Process for hydrotreating and cracking crude oil

Abstract

In accordance with at least one aspect of the present disclosure, a method for treating a crude oil having an API between 30 degrees and 35 degrees includes contacting the crude oil with one or more hydrotreating catalysts to produce a hydrotreated effluent. The hydrotreated effluent is delivered to a HS-FCC unit where the hydrotreated effluent is contacted with a cracking catalyst composition comprising a nano-ZSM-5 zeolite and an ultra-stable Y-type zeolite (USY zeolite) to form a cracked effluent comprising at least one product. The HS-FCC catalyst composition further comprises a nano-ZSM-5 zeolite having an average particle size of 0.01 [mu] m to 0.2 [mu] m, a USY zeolite impregnated with lanthanum, an alumina binder, colloidal silica, and a matrix material comprising kaolin. The cracked effluent comprises at least an olefin, an aromatic compound, or both.

Description

[0001] Cross - reference to related applications

[0002] This application claims the benefit of U.S. Patent Application Serial No. 18 / 064,488, filed Dec. 12, 2022, the entire disclosure of which is incorporated herein by reference. TECHNICAL FIELD

[0003] The present disclosure relates to methods for processing petroleum-based materials, and in particular to systems and methods for processing petroleum-based materials (such as crude oil) by hydrotreating and high-severity fluid catalytic cracking to form chemical products and intermediates (such as olefins and aromatics). BACKGROUND ART

[0004] The growing global demand for chemical intermediates such as light olefins remains a major challenge for many integrated refineries. In particular, the production of some valuable light olefins, such as ethylene and propylene, has attracted increasing attention because pure olefin streams are considered to be the basic materials for polymer synthesis. The production of light olefins depends on several process variables, such as feed type, operating conditions, and catalyst type. These compounds can be produced by high-severity fluid catalytic cracking (HS-FCC) of petroleum gases and distillates (such as naphtha, kerosene, or even gas oil) in the presence of an HS-FCC catalyst. FCC carried out under high-severity conditions has shown the potential to convert low-value refinery streams into high-value chemical intermediates. However, the feedstocks available for high-severity fluid catalytic cracking (HS-FCC) methods are limited and must be obtained through expensive and energy-intensive refining steps. For example, methods of fractionating the feedstock prior to HS-FCC rely on energy-intensive steam cracking to process the lighter fractions, which is an expensive method with little control in the production of the desired products. Although crude oil can be a potential feedstock, the concentrations of metals, nitrogen, and sulfur in crude oil can cause deactivation of the HS-FCC catalyst. In addition, it is extremely difficult to effectively crack feedstocks with a wide boiling range (such as crude oil) on a single HS-FCC catalyst. SUMMARY OF THE INVENTION

[0005] Accordingly, there is a continuing need for methods for upgrading crude oil feeds (such as Arabian Medium crude oil) to produce olefins with higher light olefin selectivity and yield compared to conventional methods for cracking hydrocarbon feeds.

[0006] Embodiments of the present disclosure meet this need for improved crude oil upgrading by utilizing a hydrotreating unit and a high-severity fluid catalytic cracking (HS-FCC) unit downstream of the hydrotreating unit. The hydrotreating unit is operable to hydrotreat a crude oil feed by contacting the crude oil feed with a hydrodemetallization (HDM) catalyst, a hydrodesulfurization (HDS) catalyst, and a hydrodearomatization (HDA) catalyst to form a hydrotreated effluent. The hydrotreated effluent is delivered from the hydrotreating unit to the HS-FCC unit to form a cracked effluent, wherein the hydrotreated effluent is contacted with an HS-FCC catalyst comprising nano-ZSM-5 zeolite and ultrastable Y zeolite, wherein the nano-ZSM-5 zeolite has an average particle size of 0.01 micrometers (μm) to 0.2 μm. When fluid catalytic cracking hydrotreated crude oil (e.g., hydrotreated Arab Medium), adding these different zeolite components can improve the selectivity and yield of light olefins. In addition, the reduction in the size of the nano-ZSM-5 zeolite can reduce coke formation and pore diffusion on the HS-FCC catalyst composition. The HS-FCC catalyst composition can also exhibit a reduced deactivation rate, which can improve the economics of light olefin production and other characteristics.

[0007] According to at least one aspect of the present disclosure, a method for upgrading crude oil includes contacting the crude oil with an HDM catalyst, an HDS catalyst, and an HDA catalyst under conditions operable to hydrotreat the crude oil to form a hydrotreated effluent. The crude oil has an American Petroleum Institute (API) gravity of 30 degrees to 35 degrees. The hydrotreated effluent can be contacted with an HS-FCC catalyst composition in a high-severity fluid catalytic cracking (HS-FCC) unit at a temperature of greater than or equal to 580 °C, a weight ratio of HS-FCC catalyst to crude oil of 2:1 to 10:1, and a residence time of 0.1 second to 60 seconds, wherein the HS-FCC catalyst can comprise ultrastable Y zeolite (USY zeolite) impregnated with lanthanum, nano-ZSM-5 zeolite impregnated with phosphorus (wherein the nano-ZSM-5 zeolite can have an average particle size of 0.01 μm to 0.2 μm), an alumina binder, colloidal silica, and a matrix material comprising kaolin, and the contacting can cause at least a portion of the hydrocarbons in the crude oil to undergo cracking reactions to produce a cracked effluent.

[0008] Additional features and advantages of the techniques described in this disclosure will be set forth in the detailed description below, and in part, will be readily apparent to those skilled in the art from the description, or can be learned by practicing the techniques described in this disclosure, including the following detailed description, the claims, and the drawings.

[0009] Brief description of the drawings

[0010] The following detailed description of specific embodiments of the present disclosure may be best understood when read in conjunction with the following accompanying drawings, in which like structures are represented by like reference numerals, and in which:

[0011] Figure 1 A schematic overview of an embodiment of a crude oil upgrading system including a hydrotreating unit and a high-severity fluid catalytic cracking (HS-FCC) unit, according to one or more embodiments described in the present disclosure;

[0012] Figure 2 A schematic overview of Figure 1 the crude oil upgrading system according to one or more embodiments described in the present disclosure, wherein the hydrotreating unit includes HDM catalyst, HDS catalyst, and HDA catalyst in separate catalyst zones disposed within a single reactor;

[0013] Figure 3 A schematic overview of another embodiment of a crude oil upgrading system according to one or more embodiments described in the present disclosure, wherein the hydrotreating unit includes HDM catalyst and HDS catalyst in a first reactor, and HDA catalyst in a second reactor downstream of the first reactor;

[0014] Figure 4 A schematic overview of another embodiment of a crude oil upgrading system according to one or more embodiments described in the present disclosure, wherein the hydrotreating unit includes HDM catalyst, HDS catalyst, and HDA catalyst in separate reactors arranged in series; and

[0015] Figure 5 A schematic overview of a Figure 2 crude oil upgrading system according to one or more embodiments described in the present disclosure, including a separation unit disposed downstream of the HS-FCC unit.

[0016] For purposes of describing Figures 1 - 5 the simplified schematic illustration and description, many valves, temperature sensors, electronic controllers, etc., which are available to and well known to those of ordinary skill in the art in certain chemical processing operations, are not included. In addition, the accompanying components that are typically included in chemical processing operations, such as refineries, such as, for example, air supply devices, catalyst hoppers, flue gas treatment, or other related systems, are not shown. It should be understood that these components are within the spirit and scope of the embodiments of the present disclosure. However, operating components such as those described in the present disclosure may be added to the embodiments described in the present disclosure.

[0017] It should also be noted that the arrows in the drawings refer to process flows. However, the arrows can equivalently refer to transmission lines, which can be used to transmit process flows between two or more system components. Additionally, the arrows connected to system components define the inlets or outlets in each given system component. The arrow direction generally corresponds to the main direction of movement of the material of the flow contained within the physical transmission line as indicated by the arrow. Furthermore, arrows that do not connect two or more process components represent product streams leaving the indicated process or process inlet streams entering the indicated process. The product streams can be further processed in an accompanying chemical processing system or can be commercialized as end products. The process inlet streams can be streams transmitted from an accompanying chemical process or can be unprocessed feed streams. Some arrows can represent recycle streams, i.e., the effluent streams of system components that are recycled back into the system. However, it should be understood that in some embodiments, any represented recycle stream can be replaced by a process inlet stream of the same material, and a portion of the recycle stream can leave the process as a product.

[0018] In addition, the arrows in the drawings can schematically show the process steps of transporting a flow from one process component to another. For example, an arrow pointing from one process component to another can represent "delivering" the effluent of a system component to another system component, which can include the contents of the process flow "leaving" or being "removed" from one process component and the contents of the product stream being "introduced" into another process component.

[0019] It should be understood that when two or more lines intersect in a schematic flow diagram of Figures 1 - 5 two or more process flows "mix" or "merge". Mixing or merging can also include mixing by directly introducing two flows into the same (like) reactor, separation device, or other process component. For example, it should be understood that when two flows are shown as being directly merged before entering a separation unit or reactor, in some embodiments, these flows can equivalently be introduced into the separation unit or reactor and mixed in the reactor.

[0020] Reference will now be made in more detail to various embodiments, some of which are shown in the drawings. Whenever possible, the same reference numbers will be used throughout the drawings to refer to the same or similar parts. Detailed Description

[0021] The present disclosure relates to methods for upgrading crude oil, such as Arab Medium crude oil. According to at least one aspect of the present disclosure, a method for upgrading crude oil includes contacting the crude oil with an HDM catalyst, an HDS catalyst, and an HDA catalyst under conditions operable to hydrotreat the crude oil to form a hydrotreated effluent. The crude oil has an American Petroleum Institute (API) gravity of 30 to 35 degrees. The hydrotreated effluent can be contacted with an HS-FCC catalyst composition in a high severity fluid catalytic cracking (HS-FCC) unit at a temperature of greater than or equal to 580 °C, a weight ratio of HS-FCC catalyst to crude oil of 2:1 to 10:1, and a residence time of 0.1 second to 60 seconds, wherein the HS-FCC catalyst can include ultrastable Y zeolite (USY zeolite) impregnated with lanthanum, nano-ZSM-5 zeolite impregnated with phosphorus (wherein the nano-ZSM-5 zeolite can have an average particle size of 0.01 μm to 0.2 μm), an alumina binder, colloidal silica, and a matrix material comprising kaolin, and the contacting can cause at least a portion of the hydrocarbons in the crude oil to undergo cracking reactions to produce a cracked effluent.

[0022] The methods of the present disclosure enable the crude oil to be used as a feedstock for producing light olefins and other chemical products by high severity fluid catalytic cracking. Hydrotreating of the crude oil can remove metals, sulfur, nitrogen, and aromatic compounds that can cause cracking catalyst deactivation under high severity conditions. Thus, the methods of the present disclosure can improve the efficiency of HS-FCC-based processes by reducing catalyst deactivation and reducing the need to add make-up catalyst. The methods of the present disclosure can also enable crude oil and other heavy oils to be introduced directly into the process without upstream separation processes, such as fractionation towers, which can be costly to construct and operate. Additionally, the methods of the present disclosure can convert crude oil directly to light olefins without using steam cracking, which is energy intensive and provides very little control over the ratio of ethylene to propylene in the steam cracker effluent.

[0023] As used in the present disclosure, "catalyst" refers to any substance that increases the rate of a specific chemical reaction. The catalysts described in the present disclosure can be used to facilitate various reactions, such as but not limited to hydrodemetallization, hydrodesulfurization, hydrodenitrogenation, hydrodearomatization, cracking, fluid catalytic cracking, aromatic cracking, or combinations thereof.

[0024] As used in the present disclosure, the term "spent catalyst" refers to a catalyst that has been contacted with reactants under reaction conditions but has not yet been regenerated in a regenerator. A "spent catalyst" can have coke deposited on the catalyst and can include partially coked catalysts as well as fully coked catalysts. The amount of coke deposited on a "spent catalyst" can be greater than the amount of coke remaining on the regenerated catalyst after regeneration. A "spent catalyst" can also include a catalyst that has a reduced temperature due to contact with reactants (compared to the catalyst before contact with reactants).

[0025] As used in this disclosure, the term "regenerated catalyst" refers to a catalyst that contacts reactants under reaction conditions and is then regenerated in a regenerator to heat the catalyst to a higher temperature, oxidize and remove at least a portion of the coke from the catalyst to restore at least a portion of the catalytic activity of the catalyst, or both. Compared to the spent catalyst, the "regenerated catalyst" may have less coke, a higher temperature, or both, and may have greater catalytic activity compared to the spent catalyst. Compared to a freshly made catalyst that has not passed through a cracking reaction zone and a regenerator, the "regenerated catalyst" may have more coke and less catalytic activity.

[0026] As used in this disclosure, the term "deactivated catalyst" refers to a catalyst that has lost its function and is different from a spent catalyst in that a deactivated catalyst generally cannot be regenerated in a regenerator during steady-state operation of a regeneration system. A deactivated catalyst can be deactivated by contaminants and / or metals in the hydrocarbon feed or steam feed deposited on the surface of the catalyst.

[0027] As used in this disclosure, the term "crude oil" refers to a mixture of petroleum liquids and gases, including impurities such as sulfur-containing compounds, nitrogen-containing compounds, and metal compounds that are directly extracted from subterranean formations or received from a desalting unit without any fractions (such as naphtha) separated by distillation.

[0028] As used in this disclosure, the term "directly" means delivering a material (such as an effluent) from a first component of the crude oil upgrading system 100 to a second component of the crude oil upgrading system 100 without passing the material through any intermediate component or process operable to change the composition of the material. Similarly, the term "directly" also means introducing a material (such as a feed) into a component of the crude oil upgrading system 100 without passing the material through any preliminary component operable to change the composition of the material. Intermediate or preliminary components or systems operable to change the composition of the material may include reactors and separators, but generally are not intended to include heat exchangers, valves, pumps, sensors, or other auxiliary components required to operate a chemical process. Additionally, combining two streams together upstream of a second component rather than delivering each stream separately to the second component is not considered an intermediate or preliminary component operable to change the composition of the material.

[0029] As used in this disclosure, "reactor" refers to any vessel, container, etc., in which one or more chemical reactions may optionally occur between one or more reactants in the presence of one or more catalysts. For example, a reactor may include a tank or tubular reactor configured 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" may be provided within the reactor. As used in this disclosure, "reaction zone" refers to the region within the reactor where a specific reaction occurs. For example, a packed bed reactor having multiple catalyst beds may have multiple reaction zones, where each reaction zone is defined by the region of each catalyst bed.

[0030] As used in this disclosure, "separation unit" refers to any separation device that at least partially separates one or more chemicals in a mixture from each other. For example, a separation unit may 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 columns, flash tanks, separation drums, separation vessels, centrifuges, filtration devices, traps, scrubbers, expansion devices, membranes, solvent extraction devices, etc. It should be understood that the separation methods described in this disclosure may not completely separate all of one chemical component from all of another chemical component. It should be understood that the separation methods described in this disclosure "at least partially" separate different chemical components from each other, and even if not explicitly stated, it should be understood that separation may include only partial separation. As used in this disclosure, one or more chemical components may be "separated" from a process stream to form a new process stream. Typically, a process stream may enter a separation unit and be split or separated into two or more process streams of desired composition. Additionally, in some separation processes, "light fractions" and "heavy fractions" may leave the separation unit separately. Generally, the light fraction stream has a lower boiling point than the heavy fraction stream. Additionally, it should be understood that where only one separation unit is shown or described in a figure, two or more separation units may be used to perform the same or substantially the same separation. For example, in the case of a distillation column described as having multiple outlets, it may be considered that several separators arranged in series may equally separate the feed stream, and such embodiments are within the scope of the embodiments described in this disclosure.

[0031] As used in this disclosure, the term "effluent" may refer to the stream delivered from a reactor, reaction zone, or separation unit after a particular reaction or separation. Typically, the effluent has a different composition from the stream entering the separation unit, reactor, or reaction zone. It should be understood that when the effluent is delivered to another system unit, only a portion of the process stream may be delivered. For example, a slip stream may carry away some of the effluent, meaning only a portion of the effluent may enter the downstream process unit. The term "reaction effluent" may be used more specifically to refer to the stream delivered from a reactor or reaction zone.

[0032] As used in this disclosure, the term "high severity conditions" refers to the operating conditions of a fluid catalytic cracking system (such as the crude oil upgrading system 100), which include: a temperature greater than or equal to 580 °C or from 580 °C to 750 °C, a catalyst-to-oil ratio greater than or equal to 1:1 or from 1:1 to 60:1, and a residence time less than or equal to 60 seconds or from 0.1 seconds to 60 seconds, where each condition may be more severe than the typical operating conditions of a fluid catalytic cracking system.

[0033] As used in this disclosure, the term "catalyst-to-oil ratio" or "CTO" refers to the weight ratio of a catalyst (such as the HS-FCC catalyst composition 125 of the HS-FCC unit 120) to a process stream containing hydrocarbons (such as the hydrotreated effluent 103 delivered to the HS-FCC unit 120).

[0034] The term "residence time" refers to the amount of time that reactants (such as the hydrocarbons in the hydrotreated effluent 103 delivered to the HS-FCC unit 120) are in contact with a catalyst under reaction conditions (such as at the reaction temperature).

[0035] As used in this disclosure, the term "particle size" refers to the maximum length of a particle measured along the longest distance of the particle from one side to the other. The "average particle size" is the average of the particle sizes of a sampled particle population. For spherical particles, the average particle size is equal to the average particle diameter of the spherical particles determined by electron microscopy.

[0036] As used in this disclosure, "cracking" generally refers to a chemical reaction in which a molecule having a carbon-carbon bond is broken into more than one molecule by the breaking of one or more carbon-carbon bonds; in which a compound including a cyclic moiety (such as an aromatic hydrocarbon) is converted into a compound not including a cyclic moiety; or in which 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 calling a catalyst for a particular function does not render the catalyst incapable of having catalytic activity for other functions.

[0037] It should be understood that the catalyst - promoted reactions described in the present disclosure can remove chemical components (such as only a part of the chemical components) from the process stream. For example, the HDM catalyst can be present in an amount sufficient to promote a reaction for removing a part of one or more metals from the process stream. The hydrodenitrogenation (HDN) catalyst can be present in an amount sufficient to promote a reaction for removing a part of the nitrogen present in the process stream. The HDS catalyst can be present in an amount sufficient to promote a reaction for removing a part of the sulfur present in the process stream. Additionally, the HDA catalyst, such as a hydrocracking catalyst, can be present in an amount sufficient to promote a reaction for converting aromatics that are difficult to crack in the HS - FCC unit into naphthalene, paraffinic compounds, or both that are more easily cracked in the HS - FCC unit. It should be understood that throughout the present disclosure, when a particular catalyst is referred to as having a particular function, its function may not be limited to the removal, conversion, or cracking of a particular chemical component or part. For example, a catalyst considered to be an HDN catalyst in the present disclosure may additionally provide a hydrodearomatization function, a hydrodesulfurization function, or both.

[0038] It should be further understood that a stream can be named according to the components of the stream, and the component used to name the stream can be the main component of the stream (such as 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 containing a component is disclosed as being delivered from one process component to another process component, the said component of the stream is disclosed as being delivered from the one process component to the other process component. For example, the disclosure of delivering a "hydrogen stream" to a first process component or from a first process component to a second process component should be understood as equivalently disclosing delivering "hydrogen" to the first process component or from the first process component to the second process component.

[0039] The composition of the feed stream and the processing variables of the FCC process play an important role in the reaction yields and heat balance within the system. Conventional FCC processes may require expensive refining to produce a suitable feed stream. Such additional expensive refining can include separating and treating one or more fractions of the hydrocarbon feedstock before introducing the refined conventional feed into the FCC process. These additional processing steps are energy - intensive and reduce the amount of viable feed from existing hydrocarbon sources. Previous processes have been developed to directly convert crude oil into higher - value chemical products and intermediates through catalytic cracking in an attempt to overcome these limitations, such as by reducing or eliminating the processing steps required to produce a suitable hydrocarbon feed before introducing it into the FCC process. However, contaminants, metals, or both present in heavy hydrocarbon feeds (such as crude oil) can deactivate the catalyst, resulting in reduced yields and increased production costs.

[0040] Accordingly, aspects of the present disclosure relate to HS-FCC catalyst compositions and methods for directly converting crude oil into higher value chemical products and intermediates (such as, but not limited to, olefins and aromatic compounds) by an FCC process using the HS-FCC catalyst compositions and reaction conditions that effect efficient cracking of the crude oil while resisting catalyst deactivation. The HS-FCC catalyst compositions of the present disclosure include nano-ZSM-5 zeolite, ultrastable Y zeolite, an alumina binder, a matrix material including kaolin, and colloidal silica. The methods of the present disclosure include contacting a crude oil feed stream with the HS-FCC catalyst composition in a high severity fluid catalytic cracking (HS-FCC) system under high severity conditions sufficient to convert at least a portion of the crude oil feed stream into light olefins, aromatic compounds, or both. The HS-FCC catalyst compositions and reaction conditions of the methods of the present disclosure enable the crude oil to be efficiently directly converted into light olefins, aromatic compounds, or both while resisting catalyst deactivation and other characteristics.

[0041] Reference is now made to Figure 1 , which schematically shows a crude oil upgrading system 100 that includes a hydrotreating unit 110 and an HS-FCC unit 120 downstream of the hydrotreating unit 110. The crude oil upgrading system 100 receives crude oil 101 and directly processes the crude oil 101 to form one or more petrochemical products. In some embodiments, the crude oil 101 may not undergo any pre-treatment, separation, or other operations that may alter the composition of the crude oil 101 before introducing the crude oil 101 into the hydrotreating unit 110 or combining the crude oil 101 with hydrogen to form a mixed stream 105 that is introduced into the hydrotreating unit 110. For example, the crude oil 101 may not be separated (fractionated) into higher boiling fractions and lower boiling fractions before being introduced into the hydrotreating unit 110. In some embodiments, the crude oil upgrading system 100 may include a crude oil source 170. The crude oil 101 may be directly delivered from the crude oil source 170 to the inlet 162 of the hydrotreating unit 110.

[0042] The crude oil source 170 can be a storage vessel, pipeline, crude oil production facility, petroleum refinery, or other crude oil source 170. The crude oil 101 can include one or more of crude oil, vacuum residue, tar sands, bitumen, atmospheric residue, vacuum gas oil, other heavy oil streams, or combinations thereof. In some embodiments, the crude oil 101 can be a crude oil having an American Petroleum Institute (API) gravity of 30 to 35 degrees. For example, in some embodiments, the crude oil 101 can include Arab Medium crude oil. Exemplary properties of exemplary grades of Arab Medium crude oil are listed in Tables 1 and 2, which are provided subsequently in this disclosure. It should be understood that, as used in this disclosure, "crude oil" can refer to raw hydrocarbons that have not been previously processed, or can refer to hydrocarbons in the crude oil 101 that have undergone a certain degree of processing prior to being introduced into the crude oil upgrading system 100.

[0043] Table 1 - Examples of Arab Medium Crude Oil Feedstock

[0044]

[0045]

[0046] Table 2 - Exemplary Boiling Point Distribution of Arab Medium Crude Oil Feedstock

[0047] Initial boiling point (IBP) Degree Celsius (°C) Value Test method 5% Boiling point (BP) ℃ 88 ASTM D7169 10% BP ℃ 131 ASTM D7169 20% BP ℃ 196 ASTM D7169 30% BP ℃ 262 ASTM D7169 40% BP ℃ 326 ASTM D7169 50% BP ℃ 393 ASTM D7169 60% BP ℃ 465 ASTM D7169 70% BP ℃ 552 ASTM D7169 80% BP ℃ 654 ASTM D7169 90% BP ℃ 721 ASTM D7169 95% BP ℃ >720 ASTM D7169 Final boiling point (FBP) ℃ >720 ASTM D7169

[0048] Still referring to Figure 1 , in some embodiments, the crude oil 101 can be mixed with hydrogen 102 to form a mixed stream 105, which can then be introduced into the hydrotreating unit 110. In some embodiments, the crude oil 101 and hydrogen 102 can be independently introduced into the hydrotreating unit 110. In such embodiments, the mixed stream 105 may not be formed. The hydrogen 102 can be supplied by a hydrogen source external to the system, such as a feed hydrogen stream, or can be supplied by a system recycle stream, as described subsequently in this disclosure with reference to Figure 5As described. In some embodiments, the hydrogen 102 may include hydrogen from a combination of multiple sources, such as being supplied in part by a feed hydrogen stream and in part by a system recycle stream. The volume ratio of the hydrogen 102 introduced into the hydrotreating unit 110 to the crude oil 101 may be from 400:1 to 1500:1, from 600:1 to 1300:1, from 800:1 to 1100:1, or even from 900:1 to 1000:1. The volume ratio of the hydrogen 102 to the crude oil 101 may depend on the composition of the crude oil 101. The hydrogen 102 may be mixed with the crude oil 101 or introduced directly into the hydrotreating unit 110, because all the reactions occurring within the hydrotreating unit 110 consume hydrogen when the crude oil 101 undergoes hydrotreating. In some embodiments, the hydrogen 102 may also be incorporated downstream of the crude oil 101. In some embodiments, the hydrotreating unit 110 includes multiple reactors, and in such embodiments each reactor may be independently supplied with hydrogen 102, or the hydrogen 102 may be mixed with the crude oil 101 before the first reactor, or the hydrogen 102 may be mixed with the reaction effluent between each reactor.

[0049] The hydrotreating unit 110 is operable to at least partially reduce the content of metals, sulfur, and aromatic portions in the crude oil 101 to produce a hydrotreated effluent 103. For example, the hydrotreated effluent 103 delivered out of the hydrotreating unit 110 may have a content of one or more metals, sulfur, and aromatic compounds that is at least 2 percent (%) lower, at least 5%, at least 10%, at least 25%, at least 50%, or even at least 75% lower than the content of one or more metals, nitrogen, sulfur, or aromatic compounds in the crude oil 101. For example, the HDM catalyst may remove at least a portion of one or more metals from the crude oil 101, and the HDS catalyst may remove at least a portion of the sulfur present in the process stream. Additionally, the HDA catalyst may reduce the amount of aromatic compounds in the crude oil 101 by saturating and cracking the aromatic portions of these aromatic compounds. The hydrotreating unit 110 may also optionally be operable to reduce the nitrogen concentration in the crude oil 101, reducing nitrogen by one or more of the HDM, HDS, or HDA catalysts or by an optional HDN catalyst incorporated into the hydrotreating unit 110.

[0050] According to one or more embodiments, the hydrotreating unit 110 may include a plurality of catalyst beds arranged in series. For example, the hydrotreating unit 110 may include an HDM catalyst, an HDS catalyst, and an HDA catalyst arranged in series. The catalysts of the hydrotreating unit 110 may include one or more metal catalysts selected from metal elements of Groups 5, 6, 8, 9, or 10 of the International Union of Pure and Applied Chemistry (IUPAC) Periodic Table, such as but not limited to molybdenum, nickel, cobalt, and tungsten. The metals of the catalyst may be supported on a carrier. The carrier material is described subsequently in the present disclosure and is related to the hydrotreating catalysts used in each reaction zone of the hydrotreating unit 110. In some embodiments, one or more catalysts for reducing the content of sulfur, metals, or both (such as HDM and HDS catalysts) may be placed upstream of a catalyst for converting aromatic hydrocarbons into more readily crackable compounds (such as an HDA catalyst). The hydrotreating unit 110 may operate at a temperature of 300 °C to 450 °C and at a pressure of 30 bar (3,000 kilopascals (kPa)) to 200 bar (20,000 kPa), such as 30 bar (3,000 kPa) to 180 bar (18,000 kPa). The hydrotreating unit 110 may operate at a liquid hourly space velocity (LHSV) of 0.1 per hour (hr -1 ) to 10 hr -1 , such as 0.2 hr -1 to 10 hr -1 .

[0051] The HDM catalyst, the HDS catalyst, and the HDA catalyst may each have a bulk density of 0.3 grams per milliliter (g / ml) to 1.0 g / ml, such as 0.4 g / ml to 0.8 g / ml. The volume of the HDA catalyst included in the hydrotreating unit 110 may be greater than the volume of the HDM catalyst, the volume of the HDS catalyst, or the combined volume of the HDM catalyst and the HDS catalyst. In some embodiments, the hydrotreating unit 110 may have a volume ratio of the HDA catalyst to the volume of the HDM catalyst and the HDS catalyst of 1:1 to 6:1, such as 1:1 to 5:1, 2:1 to 6:1, 2:1 to 5:1, 3:1 to 6:1, or 3:1 to 5:1. In some embodiments, the hydrotreating unit 110 may include a volume ratio of the HDA catalyst to the combined volume of the HDM catalyst and the HDS catalyst of about 4:1.

[0052] Still referring to Figure 1, the hydrotreated effluent 103 is delivered out of the hydrotreating unit 110. In some embodiments, at least 20 wt% of the hydrotreated effluent 103 may have a boiling point temperature of less than or equal to 225 °C. In additional embodiments, at least 5 wt%, at least 10 wt%, at least 20 wt% or even at least 30 wt% of the hydrotreated effluent 103 may have a boiling point temperature of less than or equal to 250 °C. The hydrotreated effluent 103 may be characterized by a T5 temperature, which is the temperature at which less than 5% of the components boil. In some embodiments, the hydrotreated effluent 103 may have a T5 temperature of less than or equal to 140 °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 hydrotreated effluent 103 may also be characterized by a T95 temperature, which is the temperature at which 95% of the components of the hydrotreated effluent 103 boil. In some embodiments, the hydrotreated effluent 103 may have a T95 temperature of greater than or equal to 520 °C, greater than or equal to 530 °C, greater than or equal to 540 °C, greater than or equal to 550 °C, even greater than or equal to 560 °C or even greater than or equal to 570 °C. In some embodiments, the hydrotreated effluent 103 may have an end boiling point (FBP) temperature of greater than or equal to 580 °C, such as greater than or equal to 590 °C, greater than or equal to 600 °C, or even less than or equal to 610 °C.

[0053] In some embodiments, the hydrotreated effluent 103 may have a density less than the density of the crude oil 101. In some embodiments, the hydrotreated effluent 103 may have a density of from 0.80 grams per milliliter (g / mL) to 0.95 g / mL, such as from 0.80 g / mL to 0.90 g / mL, from 0.80 g / mL to 0.85 g / mL, from 0.82 g / mL to 0.95 g / mL, from 0.82 g / mL to 0.90 g / mL, from 0.82 g / mL to 0.85 g / mL, from 0.83 g / mL to 0.95 g / mL, from 0.83 g / mL to 0.90 g / mL, or from 0.83 g / mL to 0.85 g / mL. The hydrotreated effluent 103 may have an API gravity greater than the API gravity of the crude oil 101 introduced into the hydrotreating unit 110. In some embodiments, the hydrotreated effluent 103 may have an API gravity less than or equal to 50 degrees or less than or equal to 40 degrees. In some embodiments, the hydrotreated effluent 103 may have an API of from 25 degrees to 29 degrees. The hydrotreated effluent 103 may have a sulfur content lower than the sulfur content of the crude oil 101 introduced into the hydrotreating unit 110. In some embodiments, the hydrotreated effluent 103 may have a sulfur content of from 0.001 weight % to 0.10 weight %, such as from 0.01 weight % to 0.08 weight %, from 0.01 weight % to 0.05 weight %, from 0.02 weight % to 0.10 weight %, from 0.02 weight % to 0.08 weight %, or from 0.02 weight % to 0.07 weight %. The hydrotreated effluent 103 may have a nitrogen content lower than the nitrogen content of the crude oil 101. In some embodiments, the hydrotreated effluent 103 may have a nitrogen content of from 0 parts per million by weight (ppmw) to 500 ppmw, such as from 10 ppmw to 500 ppmw, from 10 ppmw to 400 ppmw, from 10 ppmw to 300 ppmw, from 50 ppmw to 500 ppmw, from 50 ppmw to 400 ppmw, or from 50 ppmw to 300 ppmw.

[0054] The hydrotreated effluent 103 can have a metal content that is lower than the metal content of the crude oil 101 introduced into the hydrotreating unit 110. In some embodiments, the hydrotreated effluent 103 can have a metal content of from 0 ppmw to 100 ppmw, such as from 0 ppmw to 75 ppmw, from 0 ppmw to 50 ppmw, from 0 ppmw to 25 ppmw, from 0 ppmw to 10 ppmw, from 0 ppmw to 5 ppmw, from 0.1 ppmw to 100 ppmw, from 0.1 ppmw to 75 ppmw, from 0.1 ppmw to 50 ppmw, from 0.1 ppmw to 25 ppmw, from 0.1 ppmw to 10 ppmw, or from 0.1 ppmw to 5 ppmw. The hydrotreated effluent 103 can have a nickel content that is lower than the nickel content of the crude oil 101 introduced into the hydrotreating unit 110. In some embodiments, the hydrotreated effluent 103 can have a nickel content of from 0 ppmw to 10 ppmw, such as from 0 ppmw to 7.5 ppmw, from 0 ppmw to 5 ppmw, from 0 ppmw to 2.5 ppmw, from 0 ppmw to 1 ppmw, from 0 ppmw to 0.5 ppmw, from 0.1 ppmw to 10 ppmw, from 0.1 ppmw to 7.5 ppmw, from 0.1 ppmw to 5 ppmw, from 0.1 ppmw to 2.5 ppmw, from 0.1 ppmw to 1 ppmw, or from 0.1 ppmw to 0.5 ppmw. The hydrotreated effluent 103 can have a vanadium content that is lower than the vanadium content of the crude oil 101 introduced into the hydrotreating unit 110. In some embodiments, the hydrotreated effluent 103 can have a vanadium content of from 0 ppmw to 10 ppmw, such as from 0 ppmw to 7.5 ppmw, from 0 ppmw to 5 ppmw, from 0 ppmw to 2.5 ppmw, from 0 ppmw to 1 ppmw, from 0 ppmw to 0.5 ppmw, from 0.1 ppmw to 10 ppmw, from 0.1 ppmw to 7.5 ppmw, from 0.1 ppmw to 5 ppmw, from 0.1 ppmw to 2.5 ppmw, from 0.1 ppmw to 1 ppmw, or from 0.1 ppmw to 0.5 ppmw.

[0055] The hydrotreated effluent 103 may have an iron content that is lower than the iron content of the crude oil 101 introduced into the hydrotreating unit 110. In some embodiments, the hydrotreated effluent 103 may have an iron content of from 0 ppmw to 10 ppmw, such as from 0 ppmw to 7.5 ppmw, from 0 ppmw to 5 ppmw, from 0 ppmw to 2.5 ppmw, from 0 ppmw to 1 ppmw, from 0 ppmw to 0.5 ppmw, from 0.1 ppmw to 10 ppmw, from 0.1 ppmw to 7.5 ppmw, from 0.1 ppmw to 5 ppmw, from 0.1 ppmw to 2.5 ppmw, from 0.1 ppmw to 1 ppmw, or from 0.1 ppmw to 0.5 ppmw. The hydrotreated effluent 103 may have a sodium content that is lower than the sodium content of the crude oil 101 introduced into the hydrotreating unit 110. In some embodiments, the hydrotreated effluent 103 may have a sodium content of from 0 ppmw to 10 ppmw, such as from 0 ppmw to 7.5 ppmw, from 0 ppmw to 5 ppmw, from 0 ppmw to 2.5 ppmw, from 0 ppmw to 1 ppmw, from 0 ppmw to 0.5 ppmw, from 0.1 ppmw to 10 ppmw, from 0.1 ppmw to 7.5 ppmw, from 0.1 ppmw to 5 ppmw, from 0.1 ppmw to 2.5 ppmw, from 0.1 ppmw to 1 ppmw, or from 0.1 ppmw to 0.5 ppmw.

[0056] Still referring to Figure 1, in some embodiments, the hydrotreated effluent 103 may be delivered from the hydrotreating unit 110 to the HS-FCC unit 120. In some embodiments, the hydrotreated effluent 103 may be directly delivered from the hydrotreating unit 110 to the HS-FCC unit 120 without subjecting the hydrotreated effluent 103 to intermediate unit operations that change the composition of the hydrotreated effluent 103, such as separation. In some embodiments, the hydrotreated effluent 103 may be delivered through a heat exchanger, compressor, analyzer, or other system components that do not change the composition of the hydrotreated effluent 103 before being delivered to the HS-FCC unit 120. In some embodiments, the crude oil upgrading system 100 may include a conduit 166 extending directly from the outlet 164 of the hydrotreating unit 110 to the inlet 168 of the HS-FCC unit 120. The conduit 166 may be operable to directly transport the hydrotreated effluent 103 from the outlet 164 of the hydrotreating unit 110 to the inlet 168 of the HS-FCC unit 120 without delivery through a separation device or other unit operations operable to change the composition of the hydrotreated effluent 103. In some embodiments, the entire hydrotreated effluent 103 may be delivered from the hydrotreating unit 110 to the HS-FCC unit 120. In some embodiments, one or more side streams having the same composition as the hydrotreated effluent 103 may be removed from the hydrotreated effluent 103 between the hydrotreating unit 110 and the HS-FCC unit 120 without changing the composition of the hydrotreated effluent 103.

[0057] The HS-FCC unit 120 may be operable to contact the hydrotreated effluent 103 with a cracking catalyst under high severity conditions to crack at least a portion of the hydrotreated effluent 103 to produce a cracked effluent 104 comprising at least one product. In some embodiments, the entire hydrotreated effluent 103 may be contacted with the cracking catalyst in the HS-FCC unit 120 under high severity conditions. Although the entire hydrotreated effluent 103 may be contacted with the cracking catalyst, in some embodiments, only a portion of the hydrotreated effluent 103 may undergo cracking in the HS-FCC unit 120. The HS-FCC unit 120 may include a catalyst-feed mixing zone 121, a reaction zone 122, a separation zone 123, and a catalyst regeneration zone 124. The hydrotreated effluent 103 may be delivered to the catalyst-feed mixing zone 121 where it is mixed with regenerated cracking catalyst from the HS-FCC catalyst composition 125 delivered from the catalyst regeneration zone 124 to form a mixture comprising the hydrotreated effluent 103 and the cracking catalyst.

[0058] A variety of fluid catalytic cracking catalysts may be suitable for the reactions in the HS-FCC unit 120. The HS-FCC catalyst composition 125 of the present disclosure includes nano-ZSM-5 zeolite and Y-type zeolite, wherein the nano-ZSM-5 has an average particle size of 0.01 μm to 0.2 μm. The HS-FCC catalyst composition 125 may further include an alumina binder, a matrix material containing kaolin, and colloidal silica.

[0059] The nano-ZSM-5 zeolite in the HS-FCC catalyst composition 125 is operable to crack at least a portion of the hydrocarbon feed to produce one or more light olefins, such as ethylene and propylene. Without being bound by any particular theory, it is believed that the nano-ZSM-5 zeolite may have a greater tendency to crack relatively light hydrocarbons, such as those relatively light hydrocarbons present in the hydrotreated effluent 103 and those relatively light hydrocarbons produced by catalytic cracking of heavier hydrocarbons by the Y-type zeolite. Thus, including the nano-ZSM-5 zeolite can increase the yield of products, such as light olefins, when compared to an HS-FCC catalyst that does not include the nano-ZSM-5 zeolite. In addition, when compared to an HS-FCC catalyst composition including a ZSM-5 zeolite having an average particle size greater than 0.2 μm, the HS-FCC catalyst composition 125 including the nano-ZSM-5 zeolite may have reduced coke formation during the steady-state operation of the crude oil upgrading system 100. As used in the present disclosure, "ZSM-5" refers to a zeolite having a mordenite framework inverted (MFI) type according to the IUPAC zeolite nomenclature and composed of silica and alumina. ZSM-5 refers to "Zeolite Socony Mobil-5" and is a pentasil family zeolite, which can be represented by the chemical formula Na n Al n Si 96–n O 192 ·16H2O, where 0 < n < 27. The molar ratio of silica to alumina in ZSM-5 can be at least 5, at least 10, at least 25, at least 30, or even at least 50. In an embodiment, the molar ratio of silica to alumina in ZSM-5 can be 5 to 50, 5 to 40, 5 to 35, 10 to 50, 10 to 40, 10 to 35, 20 to 50, 20 to 40, 20 to 35, 30 to 50, or 30 to 40. As used in the present disclosure, "nano-ZSM-5" refers to a ZSM-5 zeolite having an average particle size of 0.01 μm to 0.2 μm, as determined by electron microscopy.

[0060] In an embodiment, the nano-ZSM-5 zeolite may have 200 square meters per gram (m 2 / g) to 800 m 2The average surface area per g. In an embodiment, the average surface area can be 200 m 2 / g to 400 m 2 / g, 200 m 2 / g to 600 m 2 / g, 200 m 2 / g to 800 m 2 / g, 300 m 2 / g to 400 m 2 / g, 300 m 2 / g to 600 m 2 / g, 300 m 2 / g to 800 m 2 / g, 400 m 2 / g to 600 m 2 / g or 400 m 2 / g to 800 m 2 / g. In an embodiment, the nano-ZSM-5 zeolite can have an average total pore volume of 0.010 milliliters per gram (mL / g) to 0.500 mL / g per unit weight of nano-ZSM-5 zeolite, such as 0.050 mL / g to 0.500 mL / g, 0.010 mL / g to 0.300 mL / g, or 0.050 mL / g to 0.300 mL / g.

[0061] In an embodiment, the nano-ZSM-5 zeolite may have an average particle size of 0.01 μm to 0.2 μm, as determined by an electron microscope. In an embodiment, the average particle size of the nano-ZSM-5 zeolite may be 0.01 μm to 0.15 μm, 0.01 μm to 0.125 μm, 0.01 μm to 0.1 μm, 0.01 μm to 0.09 μm, 0.05 μm to 0.15 μm, 0.05 μm to 0.125 μm, 0.05 μm to 0.1 μm, 0.05 μm to 0.09 μm, or 0.08 μm to 0.09 μm. In an embodiment, the nano-ZSM-5 zeolite may generally be spherical and may have an average particle diameter of 0.01 μm to 0.15 μm, 0.01 μm to 0.125 μm, 0.01 μm to 0.1 μm, 0.01 μm to 0.09 μm, 0.05 μm to 0.15 μm, 0.05 μm to 0.125 μm, 0.05 μm to 0.1 μm, 0.05 μm to 0.09 μm, or 0.08 μm to 0.09 μm, as determined by an electron microscope. Without wishing to be bound by any particular theory, it is believed that when compared to a nano-ZSM-5 zeolite having an average particle size less than or equal to 0.2 μm, a ZSM-5 zeolite having an average particle diameter or average particle size greater than 0.2 μm may have a crystal size more similar to the molecular diameter of light hydrocarbons. It is further believed that when the crystal size of the ZSM-5 zeolite is similar to the molecular diameter of the light hydrocarbons produced from the catalytic reaction, the diffusion of reactant and product molecules within the micropores of the ZSM-5 zeolite may be the rate-limiting step of the catalytic reaction, which may increase coke formation on the ZSM-5 zeolite. Therefore, it is believed that when compared to an HS-FCC catalyst composition comprising a ZSM-5 zeolite having an average particle size greater than 0.2 μm, an HS-FCC catalyst composition 125 comprising a nano-ZSM-5 zeolite having an average particle size of 0.01 μm to 0.20 μm may exhibit reduced coke formation and reduced deactivation.

[0062] In an embodiment, one or more zeolite components of the HS-FCC catalyst composition 125 may include one or more phosphorus-containing compounds, such as phosphorus pentoxide (P2O5). Without being bound by any particular theory, it is believed that the phosphorus-containing compounds may strengthen the structure of the zeolite framework by preventing the segregation of framework alumina, which may improve the hydrothermal stability of the zeolite component. This may reduce the dealumination of the zeolite component that occurs during the steaming process, which may lead to a decrease in the acidity and catalytic activity of the zeolite component. In an embodiment, one or more zeolite components of the HS-FCC catalyst composition 125 may include one or more phosphorus-containing compounds in an amount of 1 wt% to 20 wt% based on the total weight of each zeolite component. In an embodiment, the phosphorus-containing compound may be impregnated onto the nano-ZSM-5 zeolite, so that the nano-ZSM-5 zeolite is impregnated with 1 wt% to 20 wt% of the phosphorus-containing compound based on the total weight of the nano-ZSM-5 zeolite. In an embodiment, the nano-ZSM-5 zeolite may be impregnated with 1 wt% to 20 wt% of phosphorus pentoxide based on the total weight of the nano-ZSM-5 zeolite. In an embodiment, the nano-ZSM-5 zeolite may include 1 wt% to 15 wt%, 1 wt% to 10 wt%, 1 wt% to 5 wt%, 5 wt% to 20 wt%, 5 wt% to 15 wt%, 5 wt% to 10 wt%, 10 wt% to 20 wt%, 10 wt% to 15 wt%, 15 wt% to 20 wt%, 6 wt% to 9 wt% or 7 wt% to 8 wt% of phosphorus pentoxide based on the total weight of the nano-ZSM-5 zeolite. In an embodiment, the nano-ZSM-5 zeolite may include approximately 7.5 wt% of phosphorus pentoxide based on the total weight of the nano-ZSM-5 zeolite.

[0063] In an embodiment, the HS-FCC catalyst composition 125 may include up to 40 wt% of nano-ZSM-5 zeolite based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 may include up to 30 wt%, up to 25 wt% or up to 20 wt% of nano-ZSM-5 zeolite based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 may include 1 wt% to 40 wt%, 1 wt% to 30 wt%, 1 wt% to 25 wt%, 1 wt% to 20 wt%, 5 wt% to 40 wt%, 5 wt% to 30 wt%, 5 wt% to 25 wt%, 5 wt% to 20 wt%, 10 wt% to 40 wt%, 10 wt% to 30 wt%, 10 wt% to 25 wt%, 10 wt% to 20 wt%, 15 wt% to 40 wt%, 15 wt% to 30 wt%, 15 wt% to 25 wt% or 15 wt% to 20 wt% of nano-ZSM-5 zeolite based on the total weight of the HS-FCC catalyst composition 125.

[0064] The Y zeolite of the HS-FCC catalyst composition 125 is operable to produce one or more olefins from hydrocarbons in the hydrotreated effluent 103. In an embodiment, the Y zeolite may comprise ultrastable Y (USY) zeolite. The USY zeolite may be produced via dealumination of one or more Y zeolites. As used in the present disclosure, the term "Y zeolite" refers to a zeolite having a Faujasite (FAU) framework type according to the IUPAC zeolite nomenclature and composed of silica and alumina. Without being bound by any particular theory, it is believed that dealumination of the Y zeolite may result in a decrease in the number of acid sites in the USY zeolite. When compared with the undealuminated Y zeolite, this decrease in the number of acid sites may result in a decrease in the rate of secondary reactions in the HS-FCC unit 120, such as dehydrogenation or hydrogenation of the olefins produced in the HS-FCC unit 120. Thus, the USY zeolite may produce a higher yield of olefins when compared with the Y zeolite.

[0065] The molar ratio of silica to alumina in the USY zeolite may be greater than or equal to 5, greater than or equal to 10, greater than or greater than 25, or even greater than or equal to 50. In an embodiment, the molar ratio of silica to alumina in the USY zeolite may be 5 to 50, 5 to 25, 5 to 10, 10 to 50, 10 to 25, or 25 to 50. In an embodiment, the molar ratio of silica to alumina in the USY zeolite may be about 30. In an embodiment, the USY zeolite may further comprise one or more transition metals substituted into the framework of the zeolite, such as zirconium, titanium, or hafnium. The USY zeolite may have 200 m 2 / g to 900 m 2 / g of average surface area. In an embodiment, the USY zeolite may have 200 m 2 / g to 800 m 2 / g, 300 m 2 / g to 900 m 2 / g, 300 m 2 / g to 800 m 2 / g, 500 m 2 / g to 900 m 2 / g, or 500 m 2 / g to 800 m 2 / g of average surface area. The USY zeolite may have an average total pore volume of 0.050 mL / g to 0.600 mL / g per unit weight of the USY zeolite, such as 0.050 mL / g to 0.500 mL / g.

[0066] In an embodiment, one or more zeolite components of the HS-FCC catalyst composition 125 can include one or more rare earth metals or rare earth metal oxides, where the rare earth metal can be one or more of lanthanum, cerium, dysprosium, europium, gadolinium, holmium, lutetium, neodymium, praseodymium, promethium, samarium, scandium, terbium, thulium, ytterbium, yttrium, or a combination thereof. Without being bound by any particular theory, it is believed that the rare earth metal or metal oxide can increase the stability of the unit cells of the zeolite component, increase the catalytic activity of the zeolite component, or both. Further, it is believed that the rare earth metal or metal oxide can act as vanadium traps that sequester vanadium in the feed and prevent the detrimental effects that vanadium can have on the zeolite component of the catalyst. In an embodiment, one or more zeolite components of the HS-FCC catalyst composition 125 can include one or more rare earth metals in an amount of from 1 wt% to 5 wt% based on the total weight of each zeolite component. In an embodiment, one or more zeolite components of the HS-FCC catalyst composition 125 can be impregnated with lanthanum or lanthanum oxide. In an embodiment, one or more zeolite components of the HS-FCC catalyst composition 125 can include one or more lanthanum-containing compounds, such as, but not limited to, lanthanum oxide, in an amount of from 1 wt% to 5 wt%, from 1 wt% to 4 wt%, from 1 wt% to 3 wt%, from 1 wt% to 2 wt%, from 2 wt% to 5 wt%, from 2 wt% to 4 wt%, from 2 wt% to 3 wt%, from 3 wt% to 5 wt%, from 3 wt% to 4 wt%, or from 4 wt% to 5 wt% based on the total weight of each zeolite component.

[0067] In an embodiment, the rare earth or rare earth oxide can be impregnated on the USY zeolite of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 can include USY zeolite impregnated with lanthanum oxide (La2O3). In an embodiment, the USY zeolite can include from 1 wt% to 5 wt%, from 1 wt% to 4 wt%, from 1 wt% to 3 wt%, from 1 wt% to 2 wt%, from 2 wt% to 5 wt%, from 2 wt% to 4 wt%, from 2 wt% to 3 wt%, from 3 wt% to 5 wt%, from 3 wt% to 4 wt%, or from 4 wt% to 5 wt% lanthanum oxide based on the total weight of the USY zeolite. In an embodiment, the USY zeolite can include approximately 2.5 wt% lanthanum oxide based on the total weight of the USY zeolite.

[0068] In an embodiment, the HS-FCC catalyst composition 125 can include up to 40 wt% of USY zeolite based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 can include up to 30 wt% or up to 25 wt% of USY zeolite based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 can include from 1 wt% to 40 wt%, from 1 wt% to 30 wt%, from 1 wt% to 25 wt%, from 5 wt% to 40 wt%, from 5 wt% to 30 wt%, from 5 wt% to 25 wt%, from 10 wt% to 40 wt%, from 10 wt% to 30 wt%, from 10 wt% to 25 wt%, from 15 wt% to 40 wt%, from 15 wt% to 30 wt%, or from 15 wt% to 25 wt% of USY zeolite based on the total weight of the HS-FCC catalyst composition 125.

[0069] In an embodiment, the HS-FCC catalyst composition 125 can include one or more binder materials, such as alumina-containing compounds or silica-containing compounds (including compounds containing alumina and silica). As used in this disclosure, "binder material" refers to a material for "gluing" or otherwise holding the components of the HS-FCC catalyst composition 125. Binder materials can be included to improve the attrition resistance of the HS-FCC catalyst composition 125. The binder can comprise alumina (such as amorphous alumina), silica-alumina (such as amorphous silica-alumina), or silica (such as amorphous silica). According to one or more embodiments, the binder material can comprise pseudoboehmite. As used in this disclosure, "pseudoboehmite" refers to an aluminum-containing compound with a chemical composition of AlO(OH) composed of crystalline boehmite. Although boehmite generally also refers to aluminum oxide hydroxide, pseudoboehmite generally has a greater amount of water than boehmite. In an embodiment, the binder material can comprise amorphous silica. The amorphous silica can be in the form of colloidal silica. As used throughout this disclosure, the term "colloidal silica" refers to nanosized amorphous, non-porous silica particles. In an embodiment, the HS-FCC catalyst composition 125 can comprise an alumina binder, colloidal silica, or both.

[0070] In an embodiment, the HS-FCC catalyst composition 125 may include one or more binders in an amount of 5 wt% to 30 wt% based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 may include one or more binders in an amount of 5 wt% to 25 wt%, 5 wt% to 20 wt%, 5 wt% to 15 wt%, 5 wt% to 10 wt%, 10 wt% to 25 wt%, 10 wt% to 20 wt%, 10 wt% to 15 wt%, 15 wt% to 30 wt%, 15 wt% to 25 wt%, 15 wt% to 20 wt%, 20 wt% to 30 wt%, 20 wt% to 25 wt% or 25 wt% to 30 wt% based on the total weight of the HS-FCC catalyst composition 125.

[0071] In an embodiment, the HS-FCC catalyst composition 125 may include an alumina binder in an amount of 2 wt% to 20 wt% based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 may include an alumina binder in an amount of 2 wt% to 15 wt%, 2 wt% to 10 wt%, 5 wt% to 20 wt%, 5 wt% to 15 wt%, 5 wt% to 10 wt% or 7 wt% to 9 wt% based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 may include an alumina binder in an amount of about 8 wt% based on the total weight of the HS-FCC catalyst composition 125.

[0072] In an embodiment, the HS-FCC catalyst composition 125 may include colloidal silica in an amount of 0.5 wt% to 5 wt% based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 may include colloidal silica in an amount of 0.5 wt% to 4 wt%, 0.5 wt% to 3 wt%, 0.5 wt% to 2 wt%, 1 wt% to 4 wt%, 1 wt% to 3 wt%, 1 wt% to 2 wt%, 2 wt% to 4 wt% or 2 wt% to 3 wt% based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 may include colloidal silica in an amount of about 2 wt% based on the total weight of the HS-FCC catalyst composition 125. Without wishing to be bound by any particular theory, it is believed that colloidal silica may be used as a binder and / or filler to provide additional physical strength and integrity to the HS-FCC catalyst. In addition, it is believed that adding colloidal silica to the HS-FCC catalyst may improve the abrasion resistance of the HS-FCC catalyst and / or stabilize the catalytic activity of the HS-FCC catalyst.

[0073] In an embodiment, the HS-FCC catalyst composition 125 can include one or more matrix materials, which can include one or more clay materials, such as, but not limited to, kaolin. Without being bound by any particular theory, it is believed that the matrix materials of the HS-FCC catalyst composition 125 can provide both physical and catalytic functions. The physical functions can include providing particle integrity and abrasion resistance, serving as a heat transfer medium, and providing a porous structure to allow hydrocarbon diffusion into and out of the catalyst microspheres. The matrix materials can also affect catalyst selectivity, product quality, and toxicity resistance. For those reactions directly involving relatively large molecules, the matrix materials may tend to exert their strongest influence on the overall catalytic performance.

[0074] In an embodiment, the matrix material can include kaolin. As used in the present disclosure, "kaolin" refers to a clay material having a relatively large amount (such as at least about 50 wt%, at least 60 wt%, at least 70 wt%, at least 80 wt%, at least 90 wt% or at least 95 wt%) of kaolinite, which can be represented by the chemical formula Al2Si2O5(OH)4. In an embodiment, the HS-FCC catalyst composition 125 can include one or more matrix materials in an amount of 30 wt% to 60 wt% based on the total weight of each HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 can include matrix materials in an amount of 30 wt% to 55 wt%, 30 wt% to 50 wt%, 30 wt% to 45 wt%, 30 wt% to 40 wt%, 30 wt% to 35 wt%, 35 wt% to 60 wt%, 35 wt% to 55 wt%, 35 wt% to 50 wt%, 35 wt% to 45 wt%, 35 wt% to 40 wt%, 40 wt% to 60 wt%, 40 wt% to 55 wt%, 40 wt% to 50 wt%, 40 wt% to 45 wt%, 45 wt% to 60 wt%, 45 wt% to 55 wt%, 45 wt% to 50 wt%, 50 wt% to 60 wt%, 50 wt% to 55 wt% or 55 wt% to 60 wt% based on the total weight of the HS-FCC catalyst composition 125.

[0075] In an embodiment, the HS-FCC catalyst composition 125 can include nano-ZSM-5 zeolite impregnated with phosphorus, USY zeolite impregnated with lanthanum oxide, alumina binder, a matrix material containing kaolin, and colloidal silica. In an embodiment, the nano-ZSM-5 zeolite can be impregnated with 7.5 wt% of phosphorus pentoxide based on the total weight of the nano-ZSM-5 zeolite. In an embodiment, the USY zeolite can be impregnated with 2.5 wt% of lanthanum oxide based on the total weight of the USY zeolite.

[0076] In an embodiment, the HS-FCC catalyst composition 125 may comprise: 20 wt% of nano-ZSM-5 zeolite based on the total weight of the HS-FCC catalyst composition 125, wherein the nano-ZSM-5 zeolite is impregnated with 7.5 wt% of P2O5 based on the total weight of the nano-ZSM-5 zeolite; 21 wt% of USY zeolite based on the total weight of the HS-FCC catalyst composition 125, wherein the USY zeolite is impregnated with 2.5 wt% of lanthanum oxide (La2O3) based on the total weight of the USY zeolite; 8 wt% of alumina binder based on the total weight of the HS-FCC catalyst composition 125; 49 wt% of kaolin based on the total weight of the HS-FCC catalyst composition 125; 2 wt% of colloidal silica based on the total weight of the HS-FCC catalyst composition 125. In an embodiment, the HS-FCC catalyst composition 125 may comprise a plurality of catalyst particles, wherein each of the plurality of catalyst particles comprises nano-ZSM-5 zeolite impregnated with phosphorus pentoxide, USY zeolite impregnated with lanthanum oxide, alumina binder, kaolin, and colloidal silica.

[0077] The HS-FCC catalyst composition 125 can be formed by various methods. According to one embodiment, the matrix material can be mixed with a fluid (such as water) to form a slurry, and the zeolite can be separately mixed with a fluid (such as water) to form a slurry. The matrix material slurry and the zeolite slurry can be combined under stirring. Additionally, by combining the binder material with a fluid (such as water), another slurry can be formed. Then, the binder slurry can be combined with the slurry containing the zeolite and the matrix material to form a final slurry. Then the final slurry can be dried, for example, by spraying, and then calcined to produce microparticles of the cracking catalyst.

[0078] In an embodiment, the HS-FCC catalyst composition 125 can be in the form of shaped microparticles, such as microspheres. As used in this disclosure, "microparticle" refers to a particle having an average particle size of from 0.1 micrometer to 100 micrometers. The size of the microparticle refers to the maximum length of the particle measured along the longest distance of the microparticle from one side to the other. For example, a spherical microparticle has a size equal to its diameter, or a rectangular prismatic microparticle has a size equal to the maximum length of the hypotenuse extending from opposite corners. In an embodiment, each zeolite component of the HS-FCC catalyst composition 125 can be included in each catalyst microparticle. However, in other embodiments, microparticles can be mixed, wherein the microparticles contain only a portion of the HS-FCC catalyst composition 125. For example, a mixture of two types of microparticles can be included in the HS-FCC catalyst composition 125, wherein one type of microparticle includes only nano-ZSM-5 zeolite, and the other type of microparticle includes only USY zeolite.

[0079] Still referring to Figure 1, in some embodiments, a mixture comprising the hydrotreated effluent 103 and the cracking catalyst may be delivered to a reaction zone 122 where at least a portion of the hydrotreated effluent 103 may undergo cracking to form one or more chemical products or intermediates. In some embodiments, the reaction zone 122 may be a downflow reaction zone where the mixture of the hydrotreated effluent 103 and the cracking catalyst is delivered downward (i.e., along the Figure 1 -Z direction of the coordinate axis in the figure) through the reaction zone 122. Although described in the context of a downflow reaction zone, it should be understood that the HS-FCC unit 120 may include a reaction zone 122 that is an upflow reaction zone or any other type of reaction zone.

[0080] Figure 1 FIG.

[0081] It should be noted that the content in FIG.

[0081] is not clearly defined in the original text, so the translation may not be very accurate in this regard. You can provide more specific information for a more precise translation. In some embodiments, the HS-FCC unit 120 is a simplified schematic diagram of a particular embodiment of an HS-FCC unit, and it is understood that other configurations of the HS-FCC unit may be suitable for incorporation into the crude oil upgrading system 100. The HS-FCC unit 120 is operable to contact the hydrotreated effluent 103 with the cracking catalyst under high severity conditions. As used herein, the term "high severity" refers to reaction conditions including: a reaction temperature greater than or equal to 500 °C, a weight ratio of the cracking catalyst to the reactant (such as the hydrotreated effluent 103) of at least 2:1, and a residence time of the reactant (the hydrotreated effluent 103) in contact with the cracking catalyst at the reaction temperature of less than or equal to 30 seconds. In some embodiments, the HS-FCC unit 120 may be operated at a reaction temperature of at least 500 °C, at least 550 °C, at least 600 °C, at least 650 °C, at least 700 °C, or even at least 750 °C. In some embodiments, the reaction temperature in the HS-FCC unit may be from 500 °C to 800 °C, from 500 °C to 700 °C, from 500 °C to 650 °C, from 500 °C to 600 °C, from 550 °C to 800 °C, from 550 °C to 700 °C, from 550 °C to 650 °C, from 550 °C to 600 °C, from 600 °C to 800 °C, from 600 °C to 700 °C, or from 600 °C to 650 °C.In some embodiments, the weight ratio of the cracking catalyst to the hydrotreated effluent 103 in the HS-FCC unit 120 is at least 2:1, at least 3:1, at least 4:1, at least 5:1, at least 6:1, at least 7:1 or even at least 10:1. In some embodiments, the weight ratio of the cracking catalyst to the hydrotreated effluent 103 in the HS-FCC unit 120 can be from 2:1 to 40:1, from 2:1 to 30:1, from 2:1 to 20:1, from 2:1 to 10:1, from 4:1 to 40:1, from 4:1 to 30:1, from 4:1 to 20:1, from 4:1 to 10:1, from 6:1 to 40:1, from 6:1 to 30:1, from 6:1 to 20:1, from 6:1 to 10:1, from 8:1 to 40:1, from 8:1 to 30:1, from 8:1 to 20:1, from 8:1 to 10:1, from 10:1 to 40:1, from 10:1 to 30:1, from 10:1 to 20:1 or from 20:1 to 40:1.

[0082] In some embodiments, the residence time of the hydrotreated effluent 103 in contact with the cracking catalyst in the HS-FCC unit 120 at the reaction temperature can be less than 30 seconds (sec), less than 25 sec, less than 20 sec, less than 15 sec, less than 10 sec, less than 5 sec, less than 2.5 sec, less than 1 sec or less than 0.5 sec. In some embodiments, the residence time of the hydrotreated effluent 103 in contact with the cracking catalyst in the HS-FCC unit 120 at the reaction temperature can be from 0.2 sec to 30 sec, from 0.2 sec to 25 sec, from 0.2 sec to 20 sec, from 0.2 sec to 15 sec, from 0.2 sec to 10 sec, from 0.2 sec to 5 sec, from 0.2 sec to 2.5 sec, from 0.2 sec to 1 sec, from 0.2 sec to 0.5 sec, from 0.5 sec to 30 sec, from 1 sec to 30 sec or from 2.5 sec to 30 sec, from 5 sec to 30 sec, from 10 sec to 30 sec, from 15 sec to 30 sec, from 20 sec to 30 sec or from 25 sec to 30 sec.

[0083] After the cracking reaction in the reaction zone 122, the contents of the reaction zone 122 can be delivered to the separation zone 123 where the cracked products of the reaction zone 122 are separated from the spent catalyst, and the spent catalyst is delivered to the catalyst regeneration zone 124 in the form of a spent catalyst stream 126 where it is regenerated, for example, by removing coke from the spent catalyst. The cracked effluent 104 can be delivered out of the separation zone 123.

[0084] Now refer to Figure 2, the hydrotreating unit 110 may include a plurality of packed bed reaction zones arranged in series in a single hydrotreating reactor 115. For example, in some embodiments, the hydrotreating unit 110 may include an HDM reaction zone 111, an HDS reaction zone 112, and an HDA reaction zone 114. In some embodiments, each of the HDM reaction zone 111, the HDS reaction zone 112, and the HDA reaction zone 114 may include a catalyst bed. In some embodiments, each of the HDM reaction zone 111, the HDS reaction zone 112, and the HDA reaction zone 114 may be contained in a single reactor, such as the hydrotreating reactor 115, which may be a packed bed reactor having a plurality of catalyst beds in series. In such an embodiment, the hydrotreating reactor 115 includes an HDM reaction zone 111 containing an HDM catalyst, an HDS reaction zone 112 containing an HDS catalyst, and an HDA reaction zone 114 containing an HDA catalyst. The hydrotreating unit 110 may be a downflow reactor, an upflow reactor, a horizontal flow reactor, or a reactor having other types of flow patterns. In some embodiments, the hydrotreating unit 110 may be a downflow column having an HDM reaction zone 111 in the top portion of the column, an HDS reaction zone 112 in the middle portion of the column, and an HDA reaction zone 114 in the bottom portion of the column. It should be understood that the embodiments contemplated include those in which the packed catalyst beds arranged in series are contained in a single reactor or multiple reactors each containing one or more catalyst beds.

[0085] According to one or more embodiments, the crude oil 101 may be introduced into the HDM reaction zone 111 and may contact the HDM catalyst. Contacting the crude oil 101 with the HDM catalyst may facilitate a reaction to remove at least a portion of the metals present in the crude oil 101. After contacting the HDM catalyst, the crude oil 101 may be converted into an HDM reaction effluent. The HDM reaction effluent may have a reduced metal content when compared to the contents of the crude oil 101. For example, the HDM reaction effluent may have at least 2%, at least 5%, at least 10%, at least 25%, at least 50%, or even at least 75% less metal than the crude oil 101. According to some embodiments, the HDM reaction zone 111 may have a weighted average bed temperature of 300°C to 450°C, such as 370°C to 415°C, and may have a pressure of 30 bar to 200 bar, such as 90 bar to 110 bar. The HDM reaction zone 111 includes an HDM catalyst, and the HDM catalyst may fill the entire HDM reaction zone 111.

[0086] The HDM catalyst may comprise one or more metals from Groups 5, 6, or 8-10 of the IUPAC Periodic Table. For example, the HDM catalyst may comprise molybdenum. The HDM catalyst may further comprise a support material, and the metal may be disposed on the support material. The support material may be γ-alumina or a silica / alumina extrudate, sphere, cylinder, bead, pellet, and combinations thereof. In some embodiments, the HDM catalyst may comprise a γ-alumina support having a surface area of 100 square meters per gram (m 2 / g) to 160 m 2 / g, such as 100 m 2 / g to 130 m 2 / g or 130 m 2 / g to 160 m 2 / g. In one embodiment, the HDM catalyst may comprise a molybdenum metal catalyst on an alumina support (sometimes referred to as a “Mo / Al2O3 catalyst”). It should be understood that throughout this disclosure, the metals contained in any disclosed catalyst may be present as sulfides or oxides or even other compounds.

[0087] In some embodiments, the HDM catalyst may comprise 0.5 wt% to 12 wt% of an oxide or sulfide of molybdenum, such as 2 wt% to 10 wt% or 3 wt% to 7 wt% of an oxide or sulfide of molybdenum; and 88 wt% to 99.5 wt% of alumina, such as 90 wt% to 98 wt% or 93 wt% to 97 wt% of alumina.

[0088] The HDM catalyst may be best described as having a relatively large pore volume, such as at least 0.8 cubic centimeters per gram (cm 3 / g) (e.g., at least 0.9 cm 3 / g or even at least 1.0 cm 3 / g). The pore size of the HDM catalyst may be predominantly macroporous (i.e., having a pore size greater than 50 nanometers (nm)). This may provide a large capacity for the absorption of metals and optionally dopants on the surface of the HDM catalyst. In one embodiment, the HDM catalyst may include a dopant comprising one or more compounds that include elements selected from the group consisting of boron, silicon, halogen, phosphorus, and combinations thereof.

[0089] The HDM reaction effluent can be delivered from the HDM reaction zone 111 to the HDS reaction zone 112, where it contacts the HDS catalyst. Contacting the HDM reaction effluent with the HDS catalyst can facilitate a reaction to remove at least a portion of the sulfur present in the HDM reaction effluent stream. After contacting the HDS catalyst, the HDM reaction effluent can be converted to an HDS reaction effluent. The HDS reaction effluent can have a reduced sulfur content when compared to the HDM reaction effluent. For example, the HDS reaction effluent can have at least 2%, at least 5%, at least 10%, at least 25%, at least 50%, or even at least 75% less sulfur than the HDM reaction effluent. According to some embodiments, the HDS reaction zone 112 can have a weighted average bed temperature of 300 °C to 450 °C, such as 370 °C to 415 °C, and can have a pressure of 30 bar to 200 bar, such as 90 bar to 110 bar. The HDS reaction zone 112 includes the HDS catalyst, and the HDS catalyst can fill the entire HDS reaction zone 112.

[0090] In one embodiment, the HDS catalyst comprises a metal from Group 6 of the IUPAC Periodic Table and a metal from Group 8 - 10 of the IUPAC Periodic Table. Exemplary Group 6 metals include molybdenum and tungsten, and exemplary Group 8 - 10 metals include nickel and cobalt. The HDS catalyst can further comprise a support material, and the metals can be disposed on the support material. In some embodiments, the HDS catalyst can comprise Mo and Ni on an alumina support (sometimes referred to as a "Mo - Ni / Al2O3 catalyst"). The HDS catalyst can also comprise a dopant selected from the group consisting of boron, phosphorus, halogens, silicon, and combinations thereof. In one or more embodiments, the HDS catalyst can comprise: 10 wt% to 18 wt% of an oxide or sulfide of molybdenum, such as 11 wt% to 17 wt% or 12 wt% to 16 wt% of an oxide or sulfide of molybdenum; 1 wt% to 7 wt% of an oxide or nickel sulfide of nickel, such as 2 wt% to 6 wt% or 3 wt% to 5 wt% of an oxide or nickel sulfide of nickel; and 75 wt% to 89 wt% of alumina, such as 77 wt% to 87 wt% or 79 wt% to 85 wt% of alumina.

[0091] The HDS catalyst can have a surface area of 140 m 2 / g to 200 m 2 / g, such as 140 m 2 / g to 170 m 2 / g or 170 m 2 / g to 200 m 2 / g. The HDS catalyst can have an intermediate pore volume of 0.5 cm 3 / g to 0.7 cm 3 / g, such as 0.6 cm 3 / g. The HDS catalyst typically may comprise a mesoporous structure having pore diameters in the range of 12 nm to 50 nm.

[0092] The HDS reaction effluent may be delivered from the HDS reaction zone 112 to the HDA reaction zone 114 where it contacts the HDA catalyst. Contacting the HDS reaction effluent with the HDA catalyst may facilitate reactions that can reduce the concentration of aromatic hydrocarbons present in the HDS reaction effluent. After contacting the HDA catalyst, the HDN reaction effluent may be converted to the HDA reaction effluent. The HDA reaction effluent may be delivered out of the hydrotreating unit 110 as the hydrotreated effluent 103. Compared to the HDS reaction effluent, the hydrotreated effluent 103 (HDA reaction effluent) may have a reduced aromatic compound content. For example, compared to the HDN reaction effluent, the hydrotreated effluent 103 (HDA reaction effluent) may have at least 2%, at least 5%, at least 10%, at least 25%, at least 50%, or even at least 75% fewer aromatic compounds.

[0093] The HDA catalyst may comprise one or more metals from Groups 5, 6, 8, 9, or 10 of the IUPAC Periodic Table. In some embodiments, the HDA catalyst may comprise one or more metals from Group 5 or Group 6 of the IUPAC Periodic Table and one or more metals from Groups 8, 9, or 10 of the IUPAC Periodic Table. In some embodiments, the HDA catalyst may comprise molybdenum or tungsten from Group 6 and nickel or cobalt from Groups 8, 9, or 10. The HDA catalyst may further comprise a support material (such as zeolite), and the metals may be disposed on the support material. In one embodiment, the HDA catalyst may comprise a tungsten and nickel metal catalyst on a mesoporous zeolite support (sometimes referred to as a “W-Ni / mesoporous zeolite catalyst”). In another embodiment, the HDA catalyst may comprise 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, zeolites such as Y, β, AWLZ-15, LZ-45, Y-82, Y-84, LZ-210, LZ-25, silicalite, or mordenite framework zeolites are contemplated to be suitable for use in the HDA catalysts described in the present disclosure.

[0094] The support material of the HDA catalyst (i.e., mesoporous zeolite) can be characterized as mesoporous by having an average pore diameter of 2 nm to 50 nm. In comparison, conventional zeolite-based hydrocracking catalysts contain microporous zeolites, which means they have an average pore diameter of less than 2 nm. Without being bound by theory, it is believed that the relatively large-sized pores (i.e., mesoporosity) of the HDA catalyst described in the present disclosure allow larger molecules to diffuse inside the zeolite, which is considered to improve the reaction activity and selectivity of the catalyst. Due to the increased pore diameter, aromatic-containing molecules can diffuse more easily into the catalyst, and aromatic cracking can be increased. For example, in some conventional embodiments, the feedstock converted by the hydrotreating catalyst can be: vacuum gas oil; light cycle oil from, for example, a fluid catalytic cracking reactor; or coker gas oil from, for example, a coking unit. Compared with the molecular sizes of the heavy oils (such as crude oil and atmospheric residue) that can be the feedstock of the present method and system, the molecular sizes in these oils are relatively small. Crude oil generally cannot diffuse inside conventional zeolites and cannot be converted at the active sites located inside the zeolites. Therefore, zeolites with larger pore diameters (i.e., mesoporous zeolites) can allow larger molecules of heavy oils to overcome diffusion limitations and can promote the reaction and conversion of larger molecules of crude oil.

[0095] In one or more embodiments, the HDA catalyst can comprise: 18 wt% to 28 wt% of sulfide or oxide of tungsten, such as 20 wt% to 27 wt% or 22 wt% to 26 wt% of tungsten or sulfide or oxide of tungsten; 2 wt% to 8 wt% of oxide or sulfide of nickel, such as 3 wt% to 7 wt% or 4 wt% to 6 wt% of oxide or sulfide of nickel; and 5 wt% to 40 wt% of mesoporous zeolite, such as 10 wt% to 35 wt% or 10 wt% to 30 wt% of zeolite. In another embodiment, the HDA catalyst can comprise: 12 wt% to 18 wt% of oxide or sulfide of molybdenum, such as 13 wt% to 17 wt% or 14 wt% to 16 wt% of oxide or sulfide of molybdenum; 2 wt% to 8 wt% of oxide or sulfide of nickel, such as 3 wt% to 7 wt% or 4 wt% to 6 wt% of oxide or sulfide of nickel; and 5 wt% to 40 wt% of mesoporous zeolite, such as 10 wt% to 35 wt% or 10 wt% to 30 wt% of mesoporous zeolite.

[0096] It should be understood that some embodiments of the methods and systems described in the present disclosure can utilize an HDA catalyst comprising mesoporous zeolite (i.e., having an average pore diameter of 2 nm to 50 nm). However, in other embodiments, the average pore diameter of the zeolite can be less than 2 nm (i.e., microporous).

[0097] According to one or more of the described embodiments, the volume ratio of the HDM catalyst, the HDS catalyst, and the HDA catalyst in the hydrotreating unit 110 can be 5-20:5-30:5-30. The ratio of the catalysts can depend at least in part on the metal content in the oil feedstock being processed.

[0098] Reference is now made to Figure 3 , which shows a crude oil upgrading system 300, in which the hydrotreating unit 110 can include or consist of: a plurality of packed bed reaction zones (e.g., the HDM reaction zone 111 and the HDS reaction zone 112) arranged in series, and each of these reaction zones can contain a catalyst bed. Each of these zones can be included in a single reactor as a packed bed reactor having a plurality of beds in series, as shown by the upstream packed bed hydrotreating reactor 116 and the downstream packed bed hydrocracking reactor 117 in Figure 3 . The upstream packed bed hydrotreating reactor 116 or the plurality of upstream packed bed reactors can include the HDM reaction zone 111 and the HDS reaction zone 112. The downstream packed bed hydrocracking reactor 117 can include the HDA reaction zone 114. In such an embodiment, the HDM reaction zone 111, the HDS reaction zone 112, and the HDA reaction zone 114 can utilize the respective catalysts and processing conditions disclosed for the system of Figure 2 . Figure 3 The configuration of the upstream packed bed hydrotreating reactor 116 or the plurality of upstream packed bed reactors of

[0099] Reference is now made to Figure 4, shows a crude oil upgrading system 400, wherein the hydrotreating unit 110 may comprise or consist of: a plurality of packed bed reaction zones contained in a plurality of reactors arranged in series with a downstream packed bed hydrocracking reactor 117. In some embodiments, the HDM reaction zone 111 may be contained in the HDM reactor 151, the HDS reaction zone 112 may be contained in the HDS reactor 152, and the HDA reaction zone 114 may be contained in the downstream packed bed hydrocracking reactor 117. The crude oil 101 is introduced into the HDM reaction zone 111 in the HDM reactor 151 and may be converted into the HDM reaction effluent 107. The HDM reaction effluent 107 may be delivered to the HDS reaction zone 112 in the HDS reactor 152 and may be converted into the HDS reaction effluent 106. The HDS reaction effluent 106 may be delivered to the HDA reaction zone 114 in the downstream packed bed hydrocracking reactor 117 and may be converted into the hydrotreated effluent 103. In such an embodiment, the HDM reaction zone 111, the HDS reaction zone 112 and the HDA reaction zone 114 may utilize the respective catalysts and processing conditions discussed previously with respect to Figure 2 the system.

[0100] Referring now to Figure 5 , shows a crude oil upgrading system 500, which may include a separation unit 130 downstream of the HS-FCC unit 120. The cracked effluent 104 may be delivered from the separation zone 123 of the HS-FCC unit 120 to the separation unit 130, which may be operated to separate the cracked effluent 104 into a plurality of streams, which may include at least one product stream and a bottoms stream 139. In some embodiments, the separation unit 130 may be a distillation column or a fractionation column, which may be operated to separate the contents of the cracked effluent 104 into one or more product streams, such as a hydrocarbon oil stream 131, a gasoline stream 132, a mixed butene stream 133, a butadiene stream 134, a propylene stream 135, an ethylene stream 136, a methane stream 137, a hydrogen stream 138, or a combination thereof. As used in the present disclosure, product streams (such as the hydrocarbon oil stream 131, the gasoline stream 132, the mixed butene stream 133, the butadiene stream 134, the propylene stream 135, the ethylene stream 136, and the methane stream 137) may be referred to as petrochemical products, which may be used as intermediates in downstream chemical processing.

[0101] The hydrogen stream 138 may be processed by the hydrogen purification unit 140 and recycled back into the crude oil upgrading system 500 as the purified hydrogen stream 141. The purified hydrogen stream 141 may be supplemented with additional feed hydrogen from the feed hydrogen stream 142. Optionally, all or at least a portion of the hydrogen stream 138 or the purified hydrogen stream 141 may leave the system as a system product or be burned to generate heat.

[0102] Although this specification and the examples are provided in the context of Arabian heavy crude oil as the material for the crude oil 101, it should be understood that the crude oil upgrading systems 100, 200, 300, 400, 500 described with respect to the embodiments of Figures 1 - 5 can be applicable to the conversion of a wide variety of heavy oils (in the crude oil 101), including but not limited to crude oil, vacuum residue, tar sands, bitumen, atmospheric residue, and vacuum gas oil.

[0103] Examples

[0104] Various aspects of the present disclosure 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.

[0105] Example 1: Hydrotreating Crude Oil

[0106] In Example 1, in-house hydrotreating was carried out by feeding the crude oil into a three-layer hydrotreating unit containing an HDM catalyst (KFR-22 commercially available from Albemarle), an HDS catalyst (KFR-33 commercially available from Albemarle), and an HDA 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 column having an HDM catalyst bed layer at the top, an HDS catalyst bed layer in the middle, and an HDA catalyst bed layer at the bottom. The HDM catalyst bed layer had a volume of 70 mL and a bulk density of 0.5 g / mL. The HDS catalyst bed layer had a volume of 70 mL and a bulk density of 0.6 g / mL. The HDA catalyst bed layer had a volume of 560 mL and a bulk density of 0.7 g / mL. For Example 1, the crude oil was Arabian medium crude oil, and its properties are provided in Table 3 below. The hydrotreating unit was operated at a temperature of 400 °C, a pressure of 150 bar, and an LHSV of 0.3 h -1 . The hydrotreated AM crude oil was analyzed according to the method shown in Table 3 and compared with its properties before hydrotreating.

[0107] Table 3

[0108]

[0109] The boiling points of Arabian medium crude oil before and after hydrotreating were analyzed at different compositions. These results are provided in Table 4 below.

[0110] Table 4

[0111]

[0112]

[0113] Example 2: Synthesis of Nano-ZSM-5 Zeolite

[0114] The nano-ZSM-5 zeolite and HS-FCC catalyst composition according to the present disclosure were prepared. The materials used for preparing the nano-ZSM-5 zeolite of Example 2 and the HS-FCC catalyst composition of Example 3 are provided in Table 5 below.

[0115] Table 5

[0116]

[0117] To prepare the nano-ZSM-5 zeolite of Example 2, 40 grams (g) of precursor solutions were prepared by mixing water, colloidal silica, sodium hydroxide, tetrapropylammonium hydroxide (TPAOH), and aluminum isopropoxide (Al(O-i-Pr)3) according to the molar ratios (mole / mole) in Table 6 below. The precursor solutions were stirred at room temperature for one day, transferred to a Teflon-lined stainless steel autoclave, heated to 140 °C, and then held at 140 °C for 4 days to obtain a product solution. The product solution was centrifuged and the solid product was collected. The solid product was dispersed in deionized water and centrifuged to obtain a washed product. The washed product was dried in an oven at 80 °C. The washed product was calcined using the following procedure: heated at a rate of 3 °C / min until a temperature of 200 °C was reached, held at this temperature for two hours, heated at a rate of 3 °C / min until a temperature of 550 °C was reached, and held at this temperature for 8 hours to produce the nano-ZSM-5 zeolite of Example 2. The nano-ZSM-5 zeolite has an average particle size of 0.084 μm as determined by electron microscopy. The nano-ZSM-5 zeolite has an average silica to alumina ratio of 33, an average surface area of 379 m 2 / g, and an average total pore volume per unit weight of 0.254 cm 3 / g.

[0118] Table 6

[0119]

[0120] Example 3: Preparation of HS-FCC Catalyst Composition

[0121] To prepare the HS-FCC catalyst composition of Example 3, the nano-ZSM-5 zeolite was synthesized and impregnated with 7.5 wt% of phosphorus pentoxide, and USY zeolite (CBV-780 commercially available from Zeolyst International) was impregnated with 2.5 wt% of lanthanum oxide. The USY zeolite has 0.486 cm 3Average total pore volume per unit weight in g. The nano-ZSM-5 zeolite impregnated with phosphorus pentoxide and the USY zeolite impregnated with lanthanum oxide were combined with water, alumina binder, colloidal silica, and kaolin to produce a mixture. The mixture was stirred for 1 hour, and the resulting slurry was placed in a programmed oven for drying and calcination to produce HS-FCC catalyst composition particles. The HS-FCC catalyst composition particles were ground into a fine powder using a mortar and pestle. Then, the ground HS-FCC catalyst composition microparticles were sieved to obtain a fraction between 40 and 120 micrometers (μm) and used for characterization and evaluation. The composition of the HS-FCC catalyst composition microparticles of Example 3 is provided in Table 7 below.

[0122] Table 7

[0123] Component Weight % Note Nano ZSM - 5 20 <![CDATA[Phosphorus is impregnated on zeolite at 7.5 wt% P2O5]]> USY 21 <![CDATA[Lanthanum is impregnated on zeolite with 2.5 wt% La2O3]]> Aluminum oxide 8 Pural SB from Sasol Clay 49 Kaolin Silica 2 <![CDATA[Ludox added as colloidal silica TM -40]]>

[0124] Example 4: Evaluation of the HS-FCC Catalyst Composition of Example 3

[0125] In Example 4, the performance of the HS-FCC catalyst composition of Example 3 in cracking hydrotreated Arab medium crude oil at a temperature of 650 °C and a catalyst-to-oil weight ratio (CTO) of approximately 4.8 was evaluated. A quartz tube reactor and a Sakuragi Rikagaku (Japan) microactivity test (MAT) instrument were used to catalytically crack the hydrotreated Arab medium crude oil with the HS-FCC catalyst composition of Example 2. The HS-FCC catalyst composition of Example 3 for cracking hydrotreated Arab medium crude oil was evaluated according to the test method ASTM D-3907 method. Before the evaluation, the HS-FCC catalyst composition was steamed at 810 °C for 6 hours and then subjected to the cracking reaction. The experiment was carried out in a MAT unit with a run time (TOS) of 30 seconds.

[0126] After each reaction, the HS-FCC catalyst composition microparticles were stripped with nitrogen (N2) at a flow rate of 30 milliliters per minute (mL / min). The liquid products were collected in a liquid receiver, and the gas products were collected in a gas burette by the water displacement method and sent to a gas chromatograph (GC) for analysis. The amount of coke produced from the reaction was measured using the spent catalyst.

[0127] The MAT results of the cracking of hydrotreated Arab medium crude oil over the HS-FCC catalyst composition of Example 3 are shown in Table 8. It can be seen that at a reaction temperature of 650 °C and a catalyst-to-oil ratio of 4.82, a light olefin yield of 43.90 wt% was obtained using the HS-FCC catalyst composition of Example 3. Additionally, the propylene yield was 22.01 wt%, and the ethylene yield was 7.88 wt%.

[0128] Table 8

[0129]

[0130]

[0131] Comparative Example 5: Evaluation of the hydrotreated crude oil of Example 1

[0132] In Comparative Example 5, the performance of the hydrotreating step in cracking Arab medium crude oil at a reaction temperature of 650 °C and a catalyst-to-oil ratio of 5 was evaluated. As described in Example 4, the Arab medium crude oil was catalytically cracked with the commercial HS-FCC catalyst composition of Comparative Example 5. The MAT results of the cracking of Arab medium crude oil on the commercial HS-FCC catalyst composition of Comparative Example 5 are shown in Table 9.

[0133] Table 9

[0134]

[0135]

[0136] As can be seen in Table 9, the light olefin yield of the non-hydrotreated Arab medium crude oil of Comparative Example 5 was 35.61 wt%. Additionally, the propylene yield was 17.71 wt%, and the ethylene yield was 8.08 wt%. Comparatively, under similar conditions, the hydrotreated Arab medium crude oil of Example 4 produced a light olefin yield of 43.90 wt%, a propylene yield of 22.01 wt%, and an ethylene yield of 7.88 wt%.

[0137] Comparative Examples 6 and 7: Evaluation of the HS-FCC catalyst composition of Example 3

[0138] In Comparative Examples 6 and 7, the performance of the HS-FCC catalyst of Example 3 in cracking hydrotreated Arab medium crude oil at a reaction temperature of 650 °C and a catalyst-to-oil ratio of about 5 was evaluated. As described in Example 4, the hydrotreated Arab medium crude oil was catalytically cracked with the commercial HS-FCC catalyst compositions of Comparative Examples 6 and 7. OlefinsUltra is a commercial catalyst based on ZSM-5 zeolite, while HSFCC 5A is a commercial catalyst based on Y zeolite. The MAT results of the cracking of Arab medium crude oil on the commercial HS-FCC catalyst composition of Comparative Example 5 are shown in Table 10.

[0139] Table 10

[0140]

[0141]

[0142] As can be seen in Table 10, when hydrotreating Arab medium crude oil in Comparative Examples 6 and 7 of cracking, the light olefin yields using other commercially available catalysts are 26.62 wt% and 30.36 wt%, respectively. Additionally, the propylene yields of Comparative Examples 6 and 7 are 11.42 wt% and 12.87 wt%, and the ethylene yields are 10.57 wt% and 5.04 wt%. In comparison, the hydrotreating Arab medium crude oil of Example 4 using the HS-FCC catalyst composition of Example 3 produces a light olefin yield of 43.90 wt%, a propylene yield of 22.01 wt%, and an ethylene yield of 7.88 wt% under similar conditions.

[0143] Aspect

[0144] A first aspect of the present disclosure relates to a method for upgrading crude oil, which comprises: contacting the crude oil with one or more hydrotreating catalysts to produce a hydrotreated effluent, wherein the crude oil has an API gravity of 30 to 35; and contacting the hydrotreated effluent with a high-severity fluid catalytic cracking (HS-FCC) catalyst composition in a high-severity FCC (HS-FCC) unit to produce a cracked effluent comprising olefins, aromatic compounds, or both, wherein the HS-FCC unit is operated at a temperature of greater than or equal to 580 °C, a weight ratio of the HS-FCC catalyst composition to the crude oil of 2:1 to 10:1, and a residence time of 0.1 second to 60 seconds, wherein the HS-FCC catalyst composition comprises: ultrastable Y zeolite (USY zeolite) impregnated with lanthanum; nano-ZSM-5 zeolite impregnated with phosphorus, wherein the nano-ZSM-5 zeolite has an average particle size of 0.01 μm to 0.2 μm; an alumina binder; colloidal silica; and a matrix material comprising kaolin.

[0145] In a second aspect of the present disclosure, in combination with the first aspect, wherein the crude oil is Arab medium crude oil.

[0146] In a third aspect of the present disclosure, in combination with any aspect of the first or second aspect, wherein the hydrotreating catalyst comprises at least one hydrodemetallization (HDM) catalyst, at least one hydrodesulfurization (HDS) catalyst, and at least one hydrodearomatization (HDA) catalyst.

[0147] In a fourth aspect of the present disclosure, in combination with any aspect of the first to third aspects, wherein: the HDM catalyst and the HDS catalyst are placed in series in a plurality of reactors, and the HDA catalyst is placed in a reactor downstream of the plurality of reactors; or each of the plurality of packed bed reaction zones is contained in a single reactor comprising the plurality of packed bed reaction zones.

[0148] In a fifth aspect of the present disclosure, in combination with any of the first to fourth aspects, wherein the HDM catalyst, the HDS catalyst, and the HDA catalyst are placed in series in a plurality of packed bed reaction zones.

[0149] In a sixth aspect of the present disclosure, in combination with any of the first to fifth aspects, wherein the crude oil has a density greater than 0.8 grams per milliliter at 15 degrees Celsius.

[0150] In a seventh aspect of the present disclosure, in combination with any of the first to sixth aspects, wherein the crude oil has an initial boiling point of 75 degrees Celsius to 125 degrees Celsius and a final boiling point greater than 720 degrees Celsius.

[0151] In an eighth aspect of the present disclosure, in combination with any of the first to seventh aspects, wherein at least 50% by weight of the crude oil has a boiling point temperature greater than or equal to 400 degrees Celsius.

[0152] In a ninth aspect of the present disclosure, in combination with any of the first to eighth aspects, wherein the crude oil is contacted with one or more hydrotreating catalysts at a temperature of 375 degrees Celsius to 425 degrees Celsius.

[0153] In a tenth aspect of the present disclosure, in combination with any of the first to ninth aspects, wherein the crude oil is contacted with one or more hydrotreating catalysts at a pressure of 140 bar to 160 bar.

[0154] In an eleventh aspect of the present disclosure, in combination with any of the first to tenth aspects, wherein the hydrotreated effluent has a sulfur content of less than 0.1% by weight and a nitrogen content of less than 175 parts per million by weight (ppmw).

[0155] In a twelfth aspect of the present disclosure, in combination with any of the first to eleventh aspects, wherein the hydrotreated effluent has a density of 0.75 grams per cubic centimeter at 15 degrees Celsius to 0.90 grams per cubic centimeter at 15 degrees Celsius.

[0156] In a thirteenth aspect of the present disclosure, in combination with any of the first to twelfth aspects, wherein the HS-FCC catalyst composition comprises 10% to 30% by weight of lanthanum-impregnated USY zeolite.

[0157] In a fourteenth aspect of the present disclosure, in combination with any of the first to thirteenth aspects, wherein the HS-FCC catalyst composition comprises 10% to 30% by weight of phosphorus-impregnated nano-ZSM-5 zeolite.

[0158] In a fifteenth aspect of the present disclosure, in combination with any of the first to fourteenth aspects, wherein the USY zeolite is impregnated with 1 wt% to 5 wt% of lanthanum oxide based on the total weight of the USY zeolite.

[0159] In a sixteenth aspect of the present disclosure, in combination with any of the first to fifteenth aspects, wherein the nano-ZSM-5 zeolite is impregnated with 1 wt% to 15 wt% of phosphorus pentoxide based on the total weight of the nano-ZSM-5 zeolite.

[0160] In a seventeenth aspect of the present disclosure, in combination with any of the first to sixteenth aspects, wherein the HS-FCC catalyst composition comprises 20 wt% to 22 wt% of lanthanum-impregnated USY zeolite, 19 wt% to 21 wt% of phosphorus-impregnated nano-ZSM-5 zeolite, 7 wt% to 9 wt% of alumina binder, 48 wt% to 50 wt% of kaolin, and 1 wt% to 3 wt% of colloidal silica, wherein the wt% is based on the total weight of the HS-FCC catalyst composition.

[0161] In an eighteenth aspect of the present disclosure, in combination with any of the first to seventeenth aspects, wherein the cracking of the hydrotreated effluent comprises contacting the hydrotreated effluent with the HS-FCC catalyst in an HS-FCC unit at a weight ratio of HS-FCC catalyst to hydrotreated effluent of 2:1 to 10:1.

[0162] In a nineteenth aspect of the present disclosure, in combination with any of the first to eighteenth aspects, wherein the HS-FCC unit is a downflow HS-FCC unit.

[0163] In a twentieth aspect of the present disclosure, in combination with any of the first to nineteenth aspects, wherein the cracked effluent leaving the HS-FCC has a light olefin content of at least 40 mass%, an ethylene content of at least 5 mass%, a propylene content of at least 20 mass%, or a combination thereof.

[0164] It should be noted that any two quantitative values assigned to a property can form a range of that property, and all combinations of ranges formed by all the stated quantitative values of a given property are contemplated in the present disclosure.

[0165] It should be noted that one or more of the appended claims use the term "wherein" as a transitional phrase. For the purposes of defining the present technology, it should be noted that this term is introduced in the claims as an open transitional phrase for introducing a listing of a series of features of a structure and should be understood in a manner similar to the more common open preamble term "comprising".

[0166] The subject matter of the present disclosure has been described in detail by reference to specific aspects. It should be noted that the various details of these aspects should not be regarded as implying that these details are essential components of these aspects. Instead, the appended claims should be regarded as the sole representation of the scope of the present disclosure and the corresponding scope of the various aspects described in the present disclosure. In addition, it is obvious that modifications and variations can be made without departing from the scope of the appended claims.

Claims

1. A method for upgrading crude oil, comprising: Contacting the crude oil with one or more hydrotreating catalysts to produce a hydrotreated effluent, wherein, The crude oil has an API gravity of 30 to 35; and Contacting the hydrotreated effluent with a high-severity fluid catalytic cracking (HS-FCC) catalyst composition in a high-severity FCC (HS-FCC) unit to produce a cracked effluent comprising olefins, aromatic compounds, or both, wherein the HS-FCC unit is operated at a temperature of greater than or equal to 580 °C, a weight ratio of the HS-FCC catalyst composition to the crude oil of 2:1 to 6:1, and a residence time of 0.1 second to 60 seconds, wherein: The HS-FCC catalyst composition comprises: Ultra-stable Y zeolite (USY zeolite) impregnated with lanthanum; Nano-ZSM-5 zeolite impregnated with phosphorus, wherein the nano-ZSM-5 zeolite has an average particle size of 0.01 μm to 0.2 μm; Alumina binder; Colloidal silica; and A matrix material comprising kaolin.

2. The method according to claim 1, wherein, The crude oil is Arabian Medium crude oil.

3. The method according to claim 1, wherein, The hydrotreating catalyst comprises at least one hydrodemetallization (HDM) catalyst, at least one hydrodesulfurization (HDS) catalyst, and at least one hydrodearomatization (HDA) catalyst.

4. The method according to claim 3, wherein: The HDM catalyst and the HDS catalyst are placed in series in a plurality of reactors, and the HDA catalyst is placed in a reactor downstream of the plurality of reactors; Or Each of a plurality of packed bed reaction zones is contained in a single reactor containing the plurality of packed bed reaction zones.

5. The method according to claim 3, wherein The HDM catalyst, the HDS catalyst, and the HDA catalyst are placed in series in a plurality of packed bed reaction zones.

6. The method according to any one of claims 1 to 5, wherein The crude oil has: A density greater than 0.8 g / ml at 15 degrees Celsius; And An initial boiling point of 75 degrees Celsius to 125 degrees Celsius and a final boiling point greater than 720 degrees Celsius.

7. The method according to any one of claims 1 to 6, wherein, At least 50 wt% of the crude oil has a boiling point temperature of greater than or equal to 400 degrees Celsius.

8. The method according to any one of claims 1 to 7, wherein The crude oil is contacted with the one or more hydrotreating catalysts at a temperature of 375 degrees Celsius to 425 degrees Celsius and a pressure of 140 bar to 160 bar.

9. The method according to any one of claims 1 to 8, wherein, The hydrotreated effluent comprises: A sulfur content of less than 0.1 wt%; A nitrogen content of less than 175 parts per million by weight (ppmw); and A density from 0.75 g / cm3 at 15 degrees Celsius to 0.90 g / cm3 at 15 degrees Celsius.

10. The method according to any one of claims 1 to 9, wherein, The HS-FCC catalyst composition comprises 10 wt% to 30 wt% of USY zeolite impregnated with lanthanum.

11. The method according to any one of claims 1 to 10, wherein The HS-FCC catalyst composition comprises 10 wt% to 30 wt% of nano-ZSM-5 zeolite impregnated with phosphorus.

12. The method according to any one of claims 1 to 11, wherein, The USY zeolite is impregnated with 1 wt% to 5 wt% of lanthanum oxide based on the total weight of the USY zeolite.

13. The method according to any one of claims 1 to 12, wherein, The nano-ZSM-5 zeolite is impregnated with 1 wt% to 15 wt% of phosphorus pentoxide based on the total weight of the nano-ZSM-5 zeolite.

14. The method according to any one of claims 1 to 13, wherein, The HS-FCC catalyst composition comprises 20 wt% to 22 wt% of lanthanum-impregnated USY zeolite, 19 wt% to 21 wt% of phosphorus-impregnated nano-ZSM-5 zeolite, 7 wt% to 9 wt% of alumina binder, 48 wt% to 50 wt% of kaolin, and 1 wt% to 3 wt% of colloidal silica, wherein the wt% is based on the total weight of the HS-FCC catalyst composition.

15. The method according to any one of claims 1 to 15, wherein: The HS-FCC unit is a downflow HS-FCC unit; and The cracked effluent exiting the HS-FCC unit has a light olefin content of at least 40 mass%, an ethylene content of at least 5 mass%, a propylene content of at least 20 mass%, or a combination thereof.

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