416 may be sent to a regeneration unit (not shown). In some aspects, the average internal diameter of digestion unit 402 in zone 402a can be greater than the average internal diameter in zone 402b (not shown). In some aspects, the average internal diameter of digestion unit 402 in zone 402b can be greater than the average internal diameter in zone 402a (not shown).

Referring to FIG. 5, a system and method for producing olefins and/or aromatics according to a fifth embodiment of the present invention are described. System 500 may include a riser 502 and a regeneration unit 530 . Riser 502 may include a high reactivity zone 502a and a low reactivity zone 502b. The low reactivity zone 502b may be located downstream, eg above the high reactivity zone 502a. The zones 502a and 502b may be in fluid communication. The boundary 503 between the zones may be an operable boundary rather than a physical boundary, and may change position depending on conditions such as operating conditions and/or reaction conditions in the riser 502 . The average temperature of the high reactivity zone 502a may be higher than the average temperature of the low reactivity zone 502b. A lift stream 506 containing a source of hydrogen may be fed to the riser 502 in the highly reactive zone 502a from the bottom portion of the riser. A lift stream 506 may assist in the upward flow of material in the riser. Catalyst stream 508 containing cracking catalyst, for example, fluidized catalyst, may be fed to riser 502 in high reactivity zone 502a. In some aspects, lift stream 506 and catalyst stream 508 may be supplied to riser 502 as separate feeds and may be combined in riser 502 to form a combined stream. The catalyst can be fluidized in the combined stream. In some aspects, lift stream 506 and catalyst stream 508 may be combined and fed to a cracking unit as a combined stream (not shown). A first hydrocarbon feed stream 510 containing first hydrocarbons may be fed to cracking unit 502 in high reactivity zone 502a downstream to lift stream 506 and catalyst stream 508. A second hydrocarbon feed stream 518 containing a second hydrocarbon is fed to the riser 502 in a high reactivity zone 502a downstream to the lift stream 506, the catalyst stream 508 and the first hydrocarbon feed stream 510. can be supplied with A third hydrocarbon feed stream 519 containing a third hydrocarbon is highly reactive downstream to the lift stream 506, the catalyst stream 508, the first hydrocarbon feed stream 510 and the second hydrocarbon feed stream 518. Zone 502a may be fed to riser 502 . In riser 502, first hydrocarbon feed stream 510, second hydrocarbon feed stream 518, and/or third hydrocarbon feed stream 519 are contacted with a fluidized catalyst in the combined stream to reduce spent catalyst and olefins. and/or intermediate streams containing aromatics. The olefins and/or aromatics may be formed by hydropyrolysis of at least a portion of the first, second and/or tertiary hydrocarbons. Coke precursor stream 512 containing coke precursor may be fed to riser 502 in low reactivity zone 502b. The coke precursor, spent catalyst and intermediate streams can be contacted to form spent coking catalyst and additional olefins and/or aromatics. Coke may be deposited on the spent catalyst by contacting the coke precursor with the spent catalyst to form spent coking catalyst from the spent catalyst. Spent coking catalyst can be separated from olefins and/or aromatics. A product stream 514 containing at least a portion of the additional olefins and/or aromatics and olefins and/or aromatics from the intermediate stream may exit the riser 502 from an upper portion of the riser. Stream 516 containing spent coke catalyst may exit riser 502. In some aspects, the spent coking catalyst is separated from the olefins and/or aromatics in a separation device such as a volute, then in a stripping vessel equipped with steam stripping coils and baffles for effective stripping of hydrocarbons from the spent coking catalyst. Further stripping of hydrocarbons from the spent coking catalyst may follow. In some aspects, oxygenate stream 520 containing oxygenates may be supplied to riser 502 . In some aspects, oxygenate stream 520 may be supplied to riser 502 through a nozzle. In some aspects, oxygenate stream 520 is downstream to lift stream 506, catalyst stream 508, first hydrocarbon feed stream 510 and second hydrocarbon feed stream 518, and a third hydrocarbon feed. In zone 502a upstream to stream 519 may be fed to riser 502. In some aspects, oxygenate stream 520 is downstream to lift stream 506, catalyst stream 508, and first hydrocarbon feed stream 510 and to a second hydrocarbon feed stream 518 and a third hydrocarbon feed stream. may be supplied to riser 502 in zone 502a upstream to 519 (not shown). In some aspects, oxygenate stream 520 may be supplied to riser 502 in zone 502b (not shown). In some aspects, multiple oxygenate streams may be supplied to riser 502 in zones 502a and/or 502b at multiple locations (not shown). In some aspects, riser 502 may include one or more heater(s), one or more temperature sensor(s), and/or an insulating layer as described for system 400 (FIGS. 4A and B) (not shown). city). In some aspects, the average inner diameter of riser 502 in zone 502a may be greater than the average inner diameter in zone 502b (not shown). In some aspects, the average inner diameter of riser 502 in zone 502b can be greater than the average inner diameter in zone 502a (not shown). Product stream 514 may be sent to a fractionation unit for further purification of olefins and/or aromatics (not shown). Stream 516 may be sent to replay unit 530 . Regeneration stream 532 containing oxygen (O ₂ ) may be fed to regeneration unit 530 . In regeneration unit 530, regeneration stream 532 can contact spent coking catalyst and regenerate cracking catalyst from the spent coking catalyst. Cracked catalyst regenerated from regeneration unit 530 may be recycled to riser 502 via stream 508. An effluent stream 534 containing carbon oxides produced from the catalyst regeneration process with a regeneration stream may exit regeneration unit 530 . In some aspects, effluent stream 534 may be sent to a CO boiler unit (not shown).

Referring to FIG. 6, a system and method for producing olefins and/or aromatics according to a sixth embodiment of the present invention are described. System 600 may include a downer 602 and a regeneration unit 630 . The downer 602 can include a high reactivity zone 602a and a low reactivity zone 602b. Low reactivity zone 602b may be located downstream, eg, below high reactivity zone 602a. The zones 602a and 602b may be in fluid communication. The boundary 603 between the zones may be an operable boundary rather than a physical boundary and may change position depending on conditions such as operating conditions and/or reaction conditions in the downer 602 . The average temperature of the high reactivity zone 602a may be higher than the average temperature of the low reactivity zone 602b. A lift stream 606 containing a source of hydrogen may be fed from the upper portion of downer 602 to downer 602 in high reactivity zone 602a. Lift stream 606 may assist in the downward flow of material in downer 602 . Catalyst stream 608 containing a cracking catalyst, for example a fluidized catalyst, may be fed from high reactivity zone 602a to downer 602. In some aspects, lift stream 606 and catalyst stream 608 can be fed to downer 602 as separate feeds and can be combined in downer 602 to form a combined stream. The catalyst can be fluidized in the combined stream. In some aspects, lift stream 606 and catalyst stream 608 may be combined and fed to a cracking unit as a combined stream (not shown). A first hydrocarbon feed stream 610 containing first hydrocarbons may be fed to cracking unit 602 in high reactivity zone 602a downstream to lift stream 606 and catalyst stream 608. A second hydrocarbon feed stream 618 containing a second hydrocarbon is sent to the downer 602 in the high reactivity zone 602a downstream to the lift stream 606, catalyst stream 608 and first hydrocarbon feed stream 610. ) can be supplied. A third hydrocarbon feed stream 619 containing a third hydrocarbon is highly reactive downstream to the lift stream 606, the catalyst stream 608, the first hydrocarbon feed stream 610 and the second hydrocarbon feed stream 618. Zone 602a may be fed to downer 602. In the downer 602, the first hydrocarbon feed stream 610, the second hydrocarbon feed stream 618, and/or the third hydrocarbon feed stream 619 are contacted with a fluidized catalyst in the combined stream to reduce the spent catalyst and Intermediate streams containing olefins and/or aromatics may be formed. The olefins and/or aromatics may be formed by hydropyrolysis of at least a portion of the first, second and/or tertiary hydrocarbons. A coke precursor stream 612 containing coke precursor may be fed from the low reactivity zone 602b to the downer 602. The coke precursor, spent catalyst and intermediate streams can be contacted to form spent coking catalyst and additional olefins and/or aromatics. Coke may be deposited on the spent catalyst by contacting the coke precursor with the spent catalyst to form spent coking catalyst from the spent catalyst. Spent coking catalyst can be separated from olefins and/or aromatics. A product stream 614 containing at least a portion of the additional olefins and/or aromatics and olefins and/or aromatics from the intermediate stream may exit the downer 602 from the bottom portion of the riser. A stream 616 containing spent coking catalyst may exit the downer 602. In some aspects, the spent coking catalyst may be separated from the olefins and/or aromatics in a separation unit to further strip hydrocarbons from the spent coking catalyst. In some aspects oxygenate stream 620 containing oxygenates may be fed to downer 602 . In some aspects, oxygenate stream 620 may be supplied to downer 602 through a nozzle. In some aspects, oxygenate stream 620 comprises lift stream 606, catalyst stream 608, first hydrocarbon feed stream 610, second hydrocarbon feed stream 618, and third hydrocarbon feed stream 619. ) can be supplied to the downer 602 in the zone 602a downstream of . In some aspects, oxygenate stream 620 is downstream to lift stream 606, catalyst stream 608, and first hydrocarbon feed stream 610 and to a second hydrocarbon feed stream 618 and a third hydrocarbon feed stream. may be fed to downer 602 in section 602a upstream to 619 (not shown). In some aspects, oxygenate stream 620 may be supplied to downer 602 in zone 602b (not shown). In some aspects, multiple oxygenate streams may be supplied to downer 602 in zones 602a and/or 602b at multiple locations (not shown). In some aspects, downer 602 includes one or more heater(s), one or more temperature sensor(s), and/or an insulator layer (not shown) as described in system 400 ( FIGS. 4A and B). can do. In some aspects, the average inner diameter of the downers 602 in zone 602a may be greater than the average inner diameter in zone 602b (not shown). In some aspects, the average inner diameter of the downers 602 in zone 602b may be greater than the average inner diameter in zone 602a (not shown). Product stream 614 may be sent to a fractionation unit and downstream separation train for further purification of olefins and/or aromatics (not shown). Stream 616 may be sent to replay unit 630 . Regeneration stream 632 containing oxygen (O ₂ ) may be fed to regeneration unit 630 . Regeneration stream 632 in regeneration unit 630 may contact the spent coking catalyst and regenerate cracking catalyst from the spent coking catalyst. Cracked catalyst regenerated from regeneration unit 630 may be recycled to downer 602 via stream 608. An effluent stream 634 containing carbon oxides produced from the catalyst regeneration process with a regeneration stream may exit regeneration unit 630 . In some aspects, effluent stream 634 can be sent to a CO boiler unit (not shown).

Referring to FIG. 7 , in certain aspects, system 100 , 200 , 300 , 400 , 500 , or 600 may further include an independently optional second reactor 702 . High value chemicals (e.g., gaseous olefins, benzene, toluene, xylenes and/or ethyl benzene) or at least a portion of the high value chemicals are transferred from separator 704 to product stream 114, 214, 314, 414, 514 or 614. respectively) to form a high value chemical stream 714 and a residual stream 706. Stream 714 may be further purified to produce purified ethene, propene, butenes, benzene, toluene, xylenes and/or ethyl benzene. Residue stream 706 may contain crackable hydrocarbons and may be fed to an optional second reactor 702. Stream 708 containing catalyst may be fed to reactor 702. In some aspects, stream 708 may contain regenerated catalyst from a regenerator. In some aspects, the regenerator can be the same regenerator (e.g., 530, 630 for systems 500 and 600, respectively) from which the regenerated catalyst (e.g., streams 108, 208, 308, 408, 508, and 608, respectively) via) is fed to the reactor (102, 202, 302, 402, 502 or 602, respectively). In some aspects, stream 708 may contain catalyst, effluent from stream 116, 216, 316, 416, 516, or 616 from reactor 102, 202, 302, 402, 502, or 602, respectively. there is. In the second reactor 702, the residual stream (eg, hydrocarbons in the residual stream) may be cracked to produce additional methane, gaseous olefins, and/or aromatics. A stream 710 comprising additional methane, gaseous olefins and/or aromatics may exit the reactor. Stream 710 may be further purified to produce purified methane, gaseous olefins and/or aromatics. Stream 716 containing spent catalyst may exit second reactor 702 and may be sent to a regenerator. In some aspects, the regenerator can be the same regenerator (e.g., 530, 630 for system 500 or 600, respectively) from which the regenerated catalyst (e.g., stream 108, 208, 308, 408, 508, or 608, respectively) via) is fed to the reactors 102, 202, 302, 402, 502 or 602, respectively. Residue stream 706 may be treated in second reactor 702 to form additional methane, gaseous olefins and/or aromatics. In some aspects, residual stream 706 (eg, hydrocarbons in the residual stream) may be cracked in second reactor 702. The residence time in the second reactor 702 can be controlled from 0.1 to 1 second. A two reactor configuration can provide increased flexibility for adjusting digestion zone operating parameters.

In the high reactivity zones 102a, 202a, 302a, 402a, 502a, 602a, the olefins and aromatics are separated from the first, second and/or aromatics in a hydrogen pyrolysis mode by cracking of the first, second and/or third hydrocarbons. It may be formed by contacting a third hydrocarbon with a cracking catalyst, and the catalyst used may be formed from the cracking catalyst. The hydrogen source in the high reactivity zone can reduce coke formed on the cracking catalyst and/or spent catalyst. The contact conditions of the first, second and/or third hydrocarbon and the cracking catalyst in the high reactivity zones 102a, 202a, 302a, 402a, 502a, 602a are 500 °C to 750 °C, alternatively 600 °C to 850 °C, alternatively 600 °C. °C to 750 °C, or a temperature of 700 °C to 850 °C, or at least any one of 500, 525, 550, 575, 600, 625, 650, 675, 700, 725, 750, 775, 800, 825 and 850 °C , a temperature equal to any one of these, or between any two of them. Increasing the contact temperature in the high reactivity zones 102a, 202a, 302a, 402a, 502a, 602a can result in a higher ethylene yield than propylene by the cracking process (eg, higher ethylene to propylene product ratio). In some aspects, the contacting conditions are (i) a pressure in the reactor of from 0.5 bara to 5 bara or at least any one of, equal to any one of, or any of 0.5, 1, 2, 3, 4 and 5 bara and/or (ii) a contact time between 0.1 and 5 seconds or at least any one of 0.1, 0.3, 0.5, 0.7, 0.9, 1, 2, 3, 4, 5 seconds, any one of these It may further include a contact time equal to, or between any two of them.

In the low reactivity zones 102b, 202b, 302b, 402b, 502b, 602b, spent coking catalyst may be formed from the spent catalyst by contacting the spent catalyst with a coke precursor. The coke precursor may deposit coke on the spent catalyst to form spent coking catalyst. The contact conditions of the coke precursor and the catalyst used in the low reactivity zones (102b, 202b, 302b, 402b, 502b, 602b) are i) a temperature of 500 ° C to 850 ° C or 500, 525, 550, 575, 600, 650, 675 , 700, 725, 750, 775, 800, 825 and 850 °C at least any one, equal to any one of these, or a temperature between any two of these, ii) from 0.5 bara to 5 bara or 0.5, 1 , at least any one of 2, 3, 4 and 5 bara, equal to any one of them, or a pressure between any two of them, and/or iii) a contact time of 0.1 to 5 seconds or 0.1, 0.3, 0.5 . The spent coking catalyst comprises 0.1% to 10% by weight of coke or 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10% by weight of at least any one of, any of these cocose in weight percent equal to one of, or between any two of these. The catalyst to feed (w/w) ratio in the high reactivity zones (102a, 202a, 302a, 402a, 502a, 602a) is the catalyst to feed (w/w) ratio in the low reactivity zones (102b, 202b, 302b, 402b, 502b, 602b). It may be higher than the water (w/w) ratio.

Lift streams 106, 206, 306, 406, 506, 606 may contain a source of hydrogen. In some aspects, the hydrogen source can be hydrogen (H ₂ ) gas. In some aspects, the lift streams 106, 206, 306, 406, 506, 606 contain a hydrogen source such as 0.1 vol % to 99 vol % hydrogen (H ₂ ) gas or 0.1, 0.5, 1, 2, 3, 4 , 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 99, 99.5 and 99.9 at least any one, equivalent to any one of these, or these A hydrogen source such as hydrogen (H ₂ ) gas at a volume percent between any two of and 0.1 vol % to 99.9 vol % steam or 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, at least any one of 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 99, 99.5 and 99.9, equivalent to any one of these, or in volume percent between any two of these May contain vapors. In some specific aspects, lift streams 106, 206, 306, 406, 506, 606 contain 0 vol % to 35 vol % methane or 0, 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7 , 8, 9, 10, 20, 30, and 35 at least any one of, equivalent to any one of, or between any two of these in volume percent methane, 0 volume percent to 25 volume percent ethane, or at least any one of, equal to any one of, or between any two of 0, 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 20 and 25 % by volume of ethane, and from 0% by volume to 25% by volume of ethylene or at least any of 0, 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 20 and 25 ethylene in a volume percent equal to one, any one of these, or between any two of them. Lift streams 106, 206, 306, 406, 506, 606 may assist material flow in reactors 102, 202, 302, 402, 502, 602, 602) can be used to control residence time, such as the average hydrocarbon residence time, as well as for improved contacting and mixing of the hydrocarbon stream with the catalyst.

Catalyst streams 108, 208, 308, 408, 508, 608 may contain a fluidized cracking catalyst. The cracking catalyst may contain a zeolite catalyst, a fluid catalytic cracking (FCC) catalyst, a hydrocracking catalyst, an aluminosilicate or any combination thereof. Non-limiting examples of zeolite catalysts include ZSM-5, ZSM-11, ferrierite, helandite, zeolite A, erionite, and chabazite, or any combination thereof. In some aspects, the zeolite catalyst may be present in an active or inert matrix. Non-limiting examples of FCC catalysts include X-type zeolites, Y-type and/or USY-type zeolites, mordenite, faujasite, nano-crystalline zeolites, MCM mesoporous materials, SBA-15, silica-aluminum. furnace phosphate, gallophosphate, titanophosphate, a catalyst that has been consumed or equilibrated from FCC units, or any combination thereof. The zeolites referred to herein may be metal supported zeolites. The FCC catalyst may be present in an active or inactive matrix with or without a metal support. A non-limiting example of a hydrocracking catalyst includes a metal oxide with a metal sulfide in the form of an active catalyst on a support. In some aspects, the support can be silica, aluminum carbon, titania, zirconia or aluminosilicate or any combination thereof. In some aspects, the cracking catalyst can be a zeolite and/or a metal supported zeolite. Zeolites and/or metal-bearing zeolites may be intercalated in the matrix. In some aspects, the cracking catalyst can be ZSM-5 and/or metal supported ZSM-5.

The first hydrocarbon feed stream (110, 210, 310, 410, 510, 610) includes naphtha, condensate, such as petroleum condensate, gas oil, C ₃ and C ₄ saturated gas, cracked naphtha stream, C ₃ and may contain recycled degradable hydrocarbon streams containing C ₄ saturated gases and/or recycled gases and low molecular weight liquids from the process (e.g. recovered from 114, 214, 314, 414, 514, 614, respectively); , the first hydrocarbon is added to naphtha, condensates, such as petroleum condensates, gas oils, cracked naphtha streams, C ₃ saturated gases, C ₄ saturated gases, and/or recycled gases and low molecular weight liquids from the process. It may contain one or more hydrocarbons. In some aspects, the naphtha may be direct run naphtha or cracked naphtha. In certain aspects, the first hydrocarbon feed stream (110, 210, 310, 410, 510, 610) may further contain an oxygenate such as methanol. In some aspects, the first hydrocarbon feed stream (110, 210, 310, 410, 510, 610) contains 0 vol % to 20 vol % of an oxygenate such as methanol or 0, 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, and 20% by volume of at least any one of, equivalent to any one of, or in volume% between any two of an oxygenate such as methanol. may contain. Oxygenates can decompose in the reactor to generate heat or reduce coke in the cracking catalyst and/or spent catalyst. In some aspects, the first hydrocarbon feed stream (110, 210, 310, 410, 510, 610) can be preheated to a desired temperature level and fed to a cracking unit.

The second hydrocarbon feed stream (118, 218, 318, 418, 518, 618) is crude oil; atmospheric residue; vacuum gas oil; unconverted oil in the hydrocracker, for example at the bottom of the hydrocracker; hydrowax; plastics or polymers dissolved or slurried in a solvent; polyolefin oligomers; plastic; partially depolymerized plastics; plastic pyrolysis oil; hydrogenated plastic pyrolysis oil; recycled naphtha and gas oil streams; naphtha; gas oil; vacuum gas oil and/or unconverted oil products from hydrocracking of plastics; or recycled degradable heavier hydrocarbon liquids from the process (e.g., recovered from 114, 214, 314, 414, 514, 614, respectively) or any combination thereof, wherein the second hydrocarbon is crude oil. ; atmospheric residue; vacuum gas oil; unconverted oil in the hydrocracker, for example at the bottom of the hydrocracker; hydrowax; plastics or polymers dissolved or slurried in a solvent; polyolefin oligomers; plastic; partially depolymerized plastics; plastic pyrolysis oil; hydrogenated plastic pyrolysis oil; recycled naphtha and gas oil streams; naphtha; gas oil; vacuum gas oil and/or unconverted oil products from hydrocracking of plastics; or one or more hydrocarbons included in recycled degradable heavier hydrocarbon liquids from the process (e.g., recovered from 114, 214, 314, 414, 514, 614, respectively) or any combination thereof. In certain aspects, the second hydrocarbon feed stream (118, 218, 318, 418, 518, 618) may further contain an oxygenate such as methanol. In some aspects, the second hydrocarbon feed stream (118, 218, 318, 418, 518, 618) contains 0 vol % to 20 vol % of an oxygenate such as methanol or 0, 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, and 20% by volume of at least any one of, equivalent to any one of, or in volume% between any two of an oxygenate such as methanol. may contain. Oxygenates can decompose in the reactor to generate heat or reduce coke in the cracking catalyst and/or spent catalyst. In some aspects, the second hydrocarbon feed stream (118, 218, 318, 418, 518, 618) can be preheated to a desired temperature level and fed to a cracking unit.

The third hydrocarbon feed stream (119, 219, 319, 419, 519, 619) is crude oil; atmospheric residue; vacuum gas oil; unconverted oil in the hydrocracker, for example at the bottom of the hydrocracker; hydrowax; polyolefin oligomers; plastic; partially depolymerized plastics; plastics or polymers dissolved or slurried in a solvent; plastic pyrolysis oil; hydrogenated plastic pyrolysis oil; heavy recycled degradable hydrocarbon streams; gas oil; vacuum gas oil; unconverted oil products from hydrocracking of plastics; products from hydrocracking of recycled heavy liquids or plastics from the process (eg, recovered from 114, 214, 314, 414, 514, 614, respectively); or any combination thereof, and the third hydrocarbon is crude oil; atmospheric residue; vacuum gas oil; unconverted oil in the hydrocracker, for example at the bottom of the hydrocracker; hydrowax; polyolefin oligomers; plastic; partially depolymerized plastics; plastics or polymers dissolved or slurried in a solvent; plastic pyrolysis oil; hydrogenated plastic pyrolysis oil; heavy recycled degradable hydrocarbon streams; gas oil; vacuum gas oil; unconverted oil products from hydrocracking of plastics; products from hydrocracking of recycled heavy liquids or plastics from the process (eg, recovered from 114, 214, 314, 414, 514, 614, respectively); or one or more hydrocarbons included in any combination thereof. In certain aspects, the third hydrocarbon feed stream (119, 219, 319, 419, 519, 619) may further contain an oxygenate such as methanol. In some aspects, the third hydrocarbon feed stream (119, 219, 319, 419, 519, 619) contains 0% to 20% by volume of an oxygenate such as methanol or 0, 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, and 20% by volume of at least any one of, equivalent to any one of, or in volume% between any two of an oxygenate such as methanol. may contain. Oxygenates can decompose in the reactor to generate heat or reduce coke in the cracking catalyst and/or spent catalyst. In some aspects, the third hydrocarbon feed stream (119, 219, 319, 419, 519, 619) can be preheated to a desired temperature level and fed to a cracking unit.

Oxygenate streams 120, 220a, 220b, 220c, 220d, 320a, 320b, 320c, 320d, 420, 520, 620 may contain oxygenates. In some aspects, the oxygenate can be methanol. Oxygenates can decompose in reactors 102, 202, 302, 402, 502, 602 to generate heat. The heat produced can reduce the temperature drop in the reactors 102, 202, 302, 402, 502, 602 during the hydrogen pyrolysis process. When an oxygenate is introduced into the reactors (102, 202, 302, 402, 502, 602), compared to the case where the oxygenate is not introduced, 114, 214, 314 , 414, 514, 614 outlets can reduce the temperature drop. Reducing the temperature drop may increase the yield of olefins and/or aromatics produced by cracking in reactors 102, 202, 302, 402, 502, and 602. In some aspects, the oxygenate flow rate to the reactor can be controlled to control the local temperature of the reactor at the location(s) where the oxygenate is supplied and to establish a temperature profile in the reactor. Also when used with feed through the feed inlet nozzle, the oxygenate has the beneficial effect of atomizing the feed into smaller droplets and also results in lower coke deposition on the catalyst.

Coke precursor stream 112, 212, 312, 412, 512, 612 may contain coke precursor. In some aspects, the coke precursor is a fluid catalytic cracking cycle oil and slurry oil, coker stream, slurry oil, crude oil, carbon black oil, cracked distillate, vacuum residue or cracked oil, such as bio-oil or fuel oil. cracked oil from a source, or any combination thereof. In some aspects, the coke precursor streams 112, 212, 312, 412, 512, 612 may additionally contain steam. In some aspects, the coke precursor stream comprises from 40 vol % to 100 vol % coke precursor or at least any one of, equal to any one of, 40, 50, 60, 70, 80, 90, and 100 vol %, or Coke precursor and 0 vol % to 60 vol % steam or at least any one of 0, 10, 20, 30, 40, 50, and 60 vol % between any two of these, any one of these Vapor % vapor equal to, or between any two of these.

Product streams 114, 214, 314, 414, 514, and 614 may contain light olefins and aromatics. In some aspects, the light olefin can be ethylene, propylene or butylene or any combination thereof. In some aspects, the aromatic can be benzene, toluene, xylene or ethyl benzene or any combination thereof.

In regeneration units 530, 630, regeneration streams 532, 632 and spent coking catalyst streams 516, 616 are subjected to (i) a temperature of 500 to 850° C. or 500, 525, 550, 575, 600, 625 , at least any one of 650, 675, 700, 725, 750, 775, 800, 825 and 850 °C, equal to any one of these, or a temperature between any two of these, (ii) from 0.5 bara to 5 bara or at least any one of 0.5, 1, 2, 3, 4 and 5 bara, equal to any one of these, or a pressure between any two of these, or (iii) from 5 minutes to 30 minutes At a contact time of at least any one of 5 minutes, 10 minutes, 15 minutes, 20 minutes, 25 minutes and 30 minutes, equivalent to any one of these, or a contact time between any two of these, or a combination thereof It is contacted at, and the decomposition catalyst can be regenerated. In some aspects, recycle streams 532 and 632 may contain 18 vol % to 30 vol % or 20 vol % to 25 vol % O ₂ . The regeneration process may generate heat and at least some of the heat may be provided to the reactors 102 , 202 , 302 , 402 , 502 , 602 . In some aspects, the recycle stream may contain air, diluted air, and/or oxygen enriched air. In some aspects, in the regenerator, an optional feed to fuel gas or heavy hydrocarbon combustion to maintain the regenerator temperature to support the reactions in the reactor may be provided.

Although embodiments of the present invention and their advantages have been described in detail, it should be understood that various changes, substitutions and modifications may be made without departing from the spirit and scope of the embodiments defined by the claims. Furthermore, the scope of this application is not intended to be limited to the processes, machines, manufacture, materials of construction, means, methods and steps of the specific embodiments described herein. As will be readily appreciated by those skilled in the art from this disclosure, currently existing or later developed processes, machines, materials of construction, or means that perform substantially the same function or achieve substantially the same results as the corresponding embodiments described herein. , methods, or steps may be used. Accordingly, the claims are intended to include within their scope such processes, machines, manufactures, materials of construction, means, methods, or steps.

In the context of the present invention, at least the following 36 aspects are described. Aspect 1 relates to a hydropyrolysis process for producing higher yields of olefins and aromatics, the process comprising: (a) a first hydrocarbon under conditions sufficient to produce a spent catalyst and an intermediate stream comprising olefins and aromatics; contacting a first hydrocarbon feed stream comprising a cracking catalyst and a hydrogen source; and (b) contacting the spent catalyst and the intermediate stream with a coke precursor stream to produce a product stream comprising spent coking catalyst and additional olefins and aromatics. Aspect 2 relates to the hydropyrolysis process of Aspect 1, wherein the catalyst to feed (C/F) ratio in step (a) is greater than the C/F ratio in step (b). Aspect 3 relates to the hydropyrolysis process of aspect 1 or 2, wherein the weight percent of coke in the spent catalyst is lower than the weight percent of coke in the spent coking catalyst. Aspect 4 relates to the hydropyrolysis process of any of aspects 1-3, the process further comprising regenerating the spent coking catalyst. Aspect 5 relates to the hydropyrolysis process of aspect 4, wherein the regenerated catalyst is recycled to step (a). Aspect 6 relates to the hydrogen pyrolysis process of any one of aspects 1-5, wherein the hydrogen source is hydrogen (H ₂ ) gas, methane, ethane, ethylene, propane, propylene, butane, butenes, or any combination thereof. Aspect 7 relates to the hydrogen pyrolysis process of any one of aspects 1 to 6, wherein the contacting conditions of step (a) include a temperature of 500°C to 750°C. Aspect 8 relates to the hydrogen pyrolysis process of any one of aspects 1 to 6, wherein the contacting conditions of step (a) include a temperature of 700°C to 850°C. Aspect 9 relates to the hydropyrolysis process of any one of aspects 1 to 8, wherein the first hydrocarbon feed stream is naphtha, condensate, gas oil, C ₃ and C ₄ saturated gases, a cracked naphtha stream, C ₃ and a recycled crackable hydrocarbon stream comprising C ₄ saturated gas or any combination thereof. Aspect 10 relates to the hydropyrolysis process of any one of aspects 1 to 9, wherein the coke precursor stream is a cycle oil, coker stream, crude oil, slurry oil, carbon black oil, cracked distillate, cracked oil, vacuum residue or Including any combination. Aspect 11 relates to the hydropyrolysis process of any one of aspects 1 to 10, further comprising providing a second hydrocarbon feed stream comprising a second hydrocarbon to step (a), wherein the intermediate stream comprises the catalyst with the first hydrocarbon feedstream and the second hydrocarbon feedstream, wherein the average molecular weight of the second hydrocarbon feedstream is higher than the average molecular weight of the first hydrocarbon feedstream. Aspect 12 relates to the hydrocracking process of aspect 11, wherein the second hydrocarbon feed stream is crude oil, atmospheric residue, vacuum gas oil, unconverted oil from a hydrocracker, hydrowax, polyolefin oligomer, dissolved in a solvent or slurry plastics or polymers, plastics, partially depolymerized plastics, plastics pyrolysis oils, hydrogenated plastics pyrolysis oils, recycled naphtha and gas oil streams, naphtha, gas oils, vacuum gas oils and unconverted oils from hydrocracking of plastics. products or combinations thereof. Aspect 13 relates to the hydropyrolysis process of aspect 11 or 12, wherein the second hydrocarbon feed stream is contacted with the catalyst downstream relative to contacting the first hydrocarbon feed stream with the catalyst. Aspect 14 relates to the hydropyrolysis process of any one of aspects 11 to 13, the process further comprising providing a third hydrocarbon feed stream comprising a third hydrocarbon to step (a), wherein the intermediate stream is produced by contacting the catalyst with the first hydrocarbon feed stream, the second hydrocarbon feed stream, and the third hydrocarbon feed stream, wherein the average molecular weight of the third hydrocarbon stream is higher than the average molecular weight of the first hydrocarbon stream. Aspect 15 relates to the hydropyrolysis process of aspect 14, wherein the third hydrocarbon feed stream is crude oil, atmospheric residue, vacuum gas oil, unconverted oil in a hydrocracker, hydrowax, polyolefin oligomer, dissolved in a solvent or slurry polymerized polymers, plastics, partially depolymerized plastics, plastics pyrolysis oils, hydrogenated plastics pyrolysis oils, heavy recycled crackable hydrocarbon streams, gas oils, vacuum gas oils and unconverted oil products from hydrocracking of plastics, or any combination thereof. Aspect 16 relates to the hydropyrolysis process of aspect 14 or 15, wherein the third hydrocarbon feed stream is contacted with the catalyst downstream relative to contacting the second hydrocarbon feed stream with the catalyst. Aspect 17 relates to the hydrogen pyrolysis process of any one of aspects 1 to 16, wherein steps (a) and (b) are performed in a reactor, wherein the average hydrocarbon residence time in the reactor is from 100 milliseconds (ms) to 2 seconds. , preferably 100 ms to 1 second. Aspect 18 relates to the hydrogen pyrolysis process of aspect 17, wherein the source of hydrogen is provided to step (a) comprised in a lift stream, wherein the lift stream may further comprise steam. Aspect 19 relates to the hydrogen pyrolysis process of any of aspects 17 or 18, wherein the process further comprises supplying an oxygenate to one or more locations. Aspect 20 relates to the hydrogen pyrolysis process of aspect 19, the process further comprising controlling a local temperature of the reactor at the one or more locations where the oxygenate is supplied, the controlling step comprising: measuring the local temperature at the one or more locations supplied; and if the local temperature at the one or more locations is lower than the desired temperature at the one or more locations, increasing the oxygenate flow rate to the reactor or increasing the local temperature at the one or more locations to the one or more locations. and reducing the oxygenate flow rate to the reactor if it is above the desired temperature at the location. Aspect 21 relates to the hydropyrolysis process of any one of aspects 19 or 20, wherein the oxygenates are one or more oxygenate streams, a first hydrocarbon feedstream, a second hydrocarbon feedstream, or a third hydrocarbon feedstream, coke fed to the reactor included in the precursor stream, or any combination thereof. Aspect 22 relates to the hydrogen pyrolysis process of any of aspects 19-21, wherein the oxygenate is methanol. Aspect 23 relates to the hydrogen pyrolysis process of any of aspects 19 to 22, wherein the reactor includes one or more heaters and one or more sensors positioned on reactor walls along a length of the reactor, wherein the hydrogen pyrolysis process during The reactor temperature is controlled by the one or more sensors, the one or more heaters and/or the oxygenate flow rate to one or more locations in the reactor, the temperature at the inlet to the catalyst to the reactor and the temperature from the reactor. The difference between the temperatures at the outlet for spent catalyst is less than 200°C, preferably less than 150°C, more preferably less than 100°C. Aspect 24 relates to a system for producing olefins and aromatics, the system comprising a reactor comprising a cylindrical body configured to include a first reaction zone and a second reaction zone, wherein the second reaction zone comprises the second reaction zone. the reactor in fluid communication with the first reaction zone, wherein the first reaction zone and the second reaction zone are located along the length of the reactor; and one or more first heaters positioned on walls along the length of the reactor, wherein the reactor receives a first hydrocarbon feed stream, a cracking catalyst, and a source of hydrogen in the first reaction zone, the first hydrocarbon feed stream contacting the cracking catalyst and the hydrogen source to produce an intermediate stream comprising spent catalyst and olefins and aromatics, receiving a coke precursor feed, the spent catalyst and the intermediate stream in the second reaction zone; and contacting the spent catalyst, the intermediate stream and the coke precursor feed to produce a product stream comprising spent coking catalyst and additional olefins and aromatics. Aspect 25 relates to the system of aspect 24, wherein the reactor is configured to receive a second hydrocarbon feed stream from the first reaction zone downstream of the first hydrocarbon feed stream and the intermediate stream, and wherein the catalyst used is It is produced by contacting a catalyst with the first hydrocarbon feed stream and the second hydrocarbon feed stream. Aspect 26 relates to the system of aspect 25, wherein the reactor is configured to receive a third hydrocarbon feed stream from the first reaction zone downstream of the second hydrocarbon feed stream and the intermediate stream, wherein the catalyst used is It is produced by contacting a catalyst with the first hydrocarbon feed stream, the second hydrocarbon feed stream and the third hydrocarbon feed stream. Aspect 27 relates to the system of any of aspects 24-26, wherein the reactor further includes an insulating layer positioned on an outer surface of a first heater layer formed by the one or more first heaters. Aspect 28 relates to the system of aspect 27, wherein the reactor further includes at least one second heater positioned on an outer surface of the insulating layer. Aspect 29 relates to the system of any one of aspects 24-28, wherein the average internal diameter of the reactor in the first reaction zone is greater than the average internal diameter of the reactor in the second reaction zone. Aspect 30 relates to the system of any one of aspects 24-28, wherein the average internal diameter of the reactor in the first reaction zone is less than the average internal diameter of the reactor in the second reaction zone. Aspect 31 relates to the system of any one of aspects 24-30, wherein the reactor is a riser reactor or a downer reactor. Aspect 32 relates to the system of any one of aspects 24 to 31, wherein the system recovers light gas olefins, benzene, toluene, xylenes and ethyl benzene from the product stream and then processes the degradable hydrocarbons separated from the product stream. It further includes a second reactor configured to. Aspect 33 relates to the system of aspect 32, wherein the residence times in the reactor and the second reactor are independently from 100 ms to 1 second. Aspect 34 relates to the system of any one of aspects 24-33, wherein the reactor further comprises a plurality of nozzles arranged along the length of the reactor configured to introduce one or more oxygenates into the reactor. Aspect 35 relates to the system of any one of aspects 24-34, wherein the number of nozzles in the first reaction zone is greater than the number of nozzles in the second reaction zone. Aspect 36 relates to the system of any one of aspects 24-35, wherein the reactor receives a regeneration stream comprising the spent coking catalyst and oxygen (O ₂ ) from the reactor, and the spent coking catalyst and a regeneration unit configured to regenerate the decomposition catalyst by contacting with oxygen.

Examples

The present invention will be explained in more detail through specific examples. The following examples are provided for illustrative purposes only and do not limit the invention in any way. One skilled in the art will readily recognize various non-critical parameters that can be modified or modified to yield substantially the same results.

Example 1

Hydrogen pyrolysis of West Texas Blend crude oil boiling point cut (370 °C to 415 °C)

Hydrogen pyrolysis was performed on West Texas crude oil cuts (370° C. to 415° C.) in a laboratory reactor with a fluidizing stream containing 10 vol % H ₂ and 90 vol % N ₂ . The reactor was an in-situ fluidized-bed tubular reactor with a length of 783 mm and an inner diameter of 15 mm, housed in a split-zone three-zone tubular furnace with independent temperature control for each zone. The size of each heating zone was 9.3 inches (236.2 mm). The total heated length of the reactor placed inside the furnace was 591 mm. Reactor wall temperature was measured at the center of each zone and used to control the heating of each furnace zone. The reactor had a conical bottom and the reactor bed temperature was measured using a thermocouple housed inside a thermowell and placed inside the reactor at the top of the conical bottom. Additionally, the reactor wall temperature was measured at the bottom of the cone to ensure that the bottom of the reactor was hot. The reactor bottom was placed in the middle of the furnace bottom zone to minimize the effect of furnace end cap heat loss and to keep the reactor bottom wall temperature within 20 °C of the measured inner bed temperature difference. The catalyst used is a combination of the above proportions of FCC catalyst and ZSM-5 additive (67.5 wt% and 37.5 wt%, respectively). Conditions and product distributions are listed in Table 1, Runs #3, 4 and 5.

Example 2:

West Texas Boiling Point Cut (Pyrolysis of 370 to 415 ° C - Comparative Example

Example 2 was run under conditions similar to Example 1 except that the flow stream was 100% N ₂ ie no H ₂ in the flow stream. Conditions and product distributions are listed in Table 1 (Runs # 1 and 2).

The results of Example 1 (Table 1, Runs #3, 4 and 5) and Example 2 (Table 1, Runs #1 and 2) show that the presence of hydrogen in the reaction environment has a significant effect on product distribution and coke formation. show what Light gas olefins increased by at least 3% by weight and coke decreased by at least 1% by weight. This improved the light gas olefins per unit coke to 9 to 10 to 14 to 17 weight/weight, although the average cup mixing temperature was lower in Example 1 in two out of three cases compared to Example 2. Heavies formation is also reduced. The results indicate that, as in Example 1, the presence of hydrogen in the reaction environment causes less coke to be deposited on the surface of the catalyst and therefore maintains a relatively more activated catalyst. This in turn results in higher light gas olefins and less heavy formations.

Table 1: Conditions and product distribution for high severity pyrolysis (Example 2) and hydrogen pyrolysis (Example 1).

unit high severity pyrolysis hydrogen pyrolysis Perform# One 2 3 4 5 supplies West Texas Crude Oil 370-415℃ Kerosene Point Cut Fluid gas composition mol % 100% N ₂ 90% N ₂ : 10% H ₂ C/F Weight/ Weight 6.2 5.8 6.0 6.1 5.9 1 minute average cup mixing temperature

688 687 685.6 684.8 688 transference number ethylene weight % 12.1 11.8 12.4 12.7 14.9 propylene weight % 12.1 13.0 14.0 14.6 12.8 Butene weight % 8.7 9.2 9.8 9.6 9.1 weight % light gas olefins weight % 33.0 34.0 36.1 36.9 36.7 cokes weight % 3.7 3.3 2.5 2.2 2.2 Light gas olefins/unit coke Weight/ Weight 9.0 10.2 14.6 17.1 16.4 Gasoline (IBP-220℃) weight % 38.5 32.7 34.6 38.8 32.3 Diesel (220-370℃) weight % 5.2 8.5 5.7 4.4 3.9 Medium (370+℃) weight % 2.8 5.4 2.8 1.2 1.5

Example 3 Hydrogen Pyrolysis of West Texas Crude Oil Boiling Point (370° C. to 415° C.) Mixed with Varying Amounts of Methanol

Example 3 is West Texas crude oil in which the feed has weight percent ratios of 95/5 (Table 2, Experiment 6), 90/10 (Table 2, Experiment 6), and 85/15 (Table 2, Experiment 8), respectively. Similar conditions to Example 1 were carried out, except that the boiling point cut (370-415° C.) (WTB cut, 370-415° C.) was a mixture of methanol. Conditions and product distributions are listed in Table 2 as Experiments 6-8. The furnace set temperature in this case was the same as in Experiments 1-5 in Table 1, but the average cup mixing temperature in Table 2 for Experiments 6-8 was higher when methanol was used with the main feed. This is evidence that the decomposition of methanol is exothermic and generates localized heat, which increases the temperature. This local exotherm can advantageously be used in a commercial reactor to maintain a higher local temperature as desired, or to impose a temperature profile by controlling the rate of methanol addition along the length of the reactor. It can be clearly seen that Experiment 9 in Table 2 corresponds to pure methanolysis and results in a higher cup mixing temperature for the same furnace set temperature. The cup mixing temperature is the average temperature in the first minute after introduction of the feed into the laboratory reactor. This is the average temperature in the immediate vicinity (within 1 m) of the feed introduction point in a commercial reactor. Light gas olefins decreased when mixing with methanol. This is due to the dilution effect of co-feeding methanol with the feed. Gasoline yield increased because methanol was also decomposed. Co-feeding of methanol also reduces both coke and heavy formations. This may be due to better atomization of the feed and better contact between the feed and the catalyst due to the lighter oxygenate. As a result of the coke on the catalyst being lowered by this synergistic effect, in addition to maintaining activity by hydrogen in the fluidizing gas, the catalyst of hydrogen pyrolysis can also maintain activity by this effect.

Table 2: Conditions and product distribution for hydrogen pyrolysis in the presence of methanol (Example 3).

Perform# 5 6 7 8 9 supplies WTB cut, 370 to 415℃ 95 wt % WTB cut, 370-415° C. 5 wt % methanol 90 wt % WTB cut, 370-415° C. 10 wt % methanol 85 wt % WTB cut, 370-415° C. 15 wt % methanol 100% by weight
methanol Fluid gas composition mole% 90% N ₂ : 10% H ₂ C/F Weight/ Weight 5.9 6.0 6.1 5.9 6.0 1 minute average cup mixing temperature

688 687 690.2 690.2 702.4 transference number ethylene weight % 14.9 12.5 12.7 13.1 5.9 propylene weight % 12.8 13.0 12.4 12.2 4.8 Butene weight % 9.1 9.3 8.2 8.4 1.4 weight % light gas olefins weight % 36.7 34.9 33.4 33.7 12 cokes weight % 2.2 1.4 1.8 1.2 0.8 Light gas olefins/unit coke Weight/ Weight 16.4 25.3 18.3 28.3 14.4 Gasoline (IBP-220℃) weight % 32.3 36.4 34.7 36.5 Diesel (220-370℃) weight % 3.9 7.1 8.2 7.4 Medium (370+ ℃) weight % 1.5 1.6 1.7 1.7

Example 4 Hydrogen pyrolysis and high severity pyrolysis of plastic feed (comparative).

[0028] Hydrogen pyrolysis and high severity pyrolysis of plastic feed were performed. For a constant coke yield of 5% by weight, this is understood as comparing the advantages of Table 3 below. Based on forecasts and laboratory data, it can be deduced that hydropyrolysis can increase yields of light olefins, benzene, toluene, xylenes and ethylbenzene by up to 5% by weight. 8 demonstrates the advantages of hydrogen pyrolysis over high severity pyrolysis for plastic feeds.

Table 3: Prediction of yield advantage from hydrogen pyrolysis at constant coke yield based on laboratory yields of high value chemicals per unit coke

Experiment 1 comparison experiment Regenerator coke burning capacity, % by weight of feed 5 5 Light olefins/coke (weight/weight) 6.4 5.8 C ₆ -C ₈ aromatics/cokes (weight/weight) 5.1 4.2 Light olefin yield, wt % 32 29 C ₆ -C ₈ Aromatics Yield, % by weight 25.5 20.5

Claims (20)

A hydrogen pyrolysis process for producing olefins and aromatics, said process comprising:
(a) contacting a first hydrocarbon feed stream comprising a first hydrocarbon with a cracking catalyst and a source of hydrogen under conditions sufficient to produce an intermediate stream comprising spent catalyst and olefins and aromatics; and
(b) contacting the spent catalyst and the intermediate stream with a coke precursor stream to produce a product stream comprising spent coking catalyst and additional olefins and aromatics;
Hydrogen pyrolysis process. According to claim 1,
The catalyst to feed (C / F) ratio in step (a) is greater than the C / F ratio in step (b),
Hydrogen pyrolysis process. According to claim 1 or 2,
Wherein the weight percent of coke in the spent catalyst is lower than the weight percent of coke in the spent coking catalyst,
Hydrogen pyrolysis process. According to claim 1 or 2,
The process further comprises the step of regenerating the spent coking catalyst,
Hydrogen pyrolysis process. According to claim 4,
Wherein the regenerated catalyst is recycled to the step (a),
Hydrogen pyrolysis process. According to claim 1 or 2,
The hydrogen source is hydrogen (H ₂ ) gas, methane, ethane, ethylene, propane, propylene, butane, butene or any combination thereof,
Hydrogen pyrolysis process. According to claim 1 or 2,
The contacting conditions in step (a) include a temperature of 500 ° C to 750 ° C,
Hydrogen pyrolysis process. According to claim 1 or 2,
The contacting conditions in step (a) include a temperature of 700 ° C to 850 ° C,
Hydrogen pyrolysis process. According to claim 1 or 2,
The 1 hydrocarbon feed stream is a recycled crackable hydrocarbon stream containing naphtha, condensate, gas oil, C ₃ and C ₄ saturated gases, a cracked naphtha stream, C ₃ and C ₄ saturated gases, or any combination thereof. which includes,
Hydrogen pyrolysis process. According to claim 1 or 2,
Wherein the coke precursor stream comprises cycle oil, coker stream, crude oil, slurry oil, carbon black oil, cracked distillate, cracked oil, vacuum residue or any combination thereof.
Hydrogen pyrolysis process. According to claim 1 or 2,
The process further comprises providing a second hydrocarbon feed stream comprising a second hydrocarbon to step (a);
The intermediate stream is produced by contacting the catalyst with the first hydrocarbon feedstream and the second hydrocarbon feedstream, wherein the average molecular weight of the second hydrocarbon feedstream is higher than the average molecular weight of the first hydrocarbon feedstream. ,
Hydrogen pyrolysis process. According to claim 11,
The second hydrocarbon feed stream comprises crude oil, atmospheric residue, vacuum gas oil, unconverted oil from hydrocracker, hydrowax, polyolefin oligomers, solvent-dissolved or slurried plastics or polymers, plastics, partially depolymerized plastics, plastic pyrolysis oil, hydrogenated plastic pyrolysis oil, recycled naphtha and gas oil streams, naphtha, gas oil, vacuum gas oil and unconverted oil products from hydrocracking of plastics, or any combination thereof;
Hydrogen pyrolysis process. According to claim 11 or 12,
wherein the second hydrocarbon feedstream is contacted with the catalyst downstream relative to the contacting of the first hydrocarbon feedstream with the catalyst.
Hydrogen pyrolysis process. According to claim 11 or 12,
The process further comprises providing a third hydrocarbon feed stream comprising a third hydrocarbon to step (a);
The intermediate stream is produced by contacting the catalyst with the first hydrocarbon feed stream, the second hydrocarbon feed stream, and the third hydrocarbon feed stream, wherein the average molecular weight of the third hydrocarbon stream is the average molecular weight of the first hydrocarbon stream. which is higher,
Hydrogen pyrolysis process. According to claim 14,
The third hydrocarbon feed stream is crude oil, atmospheric residue, vacuum gas oil, unconverted oil in the hydrocracker, hydrowax, polyolefin oligomers, solvent-dissolved or slurried polymers, plastics, partially depolymerized plastics, plastic pyrolysis oil, hydrogenated plastics pyrolysis oil, heavy recycled crackable hydrocarbon streams, gas oils, vacuum gas oils and unconverted oil products from the hydrocracking of plastics, or any combination thereof;
Hydrogen pyrolysis process. According to claim 14,
wherein the third hydrocarbon feedstream is contacted with the catalyst downstream relative to the contacting of the second hydrocarbon feedstream with the catalyst.
Hydrogen pyrolysis process. According to claim 1 or 2,
The steps (a) and (b) are carried out in a reactor, and the average hydrocarbon residence time in the reactor is 100 ms to 2 seconds, preferably 100 ms to 1 second,
Hydrogen pyrolysis process. According to claim 17,
Wherein the hydrogen source is provided to the step (a) included in the lift stream, the lift stream may further include steam,
Hydrogen pyrolysis process. The method of claim 17 or 18,
The process further comprises the step of supplying an oxygenate at one or more locations in the reactor,
Hydrogen pyrolysis process. According to claim 19,
The process further includes controlling a local temperature of the reactor at the one or more locations where the oxygenate is supplied, wherein the controlling step comprises:
measuring the local temperature at the one or more locations where the oxygenate is supplied; and
If the local temperature at the one or more locations is lower than the desired temperature at the one or more locations, the oxygenate flow rate to the reactor is increased or the local temperature at the one or more locations is lower than the desired temperature at the one or more locations. Reducing the flow rate of the oxygenate to the reactor when it is higher than the desired temperature at
Hydrogen pyrolysis process.