System and method for upgrading crude oil and converting it into petrochemical products by steam cracking

Abstract

A method for upgrading a hydrocarbon feed such as crude oil or other heavy oils may include hydrotreating the hydrocarbon feed in a hydrotreating unit to produce a hydrotreating effluent containing asphaltenes, coke precursors, or both. The method further includes hydrocracking the hydrotreating effluent in a hydrocracking unit to produce a hydrocracking effluent, adsorbing at least a portion of the asphaltenes, coke precursors, or both from the hydrotreating effluent, the hydrocracking effluent, or both, separating the hydrocracking effluent into at least an upgraded low-distillate effluent and a high-distillate effluent in a hydrocracking effluent separation system, and steam cracking the upgraded low-distillate effluent to produce olefins, aromatic compounds, or a combination of these. The method may also include recycling the high-distillate effluent back to the hydrotreating unit and hydrocracking the intermediate distillate effluent from the hydrocracking effluent separation system. A system for performing the method is also disclosed.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to U.S. patent application serial number 16 / 720,240, filed on December 19, 2019, entitled “Systems and Processes for Upgrading and Converting Crude Oil to Petrochemicals Through Steam Cracking,” the entire contents of which are incorporated by reference into this disclosure. Background Art Technical Field

[0004] The present disclosure relates to systems and methods for processing petroleum-based materials, and in particular, systems and methods for upgrading and converting crude oil into petrochemical products and intermediates through hydroprocessing and steam cracking. Technical Background

[0006] Petrochemical feedstocks such as crude oil can be converted into chemical products and intermediates, such as olefins and aromatic compounds as basic intermediates for most of petrochemicals.For many integrated refineries, the global demand for light olefins and aromatic compounds continues to grow and remains a major challenge.Specifically, the production of some valuable light olefins (such as ethylene, propylene and butylene) has caused increasing concern, because pure olefin streams are considered to the basis of polymer synthesis.In addition, aromatic compounds such as benzene, toluene, ethylbenzene and xylene are valuable intermediates for synthesizing polymers and other organic compounds and for fuel additives.

[0007] Olefins and aromatics can be produced by hydrocarbon feed, such as natural gas, naphtha or atmospheric gas oil (AGO) stream cracking. In order to obtain higher yield of olefins and aromatics, suitable raw materials for steam cracking process are usually rich in paraffinic hydrocarbons with lower aromatic concentration, which can reduce the formation of undesirable by-products and the formation of coke during steam cracking. Crude oil and other heavy oils are increasingly regarded as the raw materials of steam cracking process. Although crude oil and other heavy oils may be a potential raw material, the concentration of metals, nitrogen, sulfur, asphaltenes, polycyclic aromatic compounds and other organic macromolecules in crude oil and other heavy oils can cause the pollution of the effluent stream from steam cracking process and the generation of coke, and coke can be accumulated on downstream equipment. When using crude oil and other heavy oils as the raw materials of steam cracking, up to 30% by weight of crude oil comprising a constituent having a boiling point temperature higher than 540 degrees Celsius must be discarded and removed from the system to reduce the formation of coke and ensure the smooth operation of the steam cracking system. Summary of the invention

[0008] Therefore, there is a continuing need for systems and methods for increasing the yield of olefins and aromatic compounds from steam cracking processes when crude oil or other heavy oils are used as hydrocarbon feeds. The systems and methods of the present disclosure can provide increased yields of olefins and aromatic compounds from steam cracking by subjecting the crude oil or heavy oil to hydroprocessing to remove trace impurities and upgrading the crude oil or heavy oil to produce an upgraded low-distillation effluent having an increased concentration of paraffin compounds. The systems and methods of the present disclosure can increase the yield of olefins and aromatic compounds from steam cracking of crude oil and other heavy oils by enabling a greater portion of the crude oil to be converted into steam-crackable constituents, such as paraffins and other hydrocarbons having a distillation temperature less than or equal to 180°C, for feeding to the steam cracking process. Therefore, a greater portion of constituents having a distillation temperature greater than 540°C can be converted into olefins and aromatic compounds instead of being discarded and removed prior to steam cracking.

[0009] Hydroprocessing may include hydrotreating crude oil or heavy oil with a hydroprocessing catalyst in a hydroprocessing system to remove impurities such as sulfur, nitrogen and metals, and to dearomatize polycyclic aromatic compounds and asphaltenes. Hydroprocessing may also include hydrocracking the hydroprocessing effluent in the presence of a hydrocracking catalyst in a hydrocracking unit to convert at least a portion of the remaining aromatic compounds and polycyclic aromatic compounds in the hydroprocessing effluent into paraffin compounds. The resulting hydrocracking effluent may have a concentration of hydrocarbons with a boiling point temperature of less than or equal to 180° C. with an increased concentration compared to the hydroprocessing effluent. The hydrocracking effluent is then separated in a hydrocracking effluent separation system to produce at least an upgraded low boiling point effluent and a high boiling point effluent. The upgraded low boiling point effluent can be transferred to a steam cracking system as a feed for steam cracking. The high-distillation point effluent can be passed back to the hydroprocessing system, such as back to the hydroprocessing unit, to further convert the high-distillation point components into hydrocarbons with a distillation temperature of less than or equal to 180° C., thereby further increasing the yield of olefins and aromatic compounds from the steam cracking system. The hydrocracking effluent separation system can further separate the medium-distillation point effluent, which can be further hydrocracked in the secondary hydrocracking unit.

[0010] During the hydroprocessing of crude oil or heavy oil, severe conditions may decompose the oil fractions that stabilize and dissolve coke precursors (such as asphaltene compounds). Destroying the stable system of asphaltene and other coke precursors may cause asphaltene and other coke precursors to precipitate from the hydroprocessing effluent. Precipitated asphaltene and other coke precursors may be deposited on the downstream hydrocracking catalyst, causing the deactivation of the hydrocracking catalyst. The deactivation of the hydrocracking catalyst caused by the deposition of asphaltene and coke on the hydrocracking catalyst can reduce the yield of paraffin compounds from the hydrocracking process and cause problems with the catalyst life and the smooth operation of the hydrocracking process. Even at low concentrations, such as less than 0.5 weight percent, asphaltene and other coke precursors may also cause the hydrocracking catalyst to be significantly deactivated.

[0011] In order to reduce the deactivation of the hydrocracking catalyst and the deposition of asphaltenes and coke on the process equipment downstream of the hydroprocessing unit, the system of the present disclosure may include an adsorption unit that is operable to remove at least a portion of the asphaltenes and other coke precursors from the system. The method of the present disclosure may include passing one or more process effluents, such as hydrotreating effluents, hydrocracking effluents, or other streams, through an adsorption unit to remove asphaltene compounds and other coke precursors. The system and method of the present disclosure may increase the yield of olefins and aromatic compounds from steam cracked crude oil or other heavy oils by removing impurities from the crude oil or heavy oil and converting a larger portion of the hydrocarbons in the crude oil or heavy oil into hydrocarbons having a distillation temperature of less than or equal to 180°C. In addition, the system and method of the present disclosure may improve the efficient operation of the hydrocracking unit and the steam cracking system by removing asphaltenes and other coke precursors from the process effluent stream.

[0012] According to at least one aspect of the present disclosure, a method for upgrading a hydrocarbon feed may include hydrotreating the hydrocarbon feed to produce a hydrotreating effluent, wherein the hydrotreating effluent may contain asphaltenes, coke precursors, or both. The method may also include hydrocracking at least a portion of the hydrotreating effluent to produce a hydrocracking effluent and adsorbing at least a portion of the asphaltenes, coke precursors, or both from the hydrotreating effluent, the hydrocracking effluent, or both. The method may also include separating the hydrocracking effluent into at least an upgraded low-distillation effluent and a high-distillation effluent, and steam cracking the upgraded low-distillation effluent to produce olefins, aromatic compounds, or a combination of these.

[0013] According to another aspect of the present disclosure, a method for upgrading a hydrocarbon feed may include contacting the hydrocarbon feed with at least one hydrotreating catalyst in the presence of hydrogen in at least one hydrotreating zone. The hydrocarbon feed may include whole crude oil or desalted whole crude oil, and the contact may remove at least one of metals, sulfur compounds, nitrogen compounds, or a combination of these to produce a hydrotreating effluent. The method may also include contacting the hydrotreating effluent with a hydrocracking catalyst in the presence of hydrogen, wherein the contact with the hydrocracking catalyst may cause at least a portion of the hydrocarbons in the hydrotreating effluent to undergo a hydrocracking reaction to produce a hydrocracking effluent. The method may also include contacting at least a portion of the hydrotreating effluent or at least a portion of the hydrocracking effluent with an adsorbent in an adsorption unit. The adsorbent may remove at least a portion of asphaltene, coke precursors, or both from the portion of the hydrotreating effluent or the portion of the hydrocracking effluent. The method may also include passing the hydrocracking effluent to a hydrocracking effluent separation system operable to separate the hydrocracking effluent into at least an upgraded low-distillate effluent and a high-distillate effluent, and contacting the upgraded low-distillate effluent with steam maintained at a steam cracking temperature in a steam cracking zone. Contacting the upgraded low-distillate effluent with steam at a steam cracking temperature may cause at least a portion of the upgraded low-distillate effluent to undergo thermal cracking to produce a steam cracking effluent comprising olefins, aromatic compounds, or both.

[0014] According to another aspect of the present disclosure, a system for processing crude oil may include a hydroprocessing unit comprising at least one hydroprocessing catalyst. The hydroprocessing unit is operable to contact the crude oil with the at least one hydroprocessing catalyst. Contact with the hydroprocessing catalyst can upgrade the crude oil to a hydroprocessing effluent having a reduced concentration of at least one of nitrogen, sulfur, metals, aromatic compounds, or these combinations. The system may also include a hydrocracking unit disposed downstream of the hydroprocessing unit and comprising a hydrocracking catalyst. The hydrocracking unit is operable to contact at least a portion of the hydroprocessing effluent with the hydrocracking catalyst under conditions sufficient to convert at least a portion of the hydroprocessing effluent to produce a hydrocracking effluent comprising hydrocarbons having a boiling point temperature less than or equal to 180°C. The system may also include an adsorption unit downstream of the hydroprocessing unit or the hydrocracking unit. The adsorption unit is operable to contact the hydroprocessing effluent or the hydrocracking effluent with an adsorbent capable of adsorbing asphaltenes, coke precursors, or both from the hydroprocessing effluent or the hydrocracking effluent; the system may also include a hydrocracking effluent separation system downstream of the hydrocracking unit. The hydrocracking effluent separation system is operable to separate at least a portion of the hydrocracking effluent into at least an upgraded low-distillation effluent and a high-distillation effluent. The system may also include a steam cracking system downstream of the hydrocracking effluent separation system. The steam cracking system is operable to convert at least a portion of the upgraded low-distillation effluent to produce olefins, aromatics, or both.

[0015] Additional features and advantages of the techniques described in the present disclosure will be set forth in the following detailed description, and will be apparent to those skilled in the art in part from the description, or may be learned by practicing the techniques described in the present disclosure (including the following detailed description, claims, and accompanying drawings). BRIEF DESCRIPTION OF THE DRAWINGS

[0016] The following detailed description of certain embodiments of the present disclosure may be best understood when taken in conjunction with the following drawings, in which like reference numerals are used to indicate like structures and in which:

[0017] Figure 1 According to one or more embodiments shown and described in this disclosure, a generalized flow diagram of a system for upgrading heavy oil to olefins, aromatics, or both is schematically depicted;

[0018] Figure 2 According to one or more embodiments shown and described in the present disclosure, a schematic diagram is shown. Figure 1 A generalized flow diagram of a hydrocracking effluent separation system of a system;

[0019] Figure 3According to one or more embodiments shown and described in the present disclosure, a schematic diagram is depicted. Figure 1 A generalized flow diagram of a steam cracking system of the system;

[0020] Figure 4 According to one or more embodiments shown and described in this disclosure, a generalized flow diagram of another embodiment of a system for upgrading heavy oil to olefins, aromatics, or both is schematically depicted;

[0021] Figure 5 A generalized flow diagram of yet another embodiment of a system for upgrading heavy oil to olefins, aromatics, or both is schematically depicted, in accordance with one or more embodiments shown and described in the present disclosure; and

[0022] Figure 6

[0046] According to one or more embodiments shown and described in the present disclosure, a generalized flow diagram of yet another system for upgrading heavy oil to olefins, aromatics, or both is schematically depicted.

[0023] For description Figure 1-6 For purposes of simplified schematic illustration and description, numerous valves, temperature sensors, electronic controllers, etc., which may be employed in certain chemical processing operations and are well known to those of ordinary skill in the art, are not included. Further, accompanying components that are often included in chemical processing operations, such as, for example, gas sources, heat exchangers, buffer tanks, or other related systems, are not depicted. It is well known that such components are included within the spirit and scope of the disclosed embodiments. However, operating components such as those described in the present disclosure may be added to the embodiments described in the present disclosure.

[0024] It should be noted that the arrows in the accompanying drawings refer to process streams. However, arrows can equivalently refer to a delivery line that can be used to transport process streams between two or more system components. In addition, the arrows connected to the system components define the inlet or outlet in each given system component. The direction of the arrows generally corresponds to the main direction of movement of the material of the stream contained in the physical delivery line represented by the arrows. In addition, the arrows that do not connect two or more system components represent the product streams leaving the depicted system or the system inlet streams entering the depicted system. The product stream can be further processed in the accompanying chemical processing system, or it can be commercialized as a final product. The system inlet stream can be a stream transported from the accompanying chemical processing system, or it can be an unprocessed raw material stream. Some arrows can represent recycle streams, which are effluent streams of the system components that are recycled back to the system. However, it should be understood that in some embodiments, any representative recycle stream can be replaced by a system inlet stream of the same material, and a portion of the recycle stream can leave the system as a system product.

[0025] In addition, arrows in the accompanying drawings may schematically depict process steps that transport a stream from one system component to another system component. For example, an arrow pointing from one system component to another system component may represent "transferring" a system component effluent to another system component, which may include: the contents of a process stream "leaving" or being "taken out" of one system component and the contents of a product stream "introducing" into another system component.

[0026] It should be understood that when two or more lines are Figure 1-6 Two or more process streams are "mixed" or "combined" when they intersect in a schematic flow diagram of. Mixing or combining can also include mixing by introducing the two streams directly into a similar reactor, separation device, or other system component. For example, it should be understood that when two streams are depicted as being combined directly before entering a separation unit or reactor, in some embodiments, the streams can equivalently be introduced into the separation unit or reactor and mixed in the reactor.

[0027] Reference will now be made in more detail to various embodiments, some of which are illustrated in the accompanying drawings. Wherever possible, the same reference numerals will be used throughout the drawings to refer to the same or like parts. DETAILED DESCRIPTION

[0028] For example, the present disclosure relates to systems and methods for upgrading heavy oils, such as crude oil, to produce more valuable chemical intermediates, such as olefins and aromatic compounds. Figure 1 , schematically depicts one embodiment of a system 100 for upgrading a hydrocarbon feed 102 comprising crude oil or other heavy oil. The system 100 includes: a hydroprocessing unit 110, which includes at least one hydroprocessing catalyst and is operable to contact the crude oil or other heavy oil with the at least one hydroprocessing catalyst; a hydrocracking unit 130, which is disposed downstream of the hydroprocessing unit 110 and includes a hydrocracking catalyst; and an adsorption unit 120, which is downstream of the hydroprocessing unit 110 or the hydrocracking unit 130 and is operable to contact the hydroprocessing effluent 112 or the hydrocracking effluent 134 with an adsorbent capable of adsorbing asphaltenes, coke precursors, or both. The system 100 further includes a hydrocracking effluent separation system 140 downstream of the hydrocracking unit 130 and a steam cracking system 160 downstream of the hydrocracking effluent separation system 140. The system 100 may also include a high effluent recycle 149 operable to transfer the high effluent 148 from the hydrocracking effluent separation system 140 back to the hydroprocessing unit 110. Figure 4, the system 100 may also include a secondary hydrocracking unit 190, which is operable to contact the middle distillate effluent 146 from the hydrocracking effluent separation system 140 with a secondary hydrocracking catalyst. The system 100 is operable to upgrade hydrocarbons in crude oil or other heavy oil into an upgraded low-distillate effluent 144 containing hydrocarbons having a distillation temperature below 180° C., and then steam cracking the upgraded low-distillate effluent 144 to produce olefins, aromatic compounds, or both. The system 100 may also include transferring the pyrolysis oil 168 from the steam cracking system 160 back to the hydrocracking effluent separation system 140 to further convert the constituent components of the crude oil or heavy oil into the upgraded low-distillate effluent 144.

[0029] Reference again Figure 1 , a method for upgrading a hydrocarbon feed 102, such as crude oil or other heavy oil, includes hydrotreating the hydrocarbon feed 102 to produce a hydroprocessing effluent 112, wherein the hydroprocessing effluent 112 may include asphaltenes, coke precursors, or both. The method further includes hydrocracking at least a portion of the hydroprocessing effluent 112 to produce a hydrocracked effluent 134 and adsorbing at least a portion of the asphaltenes, coke precursors, or both from the hydroprocessing effluent 112, the hydrocracking effluent 134, or both. The method further includes separating the hydrocracking effluent 134 into at least an upgraded low-distillation effluent 144 and a high-distillation effluent 148, and steam cracking the upgraded low-distillation effluent 144 to produce olefins, aromatic compounds, or a combination of these. The upgraded low-distillation effluent 144 may include hydrocarbons having a distillation temperature less than or equal to 180°C. The method may also include recycling the high-distillate effluent 148 to the hydrotreating process and hydrotreating the high-distillate effluent 148. The method may also include hydrocracking the middle distillate effluent 146 separated from the hydrocracking effluent 134. The method may also include passing the pyrolysis oil 168 from the steam cracking process back into the system to further convert the hydrocarbons into the upgraded low-distillate effluent 144.

[0030] The system and method of the present disclosure can enable crude oil and heavy oil to be used as hydrocarbon feed to produce olefins and aromatic compounds by steam cracking. The system and method of the present disclosure can also enable crude oil and other heavy oils to be directly introduced into the process without the need to build and operate a high upstream separation process, such as a fractionating tower. The system and method of the present disclosure can reduce the deactivation of the hydrocracking catalyst by removing asphaltenes and other coke precursors from the system, thereby improving the operation of the system. The system and method of the present disclosure can also increase the conversion of hydrocarbons in crude oil or other heavy oils into upgraded low-distillation effluents, which can then be used as feeds for steam cracking processes. Compared with other steam cracking processes, this can result in an increase in the yield of olefins, aromatic compounds, or both from crude oil or other heavy oils, as well as other features.

[0031] As used in the present disclosure, "reactor" refers to any vessel, container, etc. in which one or more chemical reactions can occur between one or more reactants, optionally in the presence of one or more catalysts. For example, the reactor can include a tank or a tubular reactor configured to be used as a batch reactor, a continuous stirred tank reactor (CSTR), or a plug flow reactor. Example reactors include packed bed reactors such as fixed bed reactors and fluidized bed reactors. One or more "reaction zones" can be set in the reactor. As used in the present disclosure, a "reaction zone" refers to an area in the reactor where a specific reaction occurs. For example, a packed bed reactor with multiple catalyst beds can have multiple reaction zones, wherein each reaction zone is defined by the area of ​​each catalyst bed.

[0032] As used in the present disclosure, "separation unit" refers to any separation unit that at least partially separates one or more chemical substances in a mixture from each other. For example, a separation unit can selectively separate different chemical substances from each other to form one or more chemical fractions. Examples of separation units include, but are not limited to, distillation towers, fractionators, flash drums, separation drums, separation tanks, centrifuges, filtration units, collectors, scrubbers, expansion devices, membranes, solvent extraction units, high-pressure separators, low-pressure separators, etc. It should be understood that the separation process described in the present disclosure may not completely separate all consistent chemical substances from all other chemical components. It should be understood that the separation process described in the present disclosure "at least partially" separates different chemical components from each other, and even if it is not explicitly stated, it should be understood that separation may also include only partial separation. As used in the present disclosure, one or more chemical components can be "separated" from a process stream to form a new process stream. Typically, a process stream can enter a separation unit and be divided or separated into two or more process streams with a desired composition.

[0033] As used in the present disclosure, the term "fractionation" may refer to a process of separating one or more components in a composition, wherein the components separate from each other during a phase change based on differences in the properties of each of the components. For example, as used in the present disclosure, "distillation" refers to separating the components of a liquid composition based on differences in the boiling point temperatures of the components of the composition.

[0034] Further, in some separation processes, a "low-distillation-point effluent" and a "high-distillation-point effluent" can leave the separation unit independently. Typically, the distillation point temperature of the low-distillation-point effluent is lower than that of the high-distillation-point effluent. Some separation systems can produce a "medium-distillation-point effluent", which may include components having a distillation point temperature between the distillation point temperatures of the low-distillation-point effluent and the high-distillation-point effluent. The medium-distillation-point effluent may be referred to as an intermediate distillate. Some separation systems are capable of operating to produce multiple streams, each having a different distillation point range. It should also be understood that where only one separation unit is depicted or described in the accompanying drawings, two or more separation units may be used to perform the same or substantially the same separation. For example, where a distillation tower having multiple outlets is described, it is contemplated that several separators arranged in series can equally separate the feed stream, and such embodiments are also within the scope of the presently described embodiments.

[0035] As used in this disclosure, the terms "upstream" and "downstream" may refer to the relative positioning of a unit operation with respect to the direction of flow of a process stream. If a process stream flowing through a system encounters a first unit operation before encountering a second unit operation, then a first unit operation of a system may be considered "upstream" of a second unit operation. Similarly, if a process stream flowing through a system encounters a first unit operation before encountering a second unit operation, then the second unit operation may be considered "downstream" of the first unit operation.

[0036] As used in this disclosure, transferring a stream or effluent "directly" from one unit to another unit may refer to transferring a stream or effluent from a first unit to a second unit without transferring the stream or effluent through an intermediate reaction system or a separation system that substantially changes the composition of the stream or effluent. Heat transfer devices, such as heat exchangers, preheaters, coolers, condensers, or other heat transfer equipment, and pressure devices, such as pumps, pressure regulators, compressors, or other pressure devices are not considered to be intermediate systems that change the composition of a stream or effluent. It is also not considered that combining two streams or effluents together includes an intermediate system that changes the composition of one or both of the combined streams or effluents.

[0037] As used in this disclosure, the term "end boiling point" or "EBP" of a composition may refer to the temperature at which the highest boiling point temperature component of the composition transitions from a liquid phase to a vapor phase.

[0038] As used in the present disclosure, the term "effluent" may refer to a stream that is transferred from a reactor, a reaction zone, or a separation unit after a particular reaction or separation. Typically, the composition of the effluent is different from the stream that enters the separation unit, the reactor, or the reaction zone. It should be understood that when the effluent is transferred to another system unit, only a portion of the system stream may be transferred. For example, a slipstream may carry away some of the effluent, which means that only a portion of the effluent may enter a downstream system unit. The term "reaction effluent" may be more specifically used to refer to a stream that is transferred from a reactor or a reaction zone.

[0039] As used in this disclosure, "catalyst" refers to any substance that increases the rate of a particular chemical reaction. The catalysts described in this disclosure can be used to promote various reactions such as, but not limited to, hydrodemetallization, hydrodesulfurization, hydrodenitrogenation, hydrodearomatization, hydrocracking, cracking, aromatics cracking, or combinations thereof.

[0040] As used in this disclosure, "cracking" generally refers to a chemical reaction in which a molecule having carbon-carbon bonds is broken down into more than one molecule by the breaking of one or more carbon-carbon bonds; a compound containing a cyclic moiety, such as an aromatic compound, is converted into a compound that does not contain a cyclic moiety; or a molecule having a carbon-carbon double bond is reduced to a carbon-carbon single bond. Some catalysts may have multiple forms of catalytic activity, and invoking the catalyst by one particular function does not render the catalyst inactive for other functions. As used throughout this disclosure, "hydrocracking" may refer to the catalytic cracking of hydrocarbons in the presence of hydrogen.

[0041] As used throughout this disclosure, the term "a butene" or "butenes" refers to one or more than one of 1-butene, trans-2-butene, cis-2-butene, isobutene, or a mixture of these isomers. As used throughout this disclosure, the term "n-butene" may refer to one or more than one of 1-butene, trans-2-butene, cis-2-butene, or a mixture of these isomers, and does not include isobutene. As used throughout this disclosure, the term "2-butene" may refer to trans-2-butene, cis-2-butene, or a mixture of these two isomers.

[0042] As used throughout this disclosure, the term "xylene" when used without specifying the isomer (such as the prefix p-, m- or o-) (or the letters p, m and o, respectively) may refer to one or more of m-xylene, o-xylene, p-xylene, and mixtures of these xylene isomers.

[0043] As used throughout this disclosure, the term "crude oil" or "whole crude oil" may refer to crude oil received directly from an oil field or from a desalting unit, without separating any fractions by distillation.

[0044] It should be understood that, as described in the present disclosure, the reaction promoted by the catalyst can remove chemical constituents, such as only a portion of the chemical constituents, from the process stream. For example, a hydrodemetallization (HDM) catalyst can be present in an amount sufficient to promote the reaction of removing a portion of one or more metals from the process stream. A hydrodenitrification (HDN) catalyst can be present in an amount sufficient to promote the reaction of a portion of the nitrogen present in the process stream. A hydrodesulfurization (HDS) catalyst can be present in an amount sufficient to promote the reaction of a portion of the sulfur present in the process stream. A hydrodearomatization (HDA) catalyst can be present in an amount sufficient to promote the reaction of converting aromatic compounds into naphthalene, paraffin compounds, or both. A hydrocracking catalyst can be present in an amount sufficient to promote the reaction of converting aromatic compounds that are difficult to convert in a steam cracking system into naphthalene, paraffin compounds, or both that are more easily converted in a steam cracking system. It should be understood that throughout the present disclosure, when a specific catalyst is referred to as having a specific function, the specific catalyst may not be functionally limited to the removal, conversion, or cracking of a specific chemical component or portion. For example, a catalyst identified in this disclosure as a HDN catalyst may additionally provide hydrodearomatization functionality, hydrodesulfurization functionality, or both.

[0045] It should be further understood that a stream can be named according to a component of the stream, and the component of the named stream can be the major component of the stream (e.g., comprising 50 wt%, 70 wt%, 90 wt%, 95 wt%, 99 wt%, 99.5 wt%, or even 99.9 wt% to 100 wt% of the content of the stream). It should also be understood that when a stream comprising the component is disclosed as passing from the system component to another system component, the component of the stream is disclosed as passing from one system component to another system component. For example, a "hydrogen gas stream" disclosed as passing to a first system component or from a first system component to a second system component should be understood to equivalently disclose "hydrogen gas" passing to the first system component or from a first system component to a second system component.

[0046] refer to Figure 1 , schematically depicts a system 100 of the present disclosure for converting a hydrocarbon feed 102 into olefins, aromatic compounds, or both by hydroprocessing and steam cracking. The system 100 may include a hydroprocessing unit 110, a hydrocracking unit 130 downstream of the hydroprocessing unit 110, a hydrocracking effluent separation system 140 downstream of the hydrocracking unit 130, and a steam cracking system 160 downstream of the hydrocracking effluent separation system 140. The system 100 may also include an adsorption unit 120 disposed downstream of the hydroprocessing unit 110. Reference Figure 4The system 100 may further include a secondary hydrocracking unit 190 operable to convert at least a portion of the middle distillate effluent 146 from the hydrocracking effluent separation system 140 into additional hydrocarbons having a distillation temperature less than or equal to 180°C.

[0047] Reference again Figure 1 , the hydrocarbon feed 102 may include one or more heavy oils, such as, but not limited to, crude oil, vacuum residue, tar sands, asphalt, atmospheric residue, vacuum gas oil, other heavy oil streams, or combinations thereof. It should be understood that, as used in the present disclosure, "heavy oil" may refer to raw hydrocarbons (such as crude oil) that have not been previously processed by distillation, or may refer to hydrocarbons that have been processed to a certain extent before being introduced into the system 100 as hydrocarbon feed 102. The hydrocarbon feed 102 may have a density less than or equal to 0.86 g / ml. The hydrocarbon feed 102 may have an end boiling point (EBP) less than 720°C. The hydrocarbon feed 102 may have a nitrogen concentration less than or equal to 900 parts per million by weight (ppmw).

[0048] In one or more embodiments, the hydrocarbon feed 102 can be crude oil. The crude oil can have an American Petroleum Institute (API) gravity of 25 to 50 degrees. For example, the hydrocarbon feed 102 can include Arabian light crude oil. Example properties of exemplary grades of Arabian light crude oil are listed in Table 1.

[0049] Table 1 - Examples of Arab Light Export Raw Materials

[0050]

[0051] When hydrocarbon feed 102 comprises crude oil, the crude oil may be whole crude oil or may be crude oil that has undergone some processing such as desalting, solid separation, washing. For example, hydrocarbon feed 102 may be a desalted crude oil that has undergone a desalting process. In some embodiments, hydrocarbon feed 102 may include crude oil that has not undergone pretreatment, separation (such as distillation), or other operations that change the hydrocarbon composition of the crude oil before introducing the crude oil into system 100.

[0052] Reference again Figure 1 , the hydrocarbon feed 102 may be introduced directly into the hydroprocessing unit 110 or may be combined with hydrogen upstream of the hydroprocessing unit 110. The hydrogen may be recycled hydrogen 143 recovered from the system 100, such as from the hydrocracking effluent separation system 140, the steam cracking unit 160, or both. The hydrogen may also include make-up hydrogen 104 from an external hydrogen source (not shown). Hydrogen, such as the recycled hydrogen 143, the make-up hydrogen 104, or both, may be delivered directly to the hydroprocessing unit 110 or may be combined with the hydrocarbon feed 102 upstream of the hydroprocessing unit 110.

[0053] The hydroprocessing unit 110 can be operated to remove one or more impurities, such as metals, sulfur compounds, nitrogen compounds, asphaltenes, or a combination of these, from the hydrocarbon feed 102. In addition, the hydroprocessing unit 110 can be operated to saturate at least a portion of the polycyclic aromatic compounds in the hydrocarbon feed 102. The hydroprocessing unit 110 can include at least one hydroprocessing catalyst, which can be disposed in at least one hydroprocessing zone within the hydroprocessing unit 110. The hydroprocessing unit 110 can be operated to contact the hydrocarbon feed 102 with the at least one hydroprocessing catalyst in the presence of hydrogen, wherein the contact with the hydroprocessing catalyst can upgrade the hydrocarbon feed 102 to produce a hydroprocessing effluent 112 having a reduced concentration of at least one of the following: nitrogen, sulfur, metals, aromatic compounds, or a combination of these.

[0054] The hydroprocessing unit 110 may include one or more hydroprocessing zones. Figure 4 , the hydroprocessing unit 110 may include a plurality of packed bed reaction zones arranged in series, such as one or more of the following: a hydrodemetallization (HDM) reaction zone 114, a transition zone 115, a hydrodesulfurization (HDS) zone 116, a hydrodenitrogenation (HDN) zone 117, a hydrodearomatization (HDA) zone (not shown), or a combination of these reaction zones. Each of the plurality of reaction zones may be disposed in a single reactor or in a plurality of reactors in series. Each of the HDM reaction zone 114, the transition reaction zone 115, the HDS reaction zone 116, the HDN reaction zone 117, and the HDA reaction zone (not shown) may include a catalyst bed containing a hydroprocessing catalyst. The hydroprocessing unit 110 may include one or more of the following: a HDM reaction zone 114 containing a HDM catalyst, a transition reaction zone 115 containing a transition catalyst, a HDS reaction zone 116 containing a HDS catalyst, a HDN reaction zone 117 containing a HDN catalyst, a HDA reaction zone containing a HDA catalyst, or a combination of these. The reaction zones of the hydroprocessing unit 110 may be in any order and need not be Figure 4 In one or more embodiments, the hydroprocessing unit 110 may include a HDM reaction zone 114, a transition reaction zone 115 downstream of the HDM reaction zone 114, and a HDS reaction zone 116 downstream of the transition reaction zone 115. The hydroprocessing unit 110 may include any type of reactor suitable for contacting the hydrocarbon feed 102 with a hydroprocessing catalyst. Suitable reactors may include, but are not limited to, fixed bed reactors, moving bed reactors, fluidized bed reactors, plug flow reactors, other types of reactors, or combinations of reactors. For example, the hydroprocessing unit 110 may include one or more fixed bed reactors that may be operated in a downward flow, upward flow, or horizontal flow configuration.

[0055] refer to Figure 1 and Figure 4 , the hydroprocessing catalyst in the hydroprocessing unit 110 may include one or more metals selected from the 5th, 6th, 8th, 9th or 10th metal elements of the International Union of Pure and Applied Chemistry (IUPAC) periodic table, such as but not limited to molybdenum, nickel, cobalt, tungsten or a combination of these metals. The metal of the hydroprocessing catalyst may exist as a pure metal, a metal oxide, a metal sulfide or a combination of these. The metal, metal oxide or metal sulfide of the hydroprocessing catalyst may be loaded on a carrier, such as silica, alumina or a combination of these. The carrier material may include but is not limited to γ-alumina or silica / alumina extrudates, spheres, cylinders, beads, pellets and combinations thereof. In one or more embodiments, the hydroprocessing catalyst may include nickel and molybdenum on an alumina carrier or cobalt and molybdenum on an alumina carrier.

[0056] When the hydroprocessing catalyst present in the hydroprocessing unit 110 includes a HDM catalyst, the HDM catalyst may include one or more metals from Group 5, Group 6, or Groups 8-10 of the IUPAC Periodic Table of Elements, which may be in the form of a metal, a metal oxide, or a metal sulfide. For example, the HDM catalyst may include molybdenum. The HDM catalyst may further include a support material, and the metal may be disposed on the support material. The support material may be a gamma-alumina support having a surface area of ​​100 square meters per gram (m 2 / g) to 160m 2 / g, such as 100m 2 / g to 130m 2 / g or 130m 2 / g to 160m 2 / g. Based on the total weight of the HDM catalyst, the HDM catalyst may include 0.5 wt % to 12 wt % of molybdenum oxide or molybdenum sulfide, such as 2 wt % to 10 wt % or 3 wt % to 7 wt % of molybdenum oxide or molybdenum sulfide. The HDM catalyst may have a carbon content greater than or equal to 0.8 cubic centimeters per gram (cm 3 / g), greater than or equal to 0.9cm 3 / g or even greater than or equal to 1.0cm 3 / g of total pore volume. The average pore size of the HDM catalyst macropores is greater than or equal to 50 nanometers (nm). The HDM catalyst may include a dopant comprising one or more compounds, wherein the one or more compounds include an element selected from the group consisting of boron, silicon, halogens, phosphorus, and combinations thereof.

[0057] When the hydroprocessing catalyst present in the hydroprocessing unit 110 includes an HDS catalyst, the HDS catalyst may include one or more metals supported on a support material. The metal of the HDS catalyst may include one or more metals from Group 6 of the IUPAC Periodic Table of Elements and a metal from Groups 8-10, which may exist as a metal, a metal oxide, or a metal sulfide. The HDS catalyst may include one or more metals selected from molybdenum, tungsten, nickel, cobalt, or a combination of these, which may exist as a metal, a metal oxide, or a metal sulfide. The HDS catalyst may further include a support material, and the metal, metal oxide, or metal sulfide may be disposed on the support material. In some embodiments, the HDS catalyst may include Mo and Ni on an alumina support (sometimes referred to as a "Mo-Ni / Al2O3 catalyst"). The HDS catalyst may also contain a dopant selected from the group consisting of boron, phosphorus, halogens, silicon, and combinations thereof. The HDS catalyst may include 10 to 18 wt % molybdenum oxide or molybdenum sulfide, such as 11 to 17 wt % or 12 to 16 wt % molybdenum oxide or molybdenum sulfide, based on the total weight of the HDS catalyst. Additionally or alternatively, the HDS catalyst may include 1 to 7 wt % nickel oxide or nickel sulfide, such as 2 to 6 wt % or 3 to 5 wt % nickel oxide or nickel sulfide, based on the total weight of the HDS catalyst. The average surface area of ​​the HDS catalyst may be 140 m 2 / g to 200m 2 / , such as 140m 2 / g to 170m 2 / g or 170m 2 / g to 200m 2 / g. The total pore volume of the HDS catalyst can be 0.5cm 3 / g to 0.7cm 3 / , such as 0.6cm 3 / g. The HDS catalyst may generally have a mesoporous structure with a pore size ranging from 2 nm to 50 nm, such as from 12 nm to 50 nm.

[0058] When the hydroprocessing catalyst present in the hydroprocessing unit 110 includes a HDN catalyst, the HDN catalyst may include a metal oxide or a metal sulfide supported on a support material. The metal of the HDN catalyst may include one or more metals from Group 5, Group 6, and Group 8-10 of the IUPAC periodic table, which may exist as a metal, a metal oxide, or a metal sulfide. In one embodiment, the HDN catalyst may contain at least one metal from Group 6 of IUPAC (such as molybdenum) and at least one metal from Group 8-10 of IUPAC (such as nickel). The HDN catalyst may also include at least one dopant selected from the group consisting of boron, phosphorus, silicon, halogen, and a combination thereof. In an embodiment, cobalt may be used to increase the desulfurization of the HDN catalyst. In an embodiment, the HDN catalyst may have a higher metal loading for the active phase compared to the HDM catalyst. An increase in metal loading may result in an increase in catalytic activity. In one or more embodiments, the HDN catalyst comprises nickel (Ni) and molybdenum (Mo), and the molar ratio of nickel to molybdenum (Ni / (Ni+Mo)) is from 0.1 to 0.3 (such as from 0.1 to 0.2 or from 0.2 to 0.3). In embodiments including cobalt (Co), the molar ratio of (Co+Ni) / Mo can be in the range of 0.25 to 0.85 (such as from 0.25 to 0.5 or from 0.5 to 0.85).

[0059] The support material may include gamma-alumina, mesoporous alumina, silica, or both in the form of extrudates, spheres, cylinders, and pellets. In embodiments, the HDN catalyst may contain a gamma-alumina based support having a surface area of ​​180 m 2 / g to 240m 2 / g (such as 180m 2 / g to 210m 2 / g, or 210m 2 / g to 240m 2 This relatively large surface area of ​​the HDN catalyst can allow for a smaller pore volume (e.g., less than 1.0 cm 3 / g, less than 0.95cm 3 / g or even less than 0.9cm 3 / g). Based on the total weight of the HDN catalyst, the HDN catalyst may contain 10 wt % to 18 wt % of molybdenum oxide or molybdenum sulfide, such as 13 wt % to 17 wt % or 14 wt % to 16 wt % of molybdenum oxide or molybdenum sulfide. Based on the total weight of the HDN catalyst, the HDN catalyst may contain 2 wt % to 8 wt % of nickel oxide or nickel sulfide, such as 3 wt % to 7 wt % or 4 wt % to 6 wt % of nickel oxide or nickel sulfide. Based on the total weight of the HDN catalyst, the HDN catalyst may include 74 wt % to 88 wt % of aluminum oxide, such as 76 wt % to 84 wt % or 78 wt % to 82 wt % of aluminum oxide.

[0060] When the hydroprocessing unit 110 includes a transition reaction zone 115, the transition reaction zone 115 is operable to remove a certain amount of metal components and a certain amount of sulfur components from the HDM reaction effluent stream. The transition catalyst may include an alumina-based carrier in the form of an extrudate and at least one metal substance supported on the alumina-based carrier. The metal substance may be in the form of a metal, a metal oxide, or a metal sulfide. The metal substance of the transition catalyst may include at least one metal from Group 6 of the IUPAC Periodic Table of Elements and at least one metal from Groups 8-10, the metal being in the form of a metal, a metal oxide, a metal sulfide, or a combination of these. Example metals from Group 6 of the IUPAC Periodic Table of Elements include molybdenum and tungsten. Example metals from Groups 8-10 of the IUPAC include nickel and cobalt. For example, the transition catalyst may include Mo and Ni on an alumina carrier (sometimes referred to as a "Mo-Ni / Al2O3 catalyst"). The transition catalyst may also include a dopant selected from a group consisting of boron, phosphorus, halogens, silicon, and combinations thereof. The surface area of ​​the transition catalyst may be 140 m 2 / g to 200m 2 / g (for example, from 140m 2 / g to 170m 2 / g or from 170m 2 / g to 200m 2 / g). The intermediate pore volume of the transition catalyst can be from 0.5 cm 3 / g to 0.7cm 3 / g (e.g. 0.6cm 3 / g). The transition catalyst may generally include a mesoporous structure having a pore size in the range of 12 nm to 50 nm. These characteristics provide balanced activity in terms of HDM and HDS. The transition catalyst may contain 10 wt % to 18 wt % of molybdenum oxide or molybdenum sulfide (such as 11 wt % to 17 wt % or 12 wt % to 16 wt % of molybdenum oxide or molybdenum sulfide), 1 wt % to 7 wt % of nickel oxide or nickel sulfide (such as 2 wt % to 6 wt % or 3 wt % to 5 wt % of nickel oxide or nickel sulfide), and 75 wt % to 89 wt % of alumina (such as 77 wt % to 87 wt % or 79 wt % to 85 wt % of alumina).

[0061] When the hydroprocessing catalyst present in the hydroprocessing unit 110 includes an HDA catalyst, the HDA catalyst may include one or more metals from Group 5, Group 6, Group 8, Group 9, or Group 10 of the IUPAC Periodic Table of Elements, which may be present as a metal, a metal oxide, or a metal sulfide. The HDA catalyst may include one or more metals from Group 5 or Group 6 of the IUPAC Periodic Table of Elements and one or more metals from Group 8, Group 9, or Group 10 of the IUPAC Periodic Table of Elements. The HDA catalyst may include one or more metals of molybdenum, tungsten, nickel, cobalt, or a combination of these, which may be present as a metal, a metal oxide, a metal sulfide, or a combination of these. The HDA catalyst may further include a support material (such as a zeolite), and the metal may be disposed on the support material. In one or more embodiments, the HDA catalyst may include a tungsten and nickel metal catalyst on a mesoporous zeolite support (sometimes referred to as a "W-Ni / mesoporous-zeolite catalyst"). In one or more embodiments, the HDA catalyst may include a molybdenum and nickel metal catalyst on a mesoporous zeolite support (sometimes referred to as a "Mo-Ni / mesoporous-zeolite catalyst"). The zeolite support material may not be limited to any particular type of zeolite. However, it is contemplated that zeolites such as Y, Beta, AW, LZ-15, LZ-45, Y-82, Y-84, LZ-210, LZ-25, silicalite, or mordenite may be suitable for use in the presently described HDA catalysts. The support material (i.e., mesoporous zeolite) of the HDA catalyst may be mesoporous, having an average pore size of 2 nm to 50 nm.

[0062] Based on the total weight of the HDA catalyst, the HDA catalyst may include 18 wt% to 28 wt% tungsten sulfide or tungsten oxide, such as 20 wt% to 27 wt% or 22 wt% to 26 wt% tungsten or tungsten sulfide or tungsten oxide. Based on the total weight of the HDA catalyst, the HDA catalyst may additionally include 2 wt% to 8 wt% nickel oxide or nickel sulfide, such as 3 wt% to 7 wt% or 4 wt% to 6 wt% nickel oxide or nickel sulfide. In one or more embodiments, the HDA catalyst may include 12 wt% to 18 wt% molybdenum oxide or molybdenum sulfide (such as 13 wt% to 17 wt% or 14 wt% to 16 wt% molybdenum oxide or molybdenum sulfide), based on the total weight of the HDA catalyst, and 2 wt% to 8 wt% nickel oxide or nickel sulfide (such as 3 wt% to 7 wt% or 4 wt% to 6 wt% nickel oxide or nickel sulfide), based on the total weight of the HDA catalyst.

[0063] The hydrocarbon feed 102 may be contacted with a hydrotreating catalyst in a hydrotreating unit 110 at a hydrotreating temperature and a hydrotreating pressure sufficient to upgrade the hydrocarbon feed 102 to remove one or more of metals, nitrogen compounds, sulfur compounds, aromatic compounds, or a combination of these. The hydrotreating unit 110 may be operated at a hydrotreating temperature of 300° C. to 450° C., such as 350° C. to 420° C. The hydrotreating unit 110 may be operated at a hydrotreating pressure of 50 bar (5,000 kilopascals (kPa)) to 200 bar (20,000 kPa), such as 130 bar (13,000 kPa) to 160 bar (16,000 kPa). The hydrotreating unit 110 may be operated at a rate of 0.1 (hr 125) per hour. -1 ) to 1hr -1 (such as 0.2hr -1 To 0.7hr -1 ) liquid volume space velocity (LHSV). The volume ratio of hydrogen introduced into the hydroprocessing unit 110 to the hydrocarbon feed 102 can be 800:1 to 1200:1. Hydrogen can be introduced into the hydroprocessing unit 110 at the inlet of the hydroprocessing unit 110. Figure 4 In some embodiments, hydrogen may also be introduced into each reaction zone, such as HDM reaction zone 114, transition reaction zone 115, HDS reaction zone 116, HDN reaction zone 117, HDA reaction zone (not shown), or a combination of these.

[0064] Reference again Figure 1, the concentration of one or more of metals, sulfur-containing hydrocarbons, nitrogen-containing hydrocarbons, and aromatic compounds in the hydroprocessing effluent 112 passed from the hydroprocessing unit 110 can be at least 2 percentage points (%) lower than the concentration of these compounds in the hydrocarbon feed 102, at least 5%, at least 10%, at least 25%, at least 50%, or even at least 75%. As previously described, contacting the hydrocarbon feed 102 with a hydroprocessing catalyst such as a transition catalyst, an HDS catalyst, an HDN catalyst, or a combination of these in the presence of hydrogen in the hydroprocessing unit 110 can cause a reaction of the sulfur-containing hydrocarbons, the nitrogen-containing hydrocarbons, or both in the hydrocarbon feed 102 to remove at least a portion of the sulfur and nitrogen from the hydrocarbons in the hydrocarbon feed 102. For example, the sulfur-containing hydrocarbons can be converted into hydrocarbons and sulfur-containing gases, such as hydrogen sulfide (H2S), and the nitrogen-containing hydrocarbons can be converted into hydrocarbons and nitrogen-containing gases, such as ammonia (NH3). The sulfur-containing gases and nitrogen-containing gases can be removed downstream from the system 100 by the hydrocracking effluent separation system 140. The hydroprocessing effluent 112 may have a lower concentration of sulfur-containing hydrocarbons than the concentration of sulfur-containing hydrocarbons in the hydrocarbon feed 102. The hydroprocessing effluent 112 may have a concentration of sulfur-containing hydrocarbons of 0.01 wt % to 0.10 wt %, such as 0.01 wt % to 0.08 wt %, 0.01 wt % to 0.05 wt %, 0.02 wt % to 0.10 wt %, 0.02 wt % to 0.08 wt %, or 0.02 wt % to 0.07 wt %, based on the total weight of the hydroprocessing effluent 112. The hydroprocessing effluent 112 may have a lower concentration of nitrogen-containing hydrocarbons than the concentration of nitrogen-containing hydrocarbons in the hydrocarbon feed 102. The nitrogen-containing hydrocarbon concentration of the hydroprocessing effluent 112 can be 0 parts per million by weight (ppmw) to 500 ppmw, such as 10 ppmw to 500 ppmw, 10 ppmw to 400 ppmw, 10 ppmw to 300 ppmw, 50 ppmw to 500 ppmw, 50 ppmw to 400 ppmw, or 50 ppmw to 300 ppmw, based on the total weight of the hydroprocessing effluent 112.

[0065] Contacting the hydrocarbon feed 102 with a hydroprocessing catalyst, such as a HDM catalyst, a transition catalyst, or both, in the presence of hydrogen in the hydroprocessing unit 110 may operate to remove metals from the hydrocarbons. The metal concentration of the hydroprocessing effluent 112 may be less than the metal concentration of the hydrocarbon feed 102. The metal concentration of the hydroprocessing effluent 103 may be 0 ppmw to 100 ppmw, such as 0 ppmw to 75 ppmw, 0 ppmw to 50 ppmw, 0 ppmw to 25 ppmw, 0 ppmw to 10 ppmw, 0 ppmw to 5 ppmw, 0.1 ppmw to 100 ppmw, 0.1 ppmw to 75 ppmw, 0.1 ppmw to 50 ppmw, 0.1 ppmw to 25 ppmw, 0.1 ppmw to 10 ppmw, or 0.1 ppmw to 5 ppmw, based on the total weight of the hydroprocessing effluent 112. The nickel concentration of the hydroprocessing effluent 112 may be less than the nickel concentration of the hydrocarbon feed 102, such as a nickel concentration of 0 ppmw to 10 ppmw, 0.1 ppmw to 5 ppmw, or 0.1 ppmw to 1 ppmw, based on the total weight of the hydroprocessing effluent 112. The arsenic content of the hydroprocessing effluent 112 may be less than the arsenic content of the hydrocarbon feed 102, such as 0 ppmw to 1 ppmw, or 0.01 ppmw to 0.5 ppmw, based on the total weight of the hydroprocessing effluent 112. The vanadium content of the hydroprocessing effluent 112 may be less than the vanadium content of the hydrocarbon feed 102, such as 0 ppmw to 10 ppmw, such as 01 ppmw to 5 ppmw, or even 0.1 ppmw to 1 ppmw, based on the total weight of the hydroprocessing effluent 112.

[0066] The hydroprocessing effluent 112 may have a lower concentration of aromatic compounds than the concentration of aromatic compounds in the hydrocarbon feed 102. The hydroprocessing effluent 112 may have a concentration of aromatic compounds of 5 wt% to 40 wt%, such as 5 wt% to 30 wt%, or 5 wt% to 20 wt%, based on the total weight of the hydroprocessing effluent 112. The hydroprocessing effluent 112 may have a lower concentration of asphaltenes, polycyclic aromatic hydrocarbons, and other coke precursors than the concentration of asphaltenes, polycyclic aromatic hydrocarbons, and other coke precursors in the hydrocarbon feed 102. The hydroprocessing effluent 112 may have a concentration of asphaltenes, polycyclic aromatic hydrocarbons, and other coke precursors of 0.01 wt% to 1 wt%, such as 0.01 wt% to 0.75 wt%, or 0.01 wt% to 0.50 wt%, based on the total weight of the hydroprocessing effluent 112.

[0067] Refer to Figure 1, at least 20 wt% of the hydroprocessed effluent 112 can have a boiling point temperature less than or equal to 225°C. In one or more embodiments, at least 5 wt%, at least 10 wt%, at least 20 wt%, or even at least 30 wt% of the hydroprocessed effluent 112 can have a boiling point temperature less than or equal to 225°C. The hydroprocessed effluent 112 can have an initial boiling point (IBP) temperature less than or equal to 100°C, such as less than or equal to 90°C, less than or equal to 80°C, less than or equal to 70°C, or even less than or equal to 60°C. The hydroprocessed effluent 112 can be characterized by a T5 temperature, which is a temperature below which 5% of the constituents boil. The hydroprocessed effluent 112 can have a T5 temperature less than or equal to 150°C, less than or equal to 130°C, less than or equal to 120°C, less than or equal to 110°C, or even less than or equal to 100°C. The hydroprocessed effluent 112 may also be characterized by a T95 temperature, which is the temperature at which 95% of the constituents of the hydroprocessed effluent 112 boil. In some embodiments, the hydroprocessed effluent 112 may have a T95 temperature greater than or equal to 570°C, greater than or equal to 580°C, greater than or equal to 590°C, even greater than or equal to 600°C, or even greater than or equal to 610°C.

[0068] The density of the hydroprocessing effluent 112 can be less than the density of the hydrocarbon feed 102. The hydroprocessing effluent 112 can have a density of 0.80 grams per milliliter (g / mL) to 0.95 g / mL (e.g., 0.80 g / mL to 0.90 g / mL, 0.80 g / mL to 0.85 g / mL, 0.82 g / mL to 0.95 g / mL, 0.82 g / mL to 0.90 g / mL, 0.82 g / mL to 0.85 g / mL, 0.83 g / mL to 0.95 g / mL, 0.83 g / mL to 0.90 g / mL, or 0.83 g / mL to 0.85 g / mL). The API gravity of the hydroprocessing effluent 112 can be greater than the API gravity of the hydrocarbon feed 102 introduced into the hydroprocessing unit 110. The hydroprocessed effluent 112 may have an API gravity of less than or equal to 50 degrees or less than or equal to 40 degrees. In some embodiments, the hydroprocessed effluent 112 may have an API of 25 to 50 degrees, 30 to 50 degrees, 25 to 45 degrees, or 255 to 40 degrees.

[0069] Reference again Figure 1, the hydrotreated effluent 112 may be passed to a hydrocracking unit 130 that may be disposed downstream of the hydrotreating unit 110. The hydrocracking unit 130 may be considered the main hydrocracking unit of the system 100. The hydrocracking unit 130 is operable to contact the hydrotreated effluent 112 with a hydrocracking catalyst in the presence of hydrogen in a hydrocracking zone 132 under reaction conditions sufficient to subject at least a portion of the hydrocarbons in the hydrotreated effluent 112 to hydrocracking to produce a hydrocracking effluent 134 having an increased concentration of hydrocarbons having a boiling point temperature of less than or equal to 180° C. as compared to the hydrotreated effluent 112. The hydrocracking unit 130 may include a hydrocracking catalyst at least in the hydrocracking zone 132. In the hydrocracking unit 130, saturated polycyclic aromatic compounds and other larger molecular weight hydrocarbons in the hydroprocessing effluent 112 can be converted into smaller low-distillation hydrocarbons by contacting the hydroprocessing effluent 112 with a hydrocracking catalyst in the presence of hydrogen. The hydrocracking unit 130 can be any type of reactor capable of operating to contact the hydroprocessing effluent 112 with a hydrocracking catalyst in the hydrocracking zone 132. Reactors suitable for the hydrocracking unit 130 can include, but are not limited to, fixed bed reactors, moving bed reactors, fluidized bed reactors, plug flow reactors, other types of reactors, or combinations of reactors. For example, the hydrocracking unit 130 can include one or more fixed bed reactors that can be operated in a downflow, upflow, or horizontal flow configuration.

[0070] Hydrogen may be introduced into the hydrocracking unit 130 along with the hydroprocessing effluent 112. The hydrogen introduced into the hydrocracking unit 130 may be recycled hydrogen 143 recovered from the system 100, such as from the hydrocracking effluent separation system 140, the steam cracking unit 160, or both. The hydrogen may also include make-up hydrogen 104 from an external hydrogen source (not shown). Hydrogen, such as the recycled hydrogen 143, the make-up hydrogen 104, or both, may be delivered directly to the hydrocracking unit 130 or combined with the hydroprocessing effluent 112 upstream of the hydrocracking unit 130.

[0071] The hydrocracking catalyst may be a solid particle catalyst capable of promoting or increasing the reaction rate of the cracking reaction of hydrocarbons in the presence of hydrogen. Suitable hydrocracking catalysts may include, but are not limited to, zeolite catalysts. Examples of zeolite catalysts suitable for use as hydrocracking catalysts may include, but are not limited to, Y-type zeolites, REY-type zeolites, USY-type zeolites, RE-USY-type zeolites, mordenite framework inversion (MFI)-type zeolites, beta zeolites, or combinations thereof. The hydrocracking catalyst may be a hydrocracking catalyst containing a graded zeolite, such as, but not limited to, graded beta zeolites, graded Y-zeolites, or other graded zeolites. Graded zeolites may refer to zeolites having an average pore size of 2nm to 40nm or 5nm to 25nm as determined using the Barrett-Joyner-Halinda (BJH) method. Graded zeolites may be prepared by subjecting microporous beta zeolite or Y-zeolite to a desiliconization process or by synthesizing beta zeolite or Y-zeolite using a template or pore directing agent to obtain a desired graded pore structure.

[0072] The hydrocracking catalyst in the hydrocracking unit 130 may additionally include one or more metals supported on the surface of the zeolite. The hydrocracking catalyst in the hydrocracking unit 130 may include one or more metals selected from metal elements in Group 6, Group 7, Group 8, Group 9 or Group 10 of the IUPAC periodic table supported on a zeolite or a graded zeolite. Example metals for the hydrocracking catalyst of the hydrocracking unit 130 may include, but are not limited to, molybdenum, cobalt, tungsten, nickel, platinum, palladium, or a combination of these. In one or more embodiments, the hydrocracking catalyst in the hydrocracking unit 130 may include nickel and molybdenum supported on a Y-zeolite or a beta zeolite carrier. In one or more embodiments, the hydrocracking catalyst in the secondary hydrocracking unit 190 may include nickel and tungsten supported on a Y-zeolite or a beta zeolite carrier. In one or more embodiments, the hydrocracking catalyst in the hydrocracking unit 130 may include platinum and palladium supported on a Y-zeolite or a beta zeolite carrier.

[0073] The hydrocracking unit 130 may be operated under conditions sufficient to promote or increase the reaction rate of the hydrocracking reaction to produce a hydrocracking effluent 134 having an increased concentration of smaller, lower-distillation hydrocarbons, such as, but not limited to, C2 to C10 paraffins and other hydrocarbons (naphtha) having a distillation temperature less than or equal to 180° C. The hydrotreated effluent 112 may be contacted with a hydrocracking catalyst in the hydrocracking unit 130 at a hydrocracking temperature and a hydrocracking pressure sufficient to crack at least a portion of the hydrocarbons, such as, but not limited to, saturated polycyclic aromatic compounds, in the hydrotreated effluent 112 to produce smaller, lower-distillation hydrocarbons having a distillation temperature less than or equal to 180° C. The hydrocracking unit 130 may be operated at a hydrocracking temperature of 300° C. to 450° C., such as 350° C. to 420° C. The hydrocracking unit 130 may be operated at a hydrocracking pressure of 50 bar (5,000 kPa) to 200 bar (20,000 kPa), such as 130 bar (13,000 kPa) to 160 bar (16,000 kPa). The hydrocracking unit 130 may be operated at a rate of 0.1 (hr) per hour. -1 ) to 3 hours -1 (such as 0.2hr -1 to 2 hours -1 ) is operated at a liquid volume space velocity (LHSV) of 100:1 to 1200:1. The volume ratio of hydrogen introduced into the hydrocracking unit 130 to the hydroprocessed effluent 112 may be 800:1 to 1200:1. Hydrogen may be introduced into the hydrocracking unit 130 at the inlet of the hydrocracking unit 130.

[0074] refer to Figure 4 In one or more embodiments, the hydrocracking unit 130 can include at least one supplemental hydroprocessing zone 131 upstream of the hydrocracking zone 132. The supplemental hydroprocessing zone 131 can include a hydroprocessing catalyst, such as any of the hydroprocessing catalysts previously described in the present disclosure. For example, in one or more embodiments, the hydroprocessing catalyst in the supplemental hydroprocessing zone 131 of the hydrocracking unit 130 can be a catalyst comprising nickel and molybdenum or cobalt and molybdenum supported on an alumina catalyst support. The supplemental hydroprocessing zone 131 can be disposed in the same reactor as the hydrocracking zone 132 and upstream of the hydrocracking zone 132, or can be disposed in a separate reactor upstream of the reactor that includes the hydrocracking zone 132.

[0075] The hydrocracking catalyst may be at least partially deactivated due to the deposition of contaminants such as coke or asphaltenes on the surface of the hydrocracking catalyst. As previously described, the hydroprocessing of the hydrocarbon feed 102 in the hydroprocessing unit 110 may deconstruct compounds of the solution of asphaltenes and other coke precursors in the stable hydrocarbon feed 102. When the stabilizing system is destroyed, asphaltenes and other coke precursors may be precipitated in the hydroprocessing effluent 112. When the hydroprocessing effluent 112 is transferred to the hydrocracking unit 130 and contacts the hydrocracking catalyst, the precipitated asphaltenes may be deposited on the surface of the hydrocracking catalyst. The coke precursors in the hydroprocessing effluent 112 may produce coke under the reaction conditions of the hydrocracking reaction, and the coke may also be deposited on the surface of the hydrocracking catalyst. Therefore, the presence of asphaltenes and other coke precursors in the hydroprocessing effluent 112 may have an adverse effect on the service life of the hydrocracking catalyst in the hydrocracking unit 130. Even small amounts of asphaltenes and coke precursors in the hydroprocessing effluent 112 , such as less than 0.5 wt %, can cause hydrocracking catalyst deactivation problems and disrupt smooth steady-state continuous operation of the system 100 .

[0076] refer to Figure 1 The system 100 may include an adsorption unit 120 operable to remove asphaltene and other coke precursors from the system. The adsorption unit 120 may be disposed downstream of the hydroprocessing unit 110. Figure 1 As shown, the adsorption unit 120 may be disposed between the hydroprocessing unit 110 and the hydrocracking unit 130. Figure 5 and Figure 6 In one or more embodiments, the adsorption unit 120 can be disposed at other locations within the system 100 , such as downstream of the hydrocracking unit 130 or between the high-pressure separator 150 and the fractionator 154 of the hydrocracking effluent separation system 140 downstream of the hydrocracking unit 130 .

[0077] Reference again Figure 1 , the adsorption unit 120 may include a plurality of adsorbent beds or adsorption zones, such as a first adsorption zone 122 and a second adsorption zone 124, which may be arranged in parallel. Figure 1100 is depicted as having two adsorption zones. However, the adsorption unit 120 may have more than or equal to two adsorption zones, such as 2, 3, 4, 5, 6, 7, 8 or more than 8 adsorption zones. Each adsorbent bed may include an adsorbent material capable of selectively adsorbing asphaltene, coke precursor, or both from hydrocarbon vapors such as hydroprocessing effluent 112, hydrocracking effluent 134, or other effluents of the system 100. Adsorbent materials suitable for the adsorption unit 120 may include, but are not limited to, spherical alumina, clay, metal nanoparticles, or a combination of these. The adsorbent material may be granular. The adsorbent material may have a pore volume sufficient to allow larger organic molecules such as asphaltene to be adsorbed into the pores. The adsorbent material may have a total pore volume greater than or equal to 1.0 milliliters per gram (ml / g), such as greater than or equal to 1.1 ml / g or greater than or equal to 1.5 ml / g. The adsorbent material may have a total pore volume of 1.0 ml / g to 3.0 ml / g, such as 1.1 ml / g to 3.0 ml / g, or even 1.5 ml / g to 3.0 ml / g.

[0078] The adsorbent material may have an asphaltene absorption of greater than or equal to 5 grams of asphaltene per gram of adsorbent material, such as 5 grams to 20 grams of asphaltene per gram of adsorbent material. The absorption of asphaltene by the adsorbent material can be determined by saturating the adsorbent with asphaltene. The adsorbent material can be saturated by monitoring the asphaltene concentration in the effluent leaving the adsorption unit 120. The adsorbent material may be saturated when the asphaltene concentration in the effluent from the adsorption unit suddenly increases. Once the adsorbent is saturated, the adsorption unit can be washed with straight-run diesel for four hours. The adsorbent can then be unloaded from the adsorption unit 120. 100 grams of saturated adsorbent is weighed, then washed with toluene and calcined in a furnace maintained at 700° C. under air flow for 8 hours. After calcination, the adsorbent sample is weighed. The absorption of asphaltene can be calculated as the difference between the initial 100 grams of saturated adsorbent sample and the final weight of the adsorbent after all asphaltene is removed by washing and calcining.

[0079] Reference again Figure 1During operation, the hydroprocessing effluent 112 may pass through one or more adsorption zones, such as the first adsorption zone 122, the second adsorption zone 124, or both, in which the hydroprocessing effluent 112 is contacted with an adsorbent material. The contact of the hydroprocessing effluent 112 with the adsorbent material in the adsorption unit 120 may cause at least a portion of the asphaltenes, coke precursors, or both to be adsorbed into the adsorbent material. The adsorption unit 120 may be operated under the operating conditions of the unit operation directly upstream of the adsorption unit 120. When the adsorption unit 120 is located directly downstream of the hydroprocessing unit 110 and between the hydroprocessing unit 110 and the hydrocracking unit 130, the adsorption unit 120 may be operated at a temperature and pressure similar to the hydroprocessing temperature and hydroprocessing pressure of the hydroprocessing unit 110. In one or more embodiments, the adsorption unit 120 may be operated at a temperature of 300° C. to 450° C., such as 350° C. to 420° C. The adsorption unit 120 may be operated at a pressure of 50 bar (5,000 kPa) to 200 bar (20,000 kPa), such as 130 bar (13,000 kPa) to 160 bar (16,000 kPa). The adsorption unit 120 may be operated at a pressure of 5 hr. -1 Up to 10 hours -1 Liquid Hourly Space Velocity (LHSV) operation.

[0080] The hydroprocessed effluent 112 passed from the adsorption unit 120 may have a reduced concentration of asphaltenes and other coke precursors compared to the hydroprocessed effluent 112 passed from the hydroprocessing unit 110. The adsorption unit 120 can be operated to remove greater than or equal to 95 percent (%) of asphaltenes from the hydroprocessed effluent 112 or other effluent passed through the adsorption unit 120. The adsorption unit 120 can be operated to remove greater than or equal to 95% or even greater than or equal to 98% of asphaltenes from the hydroprocessed effluent 112 or other effluent passed through the adsorption unit 120. Removing asphaltenes, coke precursors, or both from the system 100, such as from the hydroprocessed effluent 112, can reduce the accumulation of asphaltenes, coke, or both on the surface of the hydrocracking catalyst, which can reduce deactivation of the hydrocracking catalyst and increase the useful life of the hydrocracking catalyst. Removal of asphaltenes, coke precursors, or both may also reduce accumulation of asphaltenes, coke, or both on downstream equipment such as a downstream separation unit or steam cracking system 160. Reducing the accumulation of asphaltenes and coke on the hydrocracking catalyst may reduce deactivation of the hydrocracking catalyst and increase conversion of hydrocarbons from the hydrocarbon feed 102 to obtain hydrocarbons having a distillation temperature of less than or equal to 180° C. that are further processed in the steam cracking system 160 to produce olefins and aromatic compounds. Thus, removal of asphaltenes and coke precursors by the adsorption unit 120 may increase the yield of olefins and aromatic compounds from the system 100.

[0081] The adsorption unit 120 may include a plurality of adsorption zones, such as a first adsorption zone 122, a second adsorption zone 124, and any additional adsorption zones, which may be arranged in parallel. The adsorption unit 120 may be operated in a swing mode, wherein the hydroprocessing effluent 112 or other effluent stream is passed through a first subset of the plurality of adsorbent beds. When the first subset of adsorbent beds becomes saturated with asphaltenes, coke precursors, or both, the effluent stream passing through the adsorption unit 120 may be transitioned to a second subset of adsorbent beds to allow the first subset of adsorbent beds to be regenerated. For example, referring to Figure 1 , the hydroprocessed effluent 112 may be passed through the first adsorption zone 122 until the adsorbent material in the first adsorption zone 122 becomes saturated with asphaltenes, coke precursors, or both, and is no longer effective in removing more asphaltenes from the hydroprocessed effluent 112. The flow of the hydroprocessed effluent 112 may be transitioned to the second adsorption zone 124 while the first adsorption zone 122 is regenerating.

[0082] The adsorbent bed, such as the first adsorption zone 122 and the second adsorption zone 124, can be regenerated by passing a solvent through the adsorbent bed that is capable of desorbing and dissolving asphaltenes and coke precursors from the adsorbent material. Suitable solvents for regenerating the adsorbent bed may include, but are not limited to, aromatic solvents such as toluene, benzene, or a mixture of the two. Other solvents that are capable of dissolving asphaltenes may also be used to regenerate the adsorbent bed. Other solvents may include alkyl alcohols, halogenated hydrocarbons, aromatic compounds, or combinations of these.

[0083] Reference again Figure 1 , the hydrocracking effluent 134 may be passed to a hydrocracking effluent separation system 140. The hydrocracking effluent separation system 140 is operable to separate the hydrocracking effluent 134 to produce an upgraded low-distillate effluent 144, which may be passed as a feed to a steam cracking unit 160. The hydrocracking effluent separation system 140 may include one or more separation units that are collectively operable to separate the hydrocracking effluent 134 into at least light gases 142, an upgraded low-distillate effluent 144, and a high-distillate effluent 148. The hydrocracking effluent separation system 140 is also operable to produce a middle distillate effluent 146.

[0084] Light gas 142 may include, but is not limited to, excess hydrogen, methane, hydrogen sulfide, ammonia, and other light gases. Light gas may refer to a gas in a gaseous form at ambient temperature and pressure in the hydroprocessing effluent 112. Light gas 142 may include greater than or equal to 95%, greater than or equal to 97%, or even greater than or equal to 99% of light gas from the hydrocracking effluent 134. Light gas 142 may be transferred to a gas treatment machine for further processing, such as removal of hydrogen sulfide gas and ammonia and separation and purification of hydrogen. Hydrogen recovered from light gas 142 may be recycled back to hydroprocessing unit 110, hydrocracking unit 130, or both as at least a portion of recycled hydrogen 143. Recycled hydrogen 143 may also include hydrogen recovered from steam cracking system 160.

[0085] The upgraded low-boiling point effluent 144 may include hydrocarbon components having a boiling point temperature less than or equal to 180° C. The upgraded low-boiling point effluent 144 may include paraffinic compounds, such as alkanes having 2 to 10 carbon atoms (C2-C10 alkanes), and other hydrocarbons having a boiling point temperature less than 180° C., such as olefins and alkynes having a boiling point temperature less than 180° C. The upgraded low-boiling point effluent 144 may include greater than or equal to 95%, greater than or equal to 97%, or even greater than or equal to 98% of the C2-C10 alkanes from the hydrocracking effluent 134. The upgraded low-boiling point effluent 144 may be transferred from the hydrocracking effluent separation system 140 to the steam cracking system 160 downstream of the hydrocracking effluent separation system 140.

[0086] The middle distillate effluent 146 may include components of the hydrocracking effluent 134 having a boiling point temperature of 180° C. to 540° C. The middle distillate effluent 146 may be transferred from the system 100 or recycled back to the hydroprocessing unit 110. Figure 4 , the middle distillate effluent 146 may be passed to a secondary hydrocracking unit 190 for further processing. The secondary hydrocracking unit 190 will be described in more detail later in this disclosure.

[0087] The high-boiling effluent 148 may include constituents of the hydrocracking effluent 134 having a boiling point temperature greater than or equal to 540° C., such as 540° C. to 720° C. The high-boiling effluent 148 may be passed back to the hydroprocessing unit 110. The system 100 may include a high-boiling effluent recycle 149 operable to pass at least a portion of the high-boiling effluent 148 from the hydrocracking effluent separation system 140 back to the hydroprocessing unit 110. The portion of the high-boiling effluent 148 passed back in the high-boiling effluent recycle 149 may be combined with the hydrocarbon feed 102 upstream of the hydroprocessing unit 110 or may be passed directly and independently to the hydroprocessing unit 110. Passing at least a portion or all of high-boiling effluent 148 back to hydroprocessing unit 110 may increase the yield of olefins and aromatics from system 100 by further converting remaining larger hydrocarbons in high-boiling effluent 148 into smaller paraffinic hydrocarbons more suitable for processing in steam cracking system 160 .

[0088] refer to Figure 2 In one or more embodiments, the hydrocracking effluent separation system 140 can include at least a high pressure separator 150 and a fractionator 154. The high pressure separator 150 can be operated to separate the hydrocracking effluent 134 into light gases 142 and a high pressure separator liquid effluent 152. The light gases 142 can be passed to a gas processing machine and the high pressure separator liquid effluent 152 can be passed to the fractionator 154. The hydrocracking effluent separation system 140 can further include a low pressure separator (not shown) downstream of the high pressure separator 150 and disposed between the high pressure separator 150 and the fractionator 154. The low pressure separator can be operated to further separate gaseous components from the hydrocracking effluent 134 to produce a high pressure separator liquid effluent 152. The fractionator 154 is operable to separate the high pressure separator liquid effluent 152 into an upgraded low distillation point effluent 144, an intermediate distillation effluent 146, and a high distillation point effluent 148. In one or more embodiments, the fractionator 154 can include a fractionation tower operable to separate the high pressure separator liquid effluent 152 into a plurality of different effluent streams based on differences in distillation point temperatures.

[0089] As previously described, the upgraded low-distillation effluent 144 may be passed to the steam cracking system 160. Figure 3 , the steam cracking system 160 can include a steam cracking unit 170 and a steam cracking effluent separation system 180 downstream of the steam cracking unit 170. The steam cracking unit 170 can be operated to contact the upgraded low-boiler effluent 144 with steam 161 at a temperature sufficient to cause at least a portion of the hydrocarbons in the upgraded low-boiler effluent 144 to undergo a hydrocracking reaction to produce a steam cracking effluent 176 including an increased concentration of olefins, aromatics, or both.

[0090] The steam cracking system 160 may include a convection zone 172 and a pyrolysis zone 174. The upgraded low-boil point effluent 144 is passed into the convection zone 172 along with steam 161. In the convection zone 172, the upgraded low-boil point effluent 144 may be preheated to a desired temperature, such as 400° C. to 650° C. The contents of the upgraded low-boil point effluent 144 present in the convection zone 172 may then be passed to the pyrolysis zone 174 where it is steam cracked to produce a steam cracking effluent 176. The steam cracking effluent 176 may exit the steam cracking system 160 and pass through a heat exchanger (not shown) where a process fluid, such as water or pyrolysis fuel oil, cools the steam cracking effluent 176. The steam cracking effluent 176 may include a mixture of cracked hydrocarbon materials that may be separated into one or more petrochemical products contained in one or more system product streams. For example, the steam cracking effluent 176 may include one or more of fuel oil, gasoline, mixed butenes, butadiene, propylene, ethylene, methane, hydrogen, aromatic compounds or other hydrocarbons. The steam cracking effluent 176 may additionally include water from the cracking of the stream. The pyrolysis zone 174 may be operated at a temperature of 700° C. to 900° C. The pyrolysis zone 174 may be operated with a residence time of 0.05 seconds to 2 seconds. The mass ratio of steam 161 to the upgraded low-boil point effluent 144 may be from about 0.3:1 to about 2:1.

[0091] Reference again Figure 3 , the steam cracking effluent 176 may be passed to a steam cracking effluent separation system 180. The steam cracking effluent separation system 180 is operable to separate the steam cracking effluent 176 into a plurality of effluent streams, such as, but not limited to, a gaseous effluent 162, an olefin effluent 164, an aromatic effluent 166, a pyrolysis oil 168, or a combination of these. The steam cracking effluent separation system 180 may include one or more separation units that are collectively operable to separate the steam cracking effluent 176 into one or more of a gaseous effluent 162, an olefin effluent 164, an aromatic effluent 166, a pyrolysis oil 168, or a combination of these.

[0092] Gaseous effluent 162 may include light gases, such as excess hydrogen, methane, water vapor or other light gases. As previously mentioned, light gases may refer to gases in gaseous form at ambient temperature and pressure. Gaseous effluent 162 may include light gases greater than or equal to 95%, greater than or equal to 97%, or even greater than or equal to 99% from steam cracking effluent 176. Gaseous effluent 162 may be transferred to a gas treatment machine for further processing, such as but not limited to separation and purification of hydrogen, recovery of methane and other hydrocarbon gases, or a combination of these. Hydrogen recovered from gaseous effluent 162 via a gas treatment machine may be recycled back to hydroprocessing unit 110, hydrocracking unit 130, or both as a part of recycled hydrogen 143. As previously mentioned, recycled hydrogen 143 may include hydrogen recovered from both hydrocracking effluent separation system 140 and steam cracking system 160. In some embodiments, the gaseous effluent 162 and the light gases 142 may be passed to the same gas processing machine to produce the recycle hydrogen 143 .

[0093] The olefin effluent 164 may include olefins, such as, but not limited to, ethylene, propylene, butenes (1-butene, cis-2-butene, trans-2-butene, isobutylene or a combination of these), pentenes or other olefins and unsaturated compounds. The olefin effluent 164 may include greater than or equal to 50%, greater than or equal to 80%, greater than or equal to 90%, or even greater than or equal to 95% of the C2-C6 olefins 176 from the steam cracking effluent. The steam cracking effluent 176 may include other constituents, such as, but not limited to, saturated hydrocarbons having a boiling point temperature similar to the C2-C6 olefins. The olefin effluent 164 may be transferred to one or more processing units downstream of the steam cracking effluent separation system 180 to further separate and purify the olefins produced in the steam cracking system 160.

[0094] The aromatic effluent 166 may include one or more aromatic compounds, such as, but not limited to, benzene, toluene, xylenes (o-xylene, m-xylene, p-xylene, or a combination of these), ethylbenzene, other aromatic compounds, or a combination of aromatic compounds. The aromatic effluent 166 may contain greater than or equal to 50%, greater than or equal to 80%, greater than or equal to 90%, or even greater than or equal to 95% of the C6-C8 aromatic compounds (benzene, toluene, xylenes) from the steam cracking effluent 176. The aromatic effluent 166 may be transferred from the system 100 to one or more processing units downstream of the steam cracking effluent separation system 180 to further separate and purify the aromatic compounds in the aromatic effluent 166.

[0095] The pyrolysis oil 168 may include components of the steam cracking effluent 176 having a boiling point temperature greater than or equal to 540° C., such as 540° C. to 720° C. Referring again to Figure 1The pyrolysis oil 168 can be passed back to the system 100 to further convert the hydrocarbons in the pyrolysis oil 168 into an upgraded low-distillation effluent 144. Specifically, the pyrolysis oil 168 can be passed back to the hydrocracking effluent separation system 140, such as back to the fractionator 154 ( Figure 4 ), wherein the pyrolysis oil 168 can be separated into its various constituent components and recycled back through various portions of the system 100. At least a portion of the pyrolysis oil 168 can be passed from the hydrocracking effluent separation system 140 in a high-boiling effluent 148, which can be passed back to the hydroprocessing unit 110 via a high-boiling effluent recycle 149. The high-boiling effluent 148 can include at least 50%, at least 80%, at least 90%, or at least 95% by weight of the pyrolysis oil 168.

[0096] Reference Figure 4 As previously discussed, the middle distillate effluent 146 may be passed from the hydrocracking effluent separation system 140, such as from the fractionator 154 of the hydrocracking effluent separation system 140, to the secondary hydrocracking unit 190. The secondary hydrocracking unit 190 is operable to contact the middle distillate effluent 146 with a hydrocracking catalyst in the presence of hydrogen in the secondary hydrocracking zone 192 under reaction conditions sufficient to cause at least a portion of the hydrocarbons in the middle distillate effluent 146 to undergo hydrocracking to produce a secondary hydrocracking effluent 194 having an increased paraffin concentration compared to the middle distillate effluent 146. The secondary hydrocracking unit 190 can use the system 100 to further increase the yield of olefins, aromatics, or both from the hydrocarbon feed 102 by increasing the conversion of larger hydrocarbons passed to the middle distillate effluent 146 to an upgraded low-boiling effluent 144, which can be passed to the steam cracking system 160. Thus, the secondary hydrocracking unit 190 can increase the conversion of the hydrocarbon feed 102 to the upgraded low-boiling effluent 144, which can result in a further increase in the yield of olefins, aromatics, or both from the system 100.

[0097] The secondary hydrocracking unit 190 may include a hydrocracking catalyst in the secondary hydrocracking zone 192. In the secondary hydrocracking unit 190, larger hydrocarbons, such as but not limited to hydrocarbons having more than 10 carbon atoms, may be converted into smaller, lower-distillation hydrocarbons by contacting the middle distillate effluent 146 with the hydrocracking catalyst in the presence of hydrogen. Specifically, the larger hydrocarbons in the middle distillate effluent 146 may be converted into hydrocarbons having a distillation temperature less than or equal to 180° C. The secondary hydrocracking unit 190 may be any type of reactor capable of operating to contact the middle distillate effluent 146 with the hydrocracking catalyst in the secondary hydrocracking zone 192. Reactors suitable for the secondary hydrocracking unit 190 may include, but are not limited to, fixed bed reactors, moving bed reactors, fluidized bed reactors, plug flow reactors, other types of reactors, or combinations of reactors. For example, the secondary hydrocracking unit 190 may include one or more fixed bed reactors that may be operated in a downflow, upflow, or horizontal flow configuration.

[0098] Hydrogen may be introduced into the secondary hydrocracking unit 190 along with the middle distillate effluent 146. The hydrogen introduced into the secondary hydrocracking unit 190 may be recycled hydrogen 143 recovered from the system 100, such as from the hydrocracking effluent separation system 140, the steam cracking unit 160, or both. The hydrogen may also include make-up hydrogen 104 from an external hydrogen source (not shown). Hydrogen, such as the recycled hydrogen 143, the make-up hydrogen 104, or both, may be passed directly to the secondary hydrocracking unit 190 or combined with the middle distillate effluent 146 upstream of the secondary hydrocracking unit 190.

[0099] Since hydrogen sulfide and ammonia are removed in the hydrocracking effluent separation system 140, the middle distillate effluent 146 can be substantially free of these gases. As used in the present disclosure, the term "substantially free" of a certain component can refer to a composition, stream, catalyst, or reaction zone having less than 0.1% by weight of the component. For example, the middle distillate effluent 146 substantially free of hydrogen sulfide, ammonia, other gases, or gas combinations may include less than 0.1% by weight of hydrogen sulfide, ammonia, other gases, or gas combinations. Compared to the hydrocracking unit 130, the middle distillate effluent 146 substantially free of hydrogen sulfide, ammonia, or both can enable the middle distillate effluent 146 to be processed under less severe conditions in the secondary hydrocracking unit 190. Since the severity of the hydrocracking reaction in the secondary hydrocracking unit 190 is different from the severity of the hydrocracking reaction in the hydrocracking unit 130, the hydrocracking reaction in the secondary hydrocracking unit 190 may be favorable for the hydrogenation and ring opening of polycyclic aromatic compounds, which may further increase the overall yield of olefins, aromatic compounds, or both from the system 100.

[0100] The hydrocracking catalyst in the secondary hydrocracking unit 190 may be any hydrocracking catalyst previously described with respect to the hydrocracking unit 130. The hydrocracking catalyst in the secondary hydrocracking unit 190 may be the same as or different from the hydrocracking catalyst disposed in the hydrocracking zone 132 of the hydrocracking unit 130. In some embodiments, the hydrocracking catalyst in the secondary hydrocracking unit 190 may be different from the hydrocracking catalyst in the hydrocracking unit 130, which may be achieved by the difference in the severity of the operating conditions of the secondary hydrocracking unit 190 compared to the hydrocracking unit 130. The hydrocracking catalyst in the secondary hydrocracking unit 190 may be a solid particulate catalyst capable of promoting or increasing the reaction rate of the cracking reaction of hydrocarbons in the presence of hydrogen. Suitable hydrocracking catalysts may include, but are not limited to, zeolite catalysts. Examples of zeolite catalysts suitable for use as hydrocracking catalysts may include, but are not limited to, Y-type zeolite, REY-type zeolite, USY-type zeolite, RE-USY-type zeolite, mordenite framework inversion (MFI)-type zeolite, beta zeolite, or combinations of these. In one or more embodiments, the hydrocracking catalyst may include a hydrocracking catalyst containing a graded zeolite, such as, but not limited to, graded beta zeolite, graded Y-zeolite, or combinations of these.

[0101] The hydrocracking catalyst in the secondary hydrocracking unit 190 may additionally include one or more metals supported on the surface of the zeolite. The hydrocracking catalyst in the secondary hydrocracking unit 190 may include one or more metals selected from metal elements in Group 6, Group 7, Group 8, Group 9 or Group 10 of the IUPAC periodic table supported on a zeolite or a graded zeolite. Example metals for the hydrocracking catalyst of the secondary hydrocracking unit 190 may include, but are not limited to, molybdenum, cobalt, tungsten, nickel, platinum, palladium, or a combination of these. In one or more embodiments, the hydrocracking catalyst in the secondary hydrocracking unit 190 may include nickel and molybdenum supported on a Y-zeolite or a beta zeolite carrier. In one or more embodiments, the hydrocracking catalyst in the secondary hydrocracking unit 190 may include nickel and tungsten supported on a Y-zeolite or a beta zeolite carrier. In one or more embodiments, the hydrocracking catalyst in the secondary hydrocracking unit 190 may include platinum and palladium supported on a Y-zeolite or a beta zeolite carrier.

[0102] The secondary hydrocracking unit 190 may be operated under conditions sufficient to promote or increase the reaction rate of the hydrocracking reaction to produce a secondary hydrocracking effluent 194 having an increased concentration of smaller, low-boiling hydrocarbons, such as, but not limited to, C2 to C10 paraffins and other hydrocarbons having a boiling point temperature below 180° C. The middle distillate effluent 146 may be contacted with a hydrocracking catalyst in the secondary hydrocracking unit 190 at a hydrocracking temperature and a hydrocracking pressure sufficient to crack at least a portion of the hydrocarbons in the middle distillate effluent 146 to produce smaller, low-boiling hydrocarbons, such as paraffins and other hydrocarbons having a boiling point temperature below or equal to 180° C. Since hydrogen sulfide and ammonia are removed in the hydrocracking effluent separation system 140 upstream of the secondary hydrocracking unit 190, the hydrocracking reaction in the secondary hydrocracking unit 190 may be carried out under milder conditions than the hydrocracking unit 130. The secondary hydrocracking unit 190 may be operated at a hydrocracking temperature of 300° C. to 400° C., such as 300° C. to 475° C. The secondary hydrocracking unit 190 may be operated at a hydrocracking pressure of 50 bar (5,000 kPa) to 200 bar (20,000 kPa), such as 130 bar (13,000 kPa) to 160 bar (16,000 kPa). The secondary hydrocracking unit 190 may be operated at a rate of 0.5 (hr) per hour. -1 ) to 3.0hr -1 (such as 0.6hr -1 To 2.0hr -1 ). The volume ratio of hydrogen introduced into the secondary hydrocracking unit 190 to the hydrocarbons in the middle distillate effluent 146 may be in the range of 1000:1 to 2000:1. The hydrogen may be introduced into the secondary hydrocracking unit 190 at the inlet of the secondary hydrocracking unit 190 or may be combined with the middle distillate effluent 146 upstream of the secondary hydrocracking unit 190.

[0103] refer to Figure 4Contacting the middle distillate effluent 146 with the hydrocracking catalyst in the secondary hydrocracking zone 192 of the secondary hydrocracking unit 190 can cause at least a portion of the hydrocarbons in the middle distillate effluent 146 to undergo hydrocracking to produce a secondary hydrocracking effluent 194. The secondary hydrocracking effluent 194 can have a higher concentration of hydrocarbons having a boiling point temperature of less than or equal to 180° C. compared to the middle distillate effluent 146. The secondary hydrocracking effluent 194 can be transferred to the hydrocracking effluent separation system 140 to separate the low boiling point components into an upgraded low boiling point effluent 144 and other effluent streams. The secondary hydrocracking effluent 194 can be combined with the hydrocracking effluent 134 upstream of the hydrocracking effluent separation system 140 to produce a combined hydrocracking effluent 196. Alternatively or additionally, at least a portion of the secondary hydrocracking effluent 194 may be passed directly to the hydrocracking effluent separation system 140 independently of the hydrocracking effluent 134. The hydrocracking effluent separation system 140 is operable to separate the secondary hydrocracking effluent 194, the hydrocracking effluent 134, or a combination of both into light gas 142, an upgraded low-distillate effluent 144, a middle distillate effluent 146, and a high-distillate effluent 148.

[0104] refer to Figure 4 In operation of the system 100, the hydrocarbon feed 102, the high-boiling-point effluent recycle 149, or both may be passed to a hydroprocessing unit 110 along with hydrogen (recycle hydrogen 143, make-up hydrogen 104, or both). The hydroprocessing unit 110 is operable to hydroprocess the hydrocarbon feed 102 to produce a hydroprocessed effluent 112 having a reduced concentration of one or more of the following: sulfur, nitrogen, metals, polycyclic aromatic compounds, or a combination of these. The hydroprocessed effluent 112 may be passed directly from the hydroprocessing unit 110 to an adsorption unit 120. The adsorption unit 120 is operable to remove at least a portion of asphaltenes, coke precursors, or both from the hydroprocessed effluent 112. In some embodiments, the adsorption unit 120 is operable to remove at least 95% of the asphaltenes from the hydroprocessed effluent 112. The hydroprocessing effluent 112 can be passed from the adsorption unit 120 to a hydrocracking unit 130, which is capable of operating to hydrocrack at least a portion of the hydrocarbons in the hydroprocessing effluent 112 to produce a hydrocracked effluent 134, which can have an increased concentration of hydrocarbons having a distillation temperature below 190° C. compared to the hydroprocessing effluent 112.

[0105] The hydrocracking effluent 134, the secondary hydrocracking effluent 194, or both may be passed to a hydrocracking effluent separation system 140. The hydrocracking effluent separation system 140 is operable to separate the hydrocracking effluent 134, the secondary hydrocracking effluent 194, or both into at least a light gas 142, an upgraded low-boiling effluent 144, a middle distillate effluent 146, and a high-boiling effluent 148. The light gas 142 may be passed to a gas treatment machine to recover hydrogen, which may be recycled back to the hydroprocessing unit 110, the hydrocracking unit 130, or both. The upgraded low-boiling effluent 144 may be passed directly to a steam cracking system 160, which is operable to contact the upgraded low-boiling effluent 144 with steam at a temperature sufficient to thermally crack at least a portion of the upgraded low-boiling effluent 144 to produce olefins, aromatics, or both. The middle distillate effluent 146 may be passed to a secondary hydrocracking unit 190 operable to contact the middle distillate effluent 146 with a secondary hydrocracking catalyst to further convert larger hydrocarbons in the middle distillate effluent 146 to hydrocarbons having a boiling point temperature less than or equal to 180° C. The secondary hydrocracking effluent 194 may be combined with the hydrocracking effluent 134 and passed to the adsorption unit 120, or the secondary hydrocracking effluent 194 may be passed separately and independently to the adsorption unit 120. The high-boiling point effluent 148 may be passed back to the hydroprocessing unit 110 to further upgrade the hydrocarbons in the high-boiling point effluent 148 to hydrocarbons having a boiling point temperature less than or equal to 180° C.

[0106] Reference now Figure 5 , the adsorption unit 120 can be disposed downstream of the hydrocracking unit 130 and between the hydrocracking unit 130 and the hydrocracking effluent separation system 140. The inlet of the adsorption unit 120 can be fluidly coupled to the outlet of the hydrocracking unit 130 so that the hydrocracking effluent 134 can be directly transferred from the hydrocracking unit 130 to the adsorption unit 120. Prior to transferring the hydrocracking effluent 134 to the hydrocracking effluent separation system 140, the adsorption unit 120 can be operated to remove asphaltenes, other coke precursors, or both from the hydrocracking effluent 134. Although Figure 5 Not shown, but the secondary hydrocracking effluent 194 from the secondary hydrocracking unit 190 may also be passed to the adsorption unit 120 or combined with the hydrocracking effluent 134 upstream of the adsorption unit 120.

[0107] exist Figure 5In operation of the system 100 in FIG. 1 , the hydrocarbon feed 102, the high-boiling-point effluent recycle 149, or both may be passed to the hydroprocessing unit 110 along with hydrogen (recycle hydrogen 143, make-up hydrogen 104, or both). The hydroprocessing unit 110 is operable to hydroprocess the hydrocarbon feed 102 to produce a hydroprocessed effluent 112 having a reduced concentration of one or more of the following: sulfur, nitrogen, metals, polycyclic aromatic compounds, or a combination of these. The hydroprocessed effluent 112 may be passed directly from the hydroprocessing unit 110 to the hydrocracking unit 130 without passing through any intervening systems or unit operations that would alter the composition of the hydroprocessed effluent 112. The hydrocracking unit 130 is operable to hydrocrack at least a portion of the hydrocarbons in the hydroprocessing effluent 112 to produce a hydrocracked effluent 134, which may have an increased concentration of hydrocarbons having a boiling point temperature below 190° C. as compared to the hydroprocessing effluent 112. The hydrocracking unit 130 may also include a hydrotreating catalyst and may be operable to further hydrotreat the hydroprocessing effluent 112 prior to contacting the hydroprocessing effluent 112 with the hydrocracking catalyst. The hydrocracking effluent 134, the secondary hydrocracking effluent 194, or both may be passed directly from the hydrocracking unit 130 to the adsorption unit 120. The adsorption unit 120 is operable to remove at least a portion of asphaltenes, coke precursors, or both from the hydrocracking effluent 134, the secondary hydrocracking effluent 194, or both. In some embodiments, the adsorption unit 120 can be operated to remove at least 95% of the asphaltenes from the hydrocracking effluent 134, the secondary hydrocracking effluent 194, or both.

[0108] After the adsorption unit 120, the hydrocracking effluent 134, the secondary hydrocracking effluent 194, or both may be passed to a hydrocracking effluent separation system 140. The hydrocracking effluent separation system 140 is operable to separate the hydrocracking effluent 134, the secondary hydrocracking effluent 194, or both into at least a light gas 142, an upgraded low-distillate effluent 144, a middle distillate effluent 146, and a high-distillate effluent 148. The light gas 142 may be passed to a gas treatment machine to recover hydrogen, which may be recycled back to the hydroprocessing unit 110, the hydrocracking unit 130, or both. The upgraded low-boiling effluent 144 may be passed directly to a steam cracking system 160 operable to contact the upgraded low-boiling effluent 144 with steam at a temperature sufficient to thermally crack at least a portion of the upgraded low-boiling effluent 144 to produce olefins, aromatics, or both. The middle distillate effluent 146 may be passed to a secondary hydrocracking unit 190 operable to contact the middle distillate effluent 146 with a secondary hydrocracking catalyst to further convert larger hydrocarbons in the middle distillate effluent 146 to hydrocarbons having a boiling point temperature of less than or equal to 180° C. The secondary hydrocracking effluent 194 may be combined with the hydrocracking effluent 134 and passed to the adsorption unit 120, or the secondary hydrocracking effluent 194 may be passed to the adsorption unit 120 separately and independently. The high-boiling effluent 148 may be passed back to the hydroprocessing unit 110 to further upgrade the hydrocarbons in the high-boiling effluent 148 to hydrocarbons having a boiling point temperature less than or equal to 180°C.

[0109] Reference now Figure 6 , the adsorption unit 120 can be disposed downstream of the hydrocracking unit 130 and between the high pressure separator 150 and the fractionator 154 of the hydrocracking effluent separation system 140. The inlet of the adsorption unit 120 can be fluidly coupled to the outlet of the high pressure separator 150 so that the high pressure separator liquid effluent 152 can be passed directly from the high pressure separator 150 to the adsorption unit 120. Before passing the high pressure separator liquid effluent 152 to the fractionator 154, the adsorption unit 120 can be operated to remove asphaltenes, other coke precursors, or both from the high pressure separator liquid effluent 152.

[0110] exist Figure 6In the operation of the depicted system 100, the hydrocarbon feed 102, the high-boiling-point effluent recycle 149, or both may be passed to a hydroprocessing unit 110 along with hydrogen (recycle hydrogen 143, make-up hydrogen 104, or both). The hydroprocessing unit 110 is operable to hydroprocess the hydrocarbon feed 102 to produce a hydroprocessed effluent 112 having a reduced concentration of one or more of the following: sulfur, nitrogen, metals, polycyclic aromatic compounds, or a combination of these. The hydroprocessed effluent 112 may be passed directly from the hydroprocessing unit 110 to the hydrocracking unit 130 without passing through any intervening systems or unit operations that would alter the composition of the hydroprocessed effluent 112. The hydrocracking unit 130 is operable to hydrocrack at least a portion of the hydrocarbons in the hydroprocessing effluent 112 to produce a hydrocracked effluent 134, which may have an increased concentration of hydrocarbons having a boiling point temperature below 190° C. as compared to the hydroprocessing effluent 112. The hydrocracking unit 130 may also include a hydrotreating catalyst and may be operable to further hydrotreat the hydroprocessing effluent 112 before contacting the hydroprocessing effluent 112 with the hydrocracking catalyst. The hydrocracking effluent 134, the secondary hydrocracking effluent 194, or both may be passed directly from the hydrocracking unit 130 to the high pressure separator 150. The high pressure separator 150 is operable to separate the hydrocracking effluent 134, the secondary hydrocracking effluent 194, or both into a light gas 142 and a high pressure separator liquid effluent 152. The light gas 142 may be passed to a gas processing machine to recover hydrogen, which may be recycled back to the hydroprocessing unit 110, the hydrocracking unit 130, or both.

[0111] The high pressure separator liquid effluent 152 can be passed directly to the adsorption unit 120. The adsorption unit 120 is operable to remove at least a portion of asphaltenes, coke precursors, or both from the high pressure separator liquid effluent 152. In one or more embodiments, the adsorption unit 120 is operable to remove at least 95% of the asphaltenes from the high pressure separator liquid effluent 152. After the adsorption unit 120, the high pressure separator liquid effluent 152 can be passed to a fractionator 154. The fractionator 154 is operable to separate the high pressure separator liquid effluent 152 into at least an upgraded low distillate effluent 144, a middle distillate effluent 146, and a high distillate effluent 148. The upgraded low-boiling effluent 144 may be passed directly to a steam cracking system 160 operable to contact the upgraded low-boiling effluent 144 with steam at a temperature sufficient to thermally crack at least a portion of the upgraded low-boiling effluent 144 to produce olefins, aromatics, or both. The middle distillate effluent 146 may be passed to a secondary hydrocracking unit 190 operable to contact the middle distillate effluent 146 with a secondary hydrocracking catalyst to further convert larger hydrocarbons in the middle distillate effluent 146 to hydrocarbons having a boiling point temperature of less than or equal to 180° C. The secondary hydrocracking effluent 194 may be combined with the hydrocracking effluent 134 and passed to the high-pressure separator 150, or the secondary hydrocracking effluent 194 may be passed to the high-pressure separator 150 separately and independently. The high-boiling effluent 148 may be passed back to the hydroprocessing unit 110 to further upgrade the hydrocarbons in the high-boiling effluent 148 to hydrocarbons having a boiling point temperature less than or equal to 180°C.

[0112] Reference again Figure 1 , the method of processing the hydrocarbon feed 102 may include hydrotreating the hydrocarbon feed 102 to produce a hydroprocessing effluent 112, wherein the hydroprocessing effluent 112 may include asphaltenes, coke precursors, or both. The method may also include hydrocracking at least a portion of the hydroprocessing effluent 112 to produce a hydrocracked effluent 134. The method may also include adsorbing at least a portion of the asphaltenes, coke precursors, or both from the hydroprocessing effluent 112, the hydrocracked effluent 134, or both, and separating the hydrocracked effluent 134 into at least an upgraded low-boil effluent 144 and a high-boil effluent 148. The method may also include steam cracking the upgraded low-boil effluent 144 to produce olefins, aromatics, or a combination of these.

[0113] Reference again Figure 1, a method for converting a hydrocarbon feed 102 to olefins, aromatic compounds, or a combination of these according to the present disclosure may include contacting the hydrocarbon feed 102 with at least one hydrotreating catalyst in the presence of hydrogen in at least one hydrotreating zone 114, 115, 116, 117. The hydrocarbon feed 102 may include whole crude oil or desalted whole crude oil, and the contacting may remove at least one of metals, sulfur compounds, nitrogen compounds, or a combination of these to produce a hydrotreating effluent 112. The method may also include contacting the hydrotreating effluent 112 with a hydrocracking catalyst in the presence of hydrogen, wherein the contacting with the hydrocracking catalyst causes at least a portion of the hydrocarbons in the hydrotreating effluent 112 to undergo a hydrocracking reaction to produce a hydrocracking effluent 134. The method may also include contacting at least a portion of the hydroprocessing effluent 112, at least a portion of the hydrocracking effluent 134, or both with an adsorbent in the adsorption unit 120, wherein the adsorbent removes at least a portion of asphaltenes, coke precursors, or both from the hydroprocessing effluent 112, the hydrocracking effluent 134, or both. The method can also include passing the hydrocracking effluent 134 to a hydrocracking effluent separation system 140, which is operable to separate the hydrocracking effluent 134 into at least an upgraded low-distillate effluent 144 and a high-distillate effluent 148, and contacting the upgraded low-distillate effluent 144 with steam maintained at a steam cracking temperature in a steam cracking zone, wherein contacting the upgraded low-distillate effluent 144 with steam at the steam cracking temperature causes at least a portion of the upgraded low-distillate effluent 144 to undergo thermal cracking to produce a steam cracking effluent comprising olefins, aromatics, or both.

[0114] Although the present description and examples are provided in the context of whole crude oil or desalted crude oil as the hydrocarbon feed 102, it should be understood that the systems and methods described in the present disclosure can be applied to the conversion of a variety of heavy oils, including but not limited to crude oil, vacuum residue, tar sands, asphalt, atmospheric residue, vacuum gas oil or other heavy oils.

[0115] Example

[0116] Various embodiments of the methods and systems for heavy oil processing will be further illustrated by the following examples. The examples are illustrative in nature and should not be construed as limiting the subject matter of the present disclosure.

[0117] Example 1: Hydroprocessing method for hydroprocessing whole crude oil

[0118] In Example 1, crude oil was hydrotreated in a pilot plant scale hydrotreating unit comprising a HDM catalyst (KFR-22 commercially available from Albemarle), a transition catalyst (KFR-33 commercially available from Albemarle), and a HDS catalyst (KFR-70 commercially available from Albemarle) to reduce the concentrations of metals, sulfur, nitrogen, and aromatic compounds in the crude oil. The hydrotreating unit consisted of a packed tower having a bed of HDM catalyst at the top, a bed of transition catalyst in the middle, and a bed of HDS catalyst at the bottom. The volume ratio of HDM catalyst to transition catalyst to HDS catalyst was 15:15:70. For Example 1, the crude oil was Arabian Light Crude Oil, the properties of which are previously provided in Table 1. The hydrotreating unit was operated at a temperature of 390°C and a pressure of 150 bar. The LHSV was increased from 0.2 h of Run 1A to 1.0 h of Run 1A. -1 Increase to 0.3h for run 1B -1 And to run 1C 0.5h -1 The hydroprocessing effluent was collected from the hydroprocessing unit for Run 1A, Run 1B, and Run 1C, and the properties and composition of the hydroprocessing effluent were analyzed according to the methods shown in Table 2. These properties included the concentration of hydrogen sulfide, the concentration of ammonia, the concentration of methane (C1), the concentration of hydrocarbons having 2 to 4 carbon atoms (C2-C4), the concentration of hydrocarbons having more than 5 carbons and a distillation temperature less than or equal to 180°C (C5-180°C), the concentration of hydrocarbons having a distillation temperature between 180°C and 350°C, the concentration of hydrocarbons having a distillation temperature between 350°C and 540°C, and the concentration of hydrocarbons having a distillation temperature greater than 540°C.

[0119] Table 2

[0120] characteristic method density ASTM D287 API ASTM D287 Carbon content ASTM D5291 Hydrogen content ASTM D5292 Sulfur content ASTM D5453 Nitrogen content ASTM D4629 Asphaltene (aromatics) content ASTM D6560 Micro Carbon Residue (MCR) ASTM D4530 Metal (V, Ni, As) content IP 501 Hg content ASTM D7622 Simulated distillation (distillation point) ASTM D7169 PIONA D5443 Hydrocarbon structure NOISE

[0121] Table 3 provides the operating conditions of the hydroprocessing process of Example 1 and the composition of the hydroprocessing effluent recovered from each of Run 1A, Run 1B, and Run 1C of Example 1.

[0122] Table 3

[0123]

[0124] Example 2: Hydrocracking of the Hydroprocessed Effluent of Example 1

[0125] In Example 2, the hydroprocessing effluent from Run 1A of Example 1 is subjected to hydrocracking in a hydrocracking unit. The hydrocracking unit includes a hydroprocessing zone containing an HDS catalyst (commercially available from Albemarle as KFR-70) and a hydrocracking zone downstream of the hydroprocessing zone and containing a hydrocracking catalyst. The hydrocracking catalyst includes molybdenum and nickel supported on a graded Y-zeolite. The molar ratio of silica (SiO2) to alumina (Al2O3) of the Y-zeolite is 60:1. The graded Y-zeolite is prepared by treating the USY zeolite with an alkaline solution (NaOH or aqueous ammonia) in the presence of a structure directing agent to convert the USY zeolite into a graded Y-zeolite. In Run 2A and Run 2B, the amount of the hydrocracking catalyst was 50 wt% and 30 wt%, respectively, based on the total weight of the HDS and the hydrocracking catalyst in the hydrocracking unit. The hydrocracking unit was operated at a temperature of 390°C, a hydrogen pressure of 150 bar (15,000 kPa) and a 1.0 h -1 The hydrocracking effluent from each of Run 2A and Run 2B was collected and analyzed for composition, and the results are reported in Table 4 below.

[0126] Table 4

[0127] Run 2A Run 2B LHSV(h-1) 1.0 1.0 temperature 390 390 Density(g / cc) 0.771 0.799 Sulfur content (ppmw) 230 287 Nitrogen content (ppmw) <5 3.0 Hydrogen consumption (scfb) 1006 2066 Hydrogen sulfide content (weight %) 2.1 2.08 Ammonia content (weight %) 0.1 0.09 C1 content (weight %) 0.4 0.39 C2 content (weight %) 0.6 0.48 C3 content (weight %) 2.1 1.15 nC4 content (weight %) (normal C4) 3.8 1.34 iC1 content (weight %) (iso C4) 2.7 1.38 Total amount of C1-C4 (wt%) 9.6 4.74 C5-180℃(weight%) 53.3 30.03 180℃-350℃(weight %) 31.7 45.60 350℃-540℃(weight %) 3.2 15.18 >540℃(wt%) 0.0 4.78 Total amount of C5+ hydrocarbons (wt%) 88.1 95.58

[0128] As shown in Table 4, having 50 wt% of the hydrocracking catalyst in the hydrocracking unit causes nearly all of the hydrocarbons having a boiling point temperature above 350° C. in the hydroprocessing effluent to be converted to hydrocarbons having a boiling point temperature below 350° C. This in turn increases the amount of hydrocarbons having a boiling point temperature less than or equal to 180° C. in the hydrocracking effluent compared to the hydroprocessing effluent.

[0129] Example 3: System Modeling Including Hydroprocessing, Hydrocracking, Adsorption, Separation, and Steam Cracking

[0130] Using the composition data from Examples 1 and 2 Figure 4 A method for converting whole crude oil into olefins and aromatic compounds by hydrotreating, hydrocracking, adsorption, separation and steam cracking is modeled. The method is modeled using Aspen 6 modeling software. The method modeled in Example 3 is Figure 4 1 and includes the hydroprocessing unit 110 studied in Example 1, an adsorption unit 120 downstream of the hydroprocessing unit 110, the hydrocracking unit 130 studied in Example 2, the hydrocracking effluent separation system 140, the steam cracking system 160, and the secondary hydrocracking unit 190. The process modeled in Example 3 includes recycling the high distillate effluent 148 back to the hydroprocessing unit 110, hydrocracking the middle distillate effluent 146 in the secondary hydrocracking unit 190, and passing the pyrolysis oil from the steam cracking system 160 back to the hydrocracking effluent separation system 140.

[0131] Figure 4 The modeling of the system 100 in incorporates conversion data from the hydrotreating unit evaluated in Example 1 and the hydrocracking unit evaluated in Example 2. Figure 4 Modeling of system 100 of produces an upgraded low-distillation point effluent 144 (feed to the steam cracking system) having the composition provided in Table 5.

[0132] Table 5

[0133] Composition Weight Percentage (wt%) C1 0.8 C2-C4 hydrocarbons 12.0 C5-180℃ hydrocarbon 89.2

[0134] The steam cracking system includes a steam cracking unit operating at a hydrocarbon flow rate of 3600 gallons per hour (flow rate of upgraded low-distillation effluent), a water / steam flow rate of 3600 gallons per hour, a temperature of 840° C., and an absolute pressure of 1.8 bar (180 kPa absolute). The composition of the steam cracking effluent delivered from the steam cracking unit is provided in Table 6.

[0135] Comparative Example 4: Modeling of a process with hydrotreating, separation and steam cracking only

[0136] In Comparative Example 4, a method for converting whole crude oil into olefins and aromatic compounds by hydrotreating, separation and steam cracking is modeled. The method modeled in Comparative Example 4 includes hydrotreating whole crude oil according to the hydrotreating method evaluated in Example 1. In Comparative Example 4, the hydrotreating effluent is transferred to a separation system, in which the low-distillation effluent upgraded in the separation system is separated and delivered to the steam cracking system. The method of Comparative Example 4 does not include hydrocracking, adsorption, secondary hydrocracking unit 190 of the hydrotreating effluent or recycling the high-distillation effluent back to the hydrotreating unit. The method of Comparative Example 4 also does not include recycling the pyrolysis oil from the steam cracking system back to the separation system. The method of Comparative Example 4 is described in U.S. Patent No. 9,255,230.

[0137] The hydroprocessing unit, separation system and steam cracking system of Comparative Example 4 were operated under the same operating conditions as the hydroprocessing unit, hydrocracking effluent separation system and steam cracking system of Example 3. The steam cracking system operating conditions and the composition of the steam cracking effluent of Comparative Example 4 are provided in Table 6.

[0138] Comparative Example 5: Modeling of a process with hydrotreating, hydrocracking, separation and steam cracking

[0139] In Comparative Example 5, a method for converting whole crude oil into olefins and aromatic compounds by hydrotreating, hydrocracking, separation and steam cracking is modeled. The method modeled in Comparative Example 5 is the same as the method modeled in Comparative Example 4, including a hydrocracking unit disposed downstream of the hydrotreating unit and upstream of the separation system. The hydrocracking method of Example 2 is used as the hydrocracking unit in Comparative Example 5. In addition, the hydrotreating method in Comparative Example 5 is the hydrotreating method evaluated in Example 1. The separation unit and the steam cracking system are operated under the same conditions as in Example 3 and Comparative Example 4. The method of Comparative Example 5 does not include an adsorption unit, a secondary hydrocracking unit 190, recycling of high-distillation-point effluents back to the hydrotreating unit, and recycling of pyrolysis oil from the steam cracking system back to the separation system. The steam cracking system operating conditions and the composition of the steam cracking effluent of Comparative Example 5 are provided in Table 6.

[0140] Example 6: Comparison of Example 3 with Comparative Examples 5 and 6

[0141] The composition of the steam cracking effluent from the process modeled in Example 3 and Comparative Examples 4 and 5 is provided in Table 6 below. The hydroprocessing catalyst and operating conditions of the hydroprocessing unit, separation system, and steam cracking system are the same as in Example 3 and Comparative Examples 5 and 6. The process modeled in Comparative Example 4 includes a hydroprocessing unit, a separation system, and a steam cracking system. Comparative Example 5 adds a hydrocracking unit downstream of the hydroprocessing unit of the process of Comparative Example 4. Example 3 includes Figure 4 The method includes an adsorption unit, a secondary hydrocracking unit, recycling the high-distillation-point effluent of the separation system back to the hydroprocessing unit, and recycling the pyrolysis oil from the steam cracking system back to the separation system. In other words, Example 3 adds an adsorption unit, a secondary hydrocracking unit, a high-distillation-point effluent recycling, and a pyrolysis recycling to the method modeled in Comparative Example 5.

[0142] Table 6

[0143]

[0144] As shown in the results in Table 6, the system of the present disclosure modeled in Example 3 produces higher yields of olefins, such as ethylene, propylene, and butenes, and higher yields of aromatic compounds, such as benzene, toluene, and xylenes, than the systems of Comparative Examples 4 and 5. In addition, the system of Example 3 produces one-sixth of the C10+ compounds in the steam cracker effluent compared to the amount of C10+ constituents in the steam cracking effluent produced in the systems of Comparative Examples 4 and 5. Therefore, the data presented in Table 6 demonstrates that the system of Example 3 upgrades a greater proportion of hydrocarbons from crude oil to olefins and aromatic compounds compared to existing methods for upgrading crude oil and other heavy oils.

[0145] A first aspect of the present disclosure may include a method for upgrading a hydrocarbon feed. The method may include hydrotreating the hydrocarbon feed to produce a hydrotreating effluent, wherein the hydrotreating effluent may contain asphaltenes, coke precursors, or both. The method may also include hydrocracking at least a portion of the hydrotreating effluent to produce a hydrocracking effluent and adsorbing at least a portion of the asphaltenes, coke precursors, or both from the hydrotreating effluent, the hydrocracking effluent, or both. The method may also include separating the hydrocracking effluent into at least an upgraded low-distillation effluent and a high-distillation effluent, and steam cracking the upgraded low-distillation effluent to produce olefins, aromatics, or a combination of these.

[0146] A second aspect of the present disclosure may include the first aspect, further comprising combining the high-distillation effluent with the hydrocarbon feed prior to hydrotreating the hydrocarbon feed.

[0147] A third aspect of the present disclosure may include any of the first aspect or the second aspect, wherein adsorbing at least a portion of the asphaltenes, coke precursors, or both comprises contacting the hydroprocessing effluent with an adsorbent, wherein contacting with the adsorbent causes at least a portion of the asphaltenes, coke precursors, or both to be adsorbed onto the adsorbent.

[0148] A fourth aspect of the present disclosure may include any of the first to third aspects, including adsorbing at least 95 weight percent of asphaltenes, coke precursors, or both from the hydroprocessing effluent.

[0149] A fifth aspect of the present disclosure may include any one of the first to fourth aspects, wherein adsorbing at least a portion of asphaltenes, coke precursors, or both may reduce deactivation of a hydrocracking catalyst during hydrocracking of a hydroprocessing effluent.

[0150] A sixth aspect of the present disclosure may include any one of the first to fifth aspects, comprising separating the hydrocracking effluent into an upgraded low-distillate effluent, a middle distillate effluent, and a high-distillate effluent and contacting the middle distillate effluent with a secondary hydrocracking catalyst in the presence of hydrogen to produce a secondary hydrocracking effluent.

[0151] A seventh aspect of the present disclosure may include the sixth aspect, further comprising combining the secondary hydrocracking effluent with the hydrocracking effluent to produce a combined hydrocracking effluent and separating the combined hydrocracking effluent into an upgraded low-distillate effluent, a middle-distillate effluent, and a high-distillate effluent.

[0152] An eighth aspect of the present disclosure may include any one of the first to seventh aspects, further comprising contacting the high-distillation-point effluent with a hydrocarbon feed and hydrotreating the high-distillation-point effluent and the hydrocarbon feed.

[0153] A ninth aspect of the present disclosure may include any of the first to eighth aspects, wherein the hydroprocessing may include contacting the hydrocarbon feed with at least one hydroprocessing catalyst in the presence of hydrogen in at least one hydroprocessing zone.

[0154] A tenth aspect of the present disclosure may include any one of the first to ninth aspects, wherein the hydroprocessing may remove at least one or more metals, nitrogen compounds, sulfur compounds, or a combination thereof.

[0155] The eleventh aspect of the present disclosure may include any one of the first to tenth aspects, wherein the hydrocracking may include contacting the portion of the hydroprocessing effluent with a hydrocracking catalyst in the presence of hydrogen to produce a hydrocracking effluent. The hydrocracking effluent may have a greater concentration of hydrocarbons having a distillation temperature of less than or equal to 180° C. than the hydroprocessing effluent.

[0156] The twelfth aspect of the present disclosure may include any one of the first to eleventh aspects, including separating the steam cracking effluent into at least one product effluent and a pyrolysis oil effluent, combining the pyrolysis oil effluent with at least a portion of the hydrocracking effluent, and separating the combined pyrolysis oil effluent and hydrocracking effluent into at least an upgraded low-distillation point effluent and a high-distillation point effluent.

[0157] A thirteenth aspect of the present disclosure may include any one of the first to twelfth aspects, wherein the hydrocarbon feed comprises whole crude oil or desalted whole crude oil.

[0158] A fourteenth aspect of the present disclosure may relate to a method for upgrading a hydrocarbon feed. The method may include contacting a hydrocarbon feed with at least one hydrotreating catalyst in the presence of hydrogen in at least one hydrotreating zone. The hydrocarbon feed may include whole crude oil or desalted whole crude oil, and the contact may remove at least one of metals, sulfur compounds, nitrogen compounds, or a combination of these to produce a hydrotreating effluent. The method may also include contacting the hydrotreating effluent with a hydrocracking catalyst in the presence of hydrogen, wherein the contact with the hydrocracking catalyst may cause at least a portion of the hydrocarbons in the hydrotreating effluent to undergo a hydrocracking reaction to produce a hydrocracking effluent. The method may also include contacting at least a portion of the hydrotreating effluent or at least a portion of the hydrocracking effluent with an adsorbent in an adsorption unit. The adsorbent may remove at least a portion of asphaltene, coke precursor, or both from the portion of the hydrotreating effluent or the portion of the hydrocracking effluent. The method may also include passing the hydrocracking effluent to a hydrocracking effluent separation system operable to separate the hydrocracking effluent into at least an upgraded low-distillate effluent and a high-distillate effluent, and contacting the upgraded low-distillate effluent with steam maintained at a steam cracking temperature in a steam cracking zone. Contacting the upgraded low-distillate effluent with steam at a steam cracking temperature may cause at least a portion of the upgraded low-distillate effluent to undergo thermal cracking to produce a steam cracking effluent comprising olefins, aromatic compounds, or both.

[0159] A fifteenth aspect of the present disclosure may include the fourteenth aspect, further comprising passing the high-distillation effluent to at least one hydroprocessing zone.

[0160] A sixteenth aspect of the present disclosure may include any of the fourteenth aspect or the fifteenth aspect, wherein contacting the hydroprocessing effluent or the hydrocracking effluent with an adsorbent in an adsorption unit can remove at least 95 weight percent of asphaltenes, coke precursors, or both from the hydroprocessing effluent or the hydrocracking effluent.

[0161] A seventeenth aspect of the present disclosure may include any one of the fourteenth to sixteenth aspects, wherein contacting the hydroprocessing effluent or the hydrocracking effluent with an adsorbent in an adsorption unit may reduce deactivation of a hydrocracking catalyst during hydrocracking of the hydroprocessing effluent.

[0162] An eighteenth aspect of the present disclosure may include any one of the fourteenth to seventeenth aspects, wherein the hydrocracking effluent may have a higher concentration of hydrocarbons having a distillation point temperature of less than or equal to 180° C. than the hydrotreating effluent.

[0163] A nineteenth aspect of the present disclosure may include any one of aspects fourteen to eighteen, wherein the hydrocracking effluent separation system is operable to separate the hydrocracking effluent into at least an upgraded low distillate effluent, a middle distillate effluent, and a high distillate effluent, and the method may further include contacting the middle distillate effluent with a secondary hydrocracking catalyst in the presence of hydrogen to produce a secondary hydrocracking effluent.

[0164] The twentieth aspect of the present disclosure may include the nineteenth aspect, wherein the secondary hydrocracking effluent may have a higher concentration of hydrocarbons having a distillation point temperature less than or equal to 180° C. than the middle distillate effluent.

[0165] A twenty-first aspect of the present disclosure may include any one of the nineteenth aspect or the twentieth aspect, wherein the secondary hydrocracking catalyst may include at least one metal catalyst supported on Y-zeolite, β-zeolite, or both.

[0166] A twenty-second aspect of the present disclosure may include the twenty-first aspect, wherein the metal catalyst may include at least one metal selected from the group consisting of cobalt, molybdenum, nickel, platinum, palladium, and combinations thereof.

[0167] A twenty-third aspect of the present disclosure may include any of the twenty-first or twenty-second aspects, wherein the Y-zeolite, the β-zeolite, or both include fractionated Y-zeolite, fractionated β-zeolite, or both, respectively.

[0168] A twenty-fourth aspect of the present disclosure may include any one of the nineteenth to twenty-third aspects, further comprising passing the secondary hydrocracking effluent to a hydrocracking effluent separation system.

[0169] A twenty-fifth aspect of the present disclosure may include any one of aspects nineteen to twenty-four, further comprising combining the secondary hydrocracking effluent with the hydrocracking effluent to produce a combined hydrocracking effluent and delivering the combined hydrocracking effluent to a hydrocracking effluent separation system.

[0170] A twenty-sixth aspect of the present disclosure may include any one of the fourteenth to twenty-fifth aspects, wherein the steam cracker effluent may include at least one of ethylene, propylene, butene, or a combination of these.

[0171] A twenty-seventh aspect of the present disclosure may include any one of aspects 14 to 26, wherein the steam cracker effluent may include aromatic compounds comprising at least one of benzene, toluene, xylenes, or a combination of these.

[0172] A twenty-eighth aspect of the present disclosure may include any one of aspects fourteen to twenty-seven, including separating the steam cracking effluent into at least one product effluent and a pyrolysis oil effluent and transferring the pyrolysis oil effluent back to the hydrocracking effluent separation system.

[0173] A twenty-ninth aspect of the present disclosure may include the twenty-eighth aspect, wherein the at least one product effluent may include at least an olefin effluent comprising one or more olefins and an aromatic effluent comprising one or more aromatic compounds.

[0174] A thirtieth aspect of the present disclosure may include any one of the first to twenty-ninth aspects, wherein the adsorbent may include at least one of spherical alumina, clay, metal nanoparticles, or a combination of these.

[0175] A thirty-first aspect of the present disclosure may include any one of the first to thirtieth aspects, further comprising regenerating the adsorbent by contacting the adsorbent with a solvent capable of dissolving asphaltenes, coke precursors, or both.

[0176] A thirty-second aspect of the present disclosure may include any one of the first to thirty-first aspects, wherein the hydrocracking catalyst comprises one or more metals supported on Y-zeolite, beta zeolite, or both.

[0177] A thirty-third aspect of the present disclosure may include the thirty-second aspect, wherein the metal of the hydrocracking catalyst may include at least one of cobalt, molybdenum, nickel, platinum, palladium, or a combination of these.

[0178] A thirty-fourth aspect of the present disclosure may include the thirty-second aspect, wherein the metal of the hydrocracking catalyst may include at least one metal selected from the group consisting of cobalt, molybdenum, nickel, platinum, palladium, or a combination of these.

[0179] A thirty-fifth aspect of the present disclosure may include any one of the thirty-second to thirty-fourth aspects, wherein the Y-zeolite, the β-zeolite, or both include fractionated Y-zeolite, fractionated β-zeolite, or both, respectively.

[0180] The thirty-sixth aspect of the present disclosure may include a system for processing crude oil. The system may include a hydrotreating unit comprising at least one hydrotreating catalyst. The hydrotreating unit is operable to contact the crude oil with the at least one hydrotreating catalyst. Contact with the hydrotreating catalyst can upgrade the crude oil to a hydrotreating effluent having a reduced concentration of at least one of nitrogen, sulfur, metals, aromatic compounds, or a combination thereof. The system may also include a hydrocracking unit disposed downstream of the hydrotreating unit and comprising a hydrocracking catalyst. The hydrocracking unit is operable to contact at least a portion of the hydrotreating effluent with the hydrocracking catalyst under conditions sufficient to convert at least a portion of the hydrotreating effluent to produce a hydrocracking effluent comprising hydrocarbons having a boiling point temperature less than or equal to 180°C. The system may also include an adsorption unit downstream of the hydrotreating unit or the hydrocracking unit. The adsorption unit is operable to contact the hydroprocessing effluent or the hydrocracking effluent with an adsorbent capable of adsorbing asphaltenes, coke precursors, or both from the hydroprocessing effluent or the hydrocracking effluent; the system may also include a hydrocracking effluent separation system downstream of the hydrocracking unit. The hydrocracking effluent separation system is operable to separate at least a portion of the hydrocracking effluent into at least an upgraded low-distillation effluent and a high-distillation effluent. The system may also include a steam cracking system downstream of the hydrocracking effluent separation system. The steam cracking system is operable to convert at least a portion of the upgraded low-distillation effluent to produce olefins, aromatics, or both.

[0181] The thirty-seventh aspect of the present disclosure may include the thirty-sixth aspect, further comprising a high-distillation effluent recycle fluidly coupled to the hydrocracking effluent separation system and the hydroprocessing unit. The high-distillation effluent recycle is operable to transfer the high-distillation effluent from the hydrocracking effluent separation system back to the hydroprocessing unit.

[0182] A thirty-eighth aspect of the present disclosure may include any one of the thirty-sixth aspect or the thirty-seventh aspect, wherein the hydrocracking effluent separation system is operable to separate the hydrocracking effluent into at least an upgraded low-distillate effluent, a high-distillate effluent, and a middle distillate effluent, and the system may further include a secondary hydrocracking unit operable to contact the middle distillate effluent with a secondary hydrocracking catalyst to produce a secondary hydrocracking effluent.

[0183] The thirty-ninth aspect of the present disclosure may include any one of the thirty-sixth to the thirty-eighth aspects, further comprising a pyrolysis oil recycle fluidly coupled to the steam cracking system and the hydrocracking effluent separation system. The pyrolysis oil recycle is operable to transfer the pyrolysis oil effluent from the steam cracking system back to the hydrocracking effluent separation system.

[0184] A fortieth aspect of the present disclosure may include any one of the thirty-sixth to thirty-ninth aspects, wherein the adsorption unit may be disposed between the hydroprocessing unit and the hydrocracking unit.

[0185] A forty-first aspect of the present disclosure may include any one of the thirty-sixth to fortieth aspects, wherein the adsorption unit may be disposed downstream of the hydrocracking unit.

[0186] A forty-second aspect of the present disclosure may include any one of the thirty-sixth to forty-first aspects, wherein the adsorption unit may be disposed between the hydrocracking unit and the hydrocracking effluent separation system.

[0187] A forty-third aspect of the present disclosure may include any one of the thirty-sixth to forty-second aspects, wherein the hydrocracking effluent separation system may include at least a high-pressure separator and a fractionator located downstream of the high-pressure separator.

[0188] A forty-fourth aspect of the present disclosure may include the forty-third aspect, wherein the adsorption unit may be disposed between the high-pressure separator and the fractionator.

[0189] A forty-fifth aspect of the present disclosure may include any one of the thirty-sixth to forty-fourth aspects, wherein the adsorption unit may include a plurality of adsorption zones connected in parallel.

[0190] A forty-sixth aspect of the present disclosure may include any one of the thirty-sixth to forty-fifth aspects, wherein the adsorbent may comprise spherical alumina, clay, metal nanoparticles, or a combination of these.

[0191] A forty-seventh aspect of the present disclosure may include any one of aspects thirty-six to forty-six, wherein the hydroprocessing unit comprises a plurality of hydroprocessing zones connected in series.

[0192] A forty-eighth aspect of the present disclosure may include any one of aspects thirty-six to forty-seven, wherein the hydroprocessing catalyst may comprise at least one of a desulfurization catalyst, a transition catalyst, a denitrification catalyst, a demetallization catalyst, a dearomatization catalyst, or a combination of these.

[0193] The forty-ninth aspect of the present disclosure may include any one of aspects 36 to 48, wherein the hydroprocessing unit may include a desulfurization reaction zone comprising a desulfurization catalyst, a transition reaction zone comprising a transition catalyst, and a demetallization reaction zone comprising a demetallization catalyst.

[0194] A fiftieth aspect of the present disclosure may include any one of the thirty-sixth to forty-ninth aspects, wherein the hydrocracking catalyst comprises a metal supported on a zeolite.

[0195] The fifty-first aspect of the present disclosure may include the fiftieth aspect, wherein the metal of the hydrocracking catalyst may include at least one of cobalt, molybdenum, nickel, platinum, palladium, or a combination of these, and the zeolite includes graded Y-zeolite, graded β-zeolite, or both.

[0196] A fifty-second aspect of the present disclosure may include any one of aspects thirty-six to fifty-one, wherein the hydrocracking unit may include a supplemental hydroprocessing zone upstream of the hydrocracking zone and comprising a hydroprocessing catalyst.

[0197] A fifty-third aspect of the present disclosure may include any one of aspects thirty-six to fifty-second, wherein the steam cracking system may include a steam cracking unit and a steam cracking effluent separation system.

[0198] A fifty-fourth aspect of the present disclosure may include the fifty-third aspect, wherein the steam cracking unit is operable to contact the upgraded low-distillation effluent with steam at a steam cracking temperature of 700 degrees Celsius to 900 degrees Celsius to produce a steam cracking effluent.

[0199] A fifty-fifth aspect of the present disclosure may include any of the fifty-third aspect or the fifty-fourth aspect, wherein the steam cracking effluent separation system is operable to separate the steam cracking effluent into at least one product effluent and a pyrolysis petroleum effluent.

[0200] A fifty-sixth aspect of the present disclosure may include the fifty-fifth aspect, wherein the at least one product effluent may comprise at least one olefin effluent, at least one aromatic compound effluent, or both.

[0201] It should be noted that one or more of the following claims utilize the term "wherein" as a transitional term. For purposes of defining the present technology, it should be noted that this term is introduced in the claims as an open transitional phrase that is used to introduce a recitation of a series of features of a structure and should be interpreted in a manner similar to the more commonly used open-ended term "comprising."

[0202] It should be understood that any two quantitative values ​​assigned to a property may form a range for that property, and that all combinations of ranges formed by all of the stated quantitative values ​​for a given property are contemplated in the present disclosure.

[0203] The subject matter of the present disclosure has been described in detail and with reference to specific embodiments, it should be noted that the various details described in the present disclosure should not be considered to imply that these details relate to elements that are essential components of the various embodiments described in the present disclosure, even where specific elements are shown in each of the drawings accompanying the description of the present disclosure. Rather, the appended claims should be considered the only indication of the scope of the present disclosure and the corresponding scope of the various embodiments described in the present disclosure. In addition, it is apparent that modifications and changes can be made without departing from the scope of the appended claims.

Claims

1. A method for upgrading a hydrocarbon feed, the method comprising: hydrotreating the hydrocarbon feed in a hydrotreating unit to produce a hydrotreated effluent, wherein the hydrocarbon feed comprises whole crude oil or desalted whole crude oil and the hydrotreated effluent comprises asphaltenes, coke precursors, or both; hydrocracking at least a portion of the hydroprocessing effluent in a hydrocracking unit downstream of the hydroprocessing unit to produce a hydrocracked effluent; adsorbing at least a portion of the asphaltenes, coke precursors, or both from the hydroprocessing effluent, the hydrocracking effluent, or both, wherein the adsorption occurs at a temperature of 350° C. to 420° C. and a pressure of 5,000 kPa to 20,000 kPa; Separating the hydrocracking effluent into at least an upgraded low-distillation-point effluent and a high-distillation-point effluent; as well as The upgraded low-end effluent is steam cracked to produce olefins, aromatics, or a combination of these.

2. The method of claim 1, wherein adsorbing the at least a portion of the asphaltenes, coke precursors, or both comprises contacting the hydroprocessing effluent with an adsorbent, wherein contacting the adsorbent causes adsorption of at least a portion of the asphaltenes, coke precursors, or both onto the adsorbent.

3. The method of claim 2, wherein the adsorbent comprises at least one of spherical alumina, clay, metal nanoparticles, or a combination of these.

4. The method of claim 2, further comprising regenerating the adsorbent by contacting the adsorbent with a solvent capable of dissolving asphaltenes, coke precursors, or both.

5. The method according to any one of claims 1 to 4, comprising: separating the hydrocracking effluent into the upgraded low-distillation-point effluent, the middle distillation effluent and the high-distillation-point effluent; as well as The middle distillate effluent is contacted with a secondary hydrocracking catalyst in the presence of hydrogen to produce a secondary hydrocracking effluent.

6. The method of claim 5, further comprising combining the secondary hydrocracking effluent with the hydrocracking effluent to produce a combined hydrocracking effluent and separating the combined hydrocracking effluent into the upgraded low-distillate effluent, the middle distillate effluent, and the high-distillate effluent.

7. The process according to any one of claims 1 to 4, further comprising contacting the high-boiling effluent with the hydrocarbon feed and hydrotreating the high-boiling effluent and the hydrocarbon feed.

8. The process of any one of claims 1 to 4, wherein hydroprocessing comprises contacting the hydrocarbon feed with at least one hydroprocessing catalyst in the presence of hydrogen in at least one hydroprocessing zone, wherein the hydroprocessing removes at least one or more metals, nitrogen compounds, sulfur compounds, or a combination of these compounds from the hydrocarbon feed.

9. The method according to any one of claims 1 to 4, comprising: separating the steam cracking effluent into at least one product effluent and a pyrolysis oil effluent; combining the pyrolysis oil effluent with at least a portion of the hydrocracking effluent; as well as The combined pyrolysis oil effluent and hydrocracking effluent are separated into at least the upgraded low-distillation effluent and the high-distillation effluent.

10. The method according to claim 1, further comprising: passing the hydroprocessing effluent directly from the hydroprocessing unit to the hydrocracking unit; or The hydroprocessing effluent is passed directly from the hydroprocessing unit to an adsorption unit to adsorb at least a portion of asphaltenes, coke precursors, or both, and the hydroprocessing effluent is passed directly from the adsorption unit to the hydrocracking unit.

11. A system for processing crude oil, the system comprising: a hydroprocessing unit comprising at least one hydroprocessing catalyst, the hydroprocessing unit being operable to contact the crude oil with the at least one hydroprocessing catalyst, wherein contact with the hydroprocessing catalyst upgrades the crude oil into a hydroprocessing effluent having a reduced concentration of at least one of: nitrogen, sulfur, metals, aromatic compounds, or a combination of these; a hydrocracking unit disposed downstream of the hydrotreating unit and comprising a hydrocracking catalyst, the hydrocracking unit being operable to contact at least a portion of the hydrotreating effluent with the hydrocracking catalyst under conditions sufficient to convert at least a portion of the hydrotreating effluent to produce a hydrocracking effluent comprising hydrocarbons having a boiling point temperature less than or equal to 180° C.; an adsorption unit downstream of the hydroprocessing unit or the hydrocracking unit, the adsorption unit being operable to contact the hydroprocessing effluent or the hydrocracking effluent with an adsorbent capable of adsorbing asphaltenes, coke precursors, or both from the hydroprocessing effluent or the hydrocracking effluent, wherein the adsorption unit is operated at a temperature of 350° C. to 420° C. and a pressure of 5,000 kPa to 20,000 kPa; a hydrocracking effluent separation system downstream of the hydrocracking unit, the hydrocracking effluent separation system being operable to separate at least a portion of the hydrocracking effluent into at least an upgraded low-distillation effluent and a high-distillation effluent; a steam cracking system downstream of the hydrocracking effluent separation system, the steam cracking system operable to convert at least a portion of the upgraded low-boil effluent to produce olefins, aromatics, or both; and A high effluent recycle is fluidly coupled to the hydrocracking effluent separation system and the hydroprocessing unit, the high effluent recycle being operable to transfer the high effluent from the hydrocracking effluent separation system back to the hydroprocessing unit.

12. The system of claim 11, wherein the hydrocracking effluent separation system is operable to separate the hydrocracking effluent into at least the upgraded low-distillate effluent, the high-distillate effluent, and a middle distillate effluent, and the system further comprises a secondary hydrocracking unit operable to contact the middle distillate effluent with a secondary hydrocracking catalyst to produce a secondary hydrocracking effluent.

13. The system of claim 11 or 12, further comprising a pyrolysis oil recycle fluidly coupled to the steam cracking system and the hydrocracking effluent separation system, the pyrolysis oil recycle operable to transfer pyrolysis oil effluent from the steam cracking system back to the hydrocracking effluent separation system.

14. The system according to claim 11 or 12, wherein the adsorption unit is disposed between the hydroprocessing unit and the hydrocracking unit or downstream of the hydrocracking unit.

15. The system of claim 11 or 12, wherein the hydroprocessing unit comprises: a desulfurization reaction zone comprising a desulfurization catalyst; a transition reaction zone comprising a transition catalyst; and A demetallation reaction zone comprises a demetallation catalyst.

16. The system of claim 11 or 12, wherein the hydrocracking effluent separation system comprises a high pressure separator and a fractionator located downstream of the high pressure separator.

17. The system of claim 16, wherein the adsorption unit is disposed between the high-pressure separator and the fractionator and an inlet of the adsorption unit is fluidly coupled to an outlet of the high-pressure separator.

18. The system of claim 11, wherein: The hydrocracking unit is located directly downstream of the hydrotreating unit; or The adsorption unit is located directly downstream of the hydrotreating unit and the hydrocracking unit is located directly downstream of the adsorption unit.

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